ML043060486
| ML043060486 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 10/28/2004 |
| From: | Troy Pruett NRC/RGN-IV/DRP/RPB-D |
| To: | Forbes J Entergy Operations |
| References | |
| IR-04-004 | |
| Download: ML043060486 (53) | |
See also: IR 05000313/2004004
Text
October 28, 2004
Jeffrey S. Forbes, Vice President,
Operations
Arkansas Nuclear One
Entergy Operations, Inc.
1448 S.R. 333
Russellville, Arkansas 72801-0967
SUBJECT: ARKANSAS NUCLEAR ONE - NRC INTEGRATED INSPECTION REPORT
05000313/2004004 AND 05000368/2004004
Dear Mr. Forbes:
On September 23, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Arkansas Nuclear One, Units 1 and 2, facility. The enclosed integrated
report documents the inspection findings, which were discussed on September 28, 2004, with
you and other members of your staff.
The inspection examined activities conducted under your licenses as they relate to safety and
compliance with the Commission's rules and regulations and with the conditions of your
licenses. The inspectors reviewed selected procedures and records, observed activities, and
interviewed personnel.
This report documents one unresolved item concerning the potential unavailability of an
emergency diesel generator in Unit 1 due to a lube oil leak. This finding has potential safety
significance greater than very low safety significance. This finding did represent an immediate
safety concern until July 3, 2004, when your staff repaired a fitting associated with a
temperature switch. Also, this report documents one apparent violation regarding the potential
unavailability of a containment spray pump in Unit 2 due to a loose connection in the breaker
circuitry. This finding has potential safety significance greater than very low safety significance.
This finding did represent an immediate safety concern until August 9, 2004, when your staff
repaired the connection in the breaker circuitry.
In addition, the report documents three NRC-identified and two self-revealing findings of very
low safety significance (Green). Four of these findings were determined to involve violations of
NRC requirements. However, because of the very low safety significance and because they
are entered into your corrective action program, the NRC is treating these five findings as
noncited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy.
Additionally, one licensee-identified violation, which was determined to be of very low safety
significance, is listed in Section 4OA7 of this report. If you contest these noncited violations,
you should provide a response within 30 days of the date of this inspection report, with the
basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control
Entergy Operations, Inc.
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Desk, Washington DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear
Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas
76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,
Washington DC 20555-0001; and the NRC Resident Inspector at Arkansas Nuclear One,
Units 1 and 2, facility.
In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letter, its
enclosure, and your response (if any) will be made available electronically for public inspection
in the NRC Public Document Room or from the Publicly Available Records (PARS) component
of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Troy W. Pruett, Chief
Project Branch D
Division of Reactor Projects
Dockets: 50-313
50-368
Licenses: DPR-51
Enclosure:
NRC Inspection Report 05000313/2004004 and 05000368/2004004
w/Attachment: Supplemental Information
cc w/enclosure:
Senior Vice President
& Chief Operating Officer
Entergy Operations, Inc.
P.O. Box 31995
Jackson, MS 39286-1995
Vice President
Operations Support
Entergy Operations, Inc.
P.O. Box 31995
Jackson, MS 39286-1995
Manager, Washington Nuclear Operations
ABB Combustion Engineering Nuclear
Power
12300 Twinbrook Parkway, Suite 330
Rockville, MD 20852
Entergy Operations, Inc.
- 3 -
County Judge of Pope County
Pope County Courthouse
100 West Main Street
Russellville, AR 72801
Winston & Strawn
1400 L Street, N.W.
Washington, DC 20005-3502
Bernard Bevill
Radiation Control Team Leader
Division of Radiation Control and
Emergency Management
4815 West Markham Street, Mail Slot 30
Little Rock, AR 72205-3867
James Mallay
Director, Regulatory Affairs
Framatome ANP
3815 Old Forest Road
Lynchburg, VA 24501
Entergy Operations, Inc.
- 4 -
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (RWD)
Branch Chief, DRP/D (TWP)
Senior Project Engineer, DRP/D (GEW)
Staff Chief, DRP/TSS (KMK)
RITS Coordinator (KEG)
Matt Mitchell, OEDO RIV Coordinator (MAM4)
ANO Site Secretary (VLH)
ADAMS: / Yes
G No Initials: TWP_____
/ Publicly Available G Non-Publicly Available
G Sensitive / Non-Sensitive
R:\\_ANO\\2004\\AN2004-04RP-RWD.wpd
RIV:RI:DRP/D
RI:DRP/D
SRI:DRP/D
C:DRS/PEB
C:DRS/PSB
JLDixon
ELCrowe
RWDeese
LJSmith
MPShannon
T - TWPruett
T - TWPruett
T - TWPruett
/RA/
/RA/
10/6/04
10/6/04
10/6/04
10/25/04
10/25/04
C:DRS/EMB
C:DRS/OB
C:DRP/D
JAClark
ATGody
TWPruett
/RA/
/RA/
/RA/
10/25/04
10/25/04
10/28/04
OFFICIAL RECORD COPY
T=Telephone E=E-mail F=Fax
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets:
50-313, 50-368
Licenses:
Report:
05000313/2004004 and 05000368/2004004
Licensee:
Entergy Operations, Inc.
Facility:
Arkansas Nuclear One, Units 1 and 2
Location:
Junction of Hwy. 64W and Hwy. 333 South
Russellville, Arkansas
Dates:
June 24, 2004 to September 23, 2004
Inspectors:
E. Crowe, Resident Inspector
R. Deese, Senior Resident Inspector
J. Dixon, Resident Inspector
J. Drake, Operations Engineer
P. Gage, Senior Operations Engineer
G. Replogle, Senior Reactor Inspector
Approved By:
Troy W. Pruett, Chief, Project Branch D
Division of Reactor Projects
Enclosure
CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R01
Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R04
Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R05
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
1R06
Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R11
Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
1R13
Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 10
1R14
Operator Performance During Nonroutine Plant Evolutions and Events . . . . . 13
1R15
Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
1R16
Operator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R19
Post-Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R22
Surveillance Testing
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1R23
Temporary Plant Modifications
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
ATTACHMENT: SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3
Enclosure
SUMMARY OF FINDINGS
IR 05000313/2004004, 05000368/2004004; 6/24/04 - 9/23/04; Arkansas Nuclear One, Units 1
and 2; Adverse Weather Protection, Fire Protection, Maintenance Risk Assessments and
Emergent Work Control, Operability Evaluations, Surveillance Testing, and Event Followup.
This report covered a 3-month period of inspection by resident inspectors, a maintenance rule
inspector, and two operations inspectors. Four Green noncited violations, one Green finding,
one apparent violation with potential safety significance greater than Green, and one
unresolved item with potential safety significance greater than Green were identified. The
significance of most findings is indicated by their color (Green, White, Yellow, or Red) using
Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the
significance determination process does not apply may be Green or be assigned a severity
level after NRC management's review. The NRCs program for overseeing the safe operation
of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight
Process, Revision 3, dated July 2000.
A.
NRC-Identified and Self-Revealing Findings
Cornerstone: Initiating Events
Green. A self-revealing finding associated with an inadequate maintenance
procedure occurred when the Unit 2 main generator reverse power relays
contributed to a turbine trip and a reactor trip. The licensee had not incorporated
vendor recommended maintenance on the reverse power relays, and as a result,
one of the reverse power relays actuated with no reverse power condition
present. Corrective actions taken or planned by the licensee have been entered
into the licensee's corrective action program as Condition Report ANO-2-2002-
2173.
The finding is more than minor because it was analogous to Example 4.b. in
Appendix E, Examples of Minor Issues, of Manual Chapter 0612, Power
Reactor Inspection Reports, because a procedural error contributed to a reactor
trip. This finding affected the initiating events cornerstone. Using the Phase 1
worksheet in Manual Chapter 0609, Significance Determination Process, the
finding is of very low safety significance because, although it resulted in a reactor
trip, all mitigating systems remained available (Section 4OA3).
Cornerstone: Mitigating Systems
TBD. An unresolved item was identified for the failure to take timely corrective
action to repair an oil leak on a temperature switch for the Unit 1 Emergency
Diesel Generator K-4A in May 2004. This failure resulted in the oil leak
progressively worsening and ultimately developing into a leak which challenged
the emergency diesel generator safety function. The fitting was repaired and the
leakage is no longer a safety concern. This finding involved problem
identification and resolution crosscutting aspects associated with operations and
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Enclosure
engineering personnel not recognizing the significance of the degraded condition
and not implementing timely corrective actions to repair the leak. Corrective
actions taken or planned by the licensee have been entered into the licensees
corrective action program as Condition Report ANO-1-2004-1705.
This finding is unresolved pending a review of the duration of the condition and
the completion of a significance determination. This finding affected the
mitigating systems cornerstone. The finding was more than minor because it
directly impacted the availability and reliability of an emergency diesel generator
which is used to mitigate the loss of AC power to the respective safety-related
bus. Using Appendix A, "Technical Basis For At Power Significance
Determination Process, of Manual Chapter 0609, Significance Determination
Process, and the Phase 2 worksheets from Risk-Informed Inspection Notebook
for Arkansas Nuclear One - Unit 1, the finding was determined to potentially
have greater than very low safety significance because the failure could have
resulted in an actual loss of the safety function of the Train A emergency diesel
generator during a loss of offsite power event (Section 1R15).
TBD. The inspectors identified an apparent violation of 10 CFR Part 50,
Appendix B, Criterion XV, "Nonconforming Materials, Parts, or Components," for
the failure to establish controls to prevent a circuit breaker with a loose
connection from being installed in Unit 2. A loose connection in the Containment
Spray Pump 2P-35A breaker was not identified prior to installation in the plant
even though there were several undocumented instances where similar loose
connections were discovered during receipt inspections of other breakers in its
group. This issue involved problem identification and resolution crosscutting
aspects associated with maintenance technicians not identifying the cause of the
breaker failure and not documenting nonconformances. Corrective actions taken
or planned by the licensee have been entered into the licensee's corrective
action program as Condition Report ANO-2-2004-1712.
This finding is being considered an apparent violation pending completion of its
significance determination. The finding is more than minor because it affected
the mitigating systems cornerstone objective of ensuring the reliability of systems
that respond to initiating events to prevent undesirable consequences. Using
Appendix A, Technical Basis For At Power Significance Determination Process,
of Manual Chapter 0609, Significance Determination Process, and the Phase 2
worksheets from Risk-informed Inspection Notebook for Arkansas Nuclear
One - Unit 2, the finding was determined to potentially have greater than very
low safety significance because the loose connection could have resulted in an
actual loss of the safety function of the Unit 2 Train A containment spray pump
during small break loss of coolant accident or stuck open relief valve events
(Section 1R22).
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Enclosure
Green. The inspectors identified a noncited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, for the failure of the licensee to
correctly translate the design basis heat removal requirements for the Unit 1
intake structure into specifications for the ventilation opening sizes.
Measurements of the openings by the inspectors were smaller than those
assumed in the licensees heat removal calculations. Analyses using the smaller
dimensions resulted in a 13 percent reduction in the heat removal capability.
The licensee has taken action to update their calculation with the correct opening
sizes. Corrective actions taken or planned by the licensee have been entered
into the licensees corrective action program as Condition Report ANO-1-2004-
1829.
This finding is more than minor because it was analogous to Example 3.i of
Appendix E, Examples of Minor Issues, to Inspection Manual Chapter 0612,
Power Reactor Inspection Reports, in that the licensee's engineering staff had
to reperform analyses due to a significant dimensional discrepancy. This finding
affected the mitigating systems cornerstone. Using the Phase 1 worksheets in
Manual Chapter 0609, Significance Determination Process, the inspectors
consider this finding to have very low safety significance because it did not result
in an actual loss of safety function (Section 1R01).
Green. The inspectors identified a noncited violation of Unit 2 operating license
Condition 2.C.(3)(b), Fire Protection, for the failure to perform hydrostatic
testing on approximately 80 to 90 percent of the carbon dioxide fire
extinguishers. The licensee failed to implement a plan to ensure carbon dioxide
fire extinguishers would not exceed their hydrostatic retest expiration dates in
response to NRC Information Notice 2001-004, Neglected Fire Extinguisher
Maintenance Causes Fatality. This issue involved problem identification and
resolution crosscutting aspects associated with fire protection technicians failing
to correct adverse conditions in a timely manner. Corrective actions taken or
planned by the licensee have been entered into the licensees corrective action
program as Condition Report ANO-1-2004-1544.
This finding is more than minor because, if left uncorrected, it would become a
more significant safety concern in that internal degradation of the fire
extinguishers could continue without any means of detection until the
extinguishers were unable to perform their intended functions. Using
Appendix F, Determining Potential Risk Significance of Fire Protection and
Post-Fire Safe Shutdown Inspection Findings, of Manual Chapter 0609,
Significance Determination Process, the inspectors determined the issue is of
very low safety significance because the fire protection elements performance
and reliability was minimally impacted (Section 1R05).
Green. The inspectors identified two examples of a noncited violation of
10 CFR 50.65(a)(4) for the failure to consider the external risk from changing
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Enclosure
weather conditions (tornado warning) while a Unit 2 emergency diesel generator
was out of service for maintenance and the failure to perform an adequate risk
assessment of the removal of a high energy line break barrier between the
turbine building and the Unit 1 South switchgear room. This finding involved
problem identification and resolution crosscutting aspects associated with
operations and engineering personnel not implementing corrective actions to
address the extent of condition from a previous noncited violation documented in
NRC Inspection Report 05000313/2004003. Corrective actions taken or planned
by the licensee have been entered into the licensees corrective action program
as Condition Reports ANO-C-2004-1279 and ANO-C-2004-1402.
The inspectors determined that these issues are more than minor because, if left
uncorrected, they would become a more significant safety concern in that actions
to manage increases in risk may not be implemented. This finding affected the
mitigating systems cornerstone. Using the Phase 1 worksheet in Manual
Chapter 0609, Significance Determination Process, the example involving
changing weather conditions was determined to have very low safety
significance because the finding did not result in a loss of function per Generic Letter 91-18, Revision 1, Information to Licensees Regarding NRC Inspection
Manual Section on Resolution of Degraded and Nonconforming Conditions.
Next, using Appendix A, Technical Basis For At Power Significance
Determination Process, of Manual Chapter 0609, Significance Determination
Process, and the Phase 2 worksheets from Risk-informed Inspection Notebook
for Arkansas Nuclear One - Unit 1, the finding involving the high energy line
break barrier was determined to be of very low safety significance because the
only affected initiator was a main steam line break and a redundant train of
safety related switchgear always remained available during the short exposure
time for the condition (Section 1R13).
Cornerstone: Barrier Integrity
Green. A self-revealing violation of Unit 1 Technical Specification 3.9.2, Nuclear
Instrumentation, occurred when one of the two required source range nuclear
neutron monitors failed during core alterations. The licensee continued
movement of spent fuel assemblies from the reactor vessel for approximately
11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> following the failure of the instrument. Corrective actions taken or
planned by the licensee have been entered into the licensees corrective action
program as Condition Report ANO-1-2004-0989.
The finding is more than minor because it affects the barrier integrity cornerstone
objective of providing reasonable assurance that physical design barriers protect
the public from radionuclide releases caused by accidents or events. Using
Appendix G, Shutdown Operations Significance Determination Process, of
Manual Chapter 0609, Significance Determination Process, the finding was
determined to have very low safety significance because the instrument failure
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Enclosure
did not affect the licensee's ability to maintain reactor coolant system inventory,
terminate a leak path, or recover decay heat removal (Section 4OA3).
B.
Licensee-Identified Violations
A violation of very low safety significance which was identified by the licensee has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensee's corrective action program. This violation and corrective
actions are listed in Section 4OA7 of this report.
Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at 100 percent rated thermal power and remained there
throughout the inspection period.
Unit 2 began the inspection period at 100 percent rated thermal power and remained there until
August 29, 2004, when operators reduced power to 10 percent rated thermal power and
removed the main generator from service to correct a lowering flow condition in the main
generator stator water cooling system. On August 31 the unit resumed 100 percent power
operation and remained there for the rest of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01
Adverse Weather Protection (71111.01)
Readiness for Seasonal Susceptibilities
a.
Inspection Scope
The inspectors completed a review of the licensee's readiness of seasonal
susceptibilities involving extreme high temperatures. The inspectors (1) reviewed plant
procedures, the Updated Final Safety Analysis Report, and Technical Specifications to
ensure that operator actions defined in adverse weather procedures maintained the
readiness of essential systems; (2) walked down portions of the below listed systems to
ensure that adverse weather protection features were sufficient to support operability
including the ability to perform safe shutdown functions; (3) evaluated operator staffing
levels to ensure the licensee would maintain the readiness of essential systems required
by plant procedures; and (4) reviewed the corrective action program to determine if the
licensee identified and corrected problems related to adverse weather conditions.
Week of July 19, 2004, Units 1 and 2, service water system
The inspectors completed one sample.
b.
Findings
Introduction. The inspectors identified a Green noncited violation (NCV) of
10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to correctly
translate the Unit 1 intake structure ventilation design bases into specifications.
Description. Arkansas Nuclear One, Unit 1, Calculation 93-D-5015-01, Unit 1 Intake
Structure Natural Convection, Revision 1, addressed the cooling of the components in
the Unit 1 intake structure during a design basis accident. These components, which
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Enclosure
include the service water pumps, rely on natural convection through doors and openings
in the structure for cooling since the intake structure does not contain emergency
powered ventilation fans. The inspectors measured the dimensions of the openings
relied upon for natural convection and noted that the openings were not as large as
those assumed in the calculation. The inspectors noted that engineering personnel had
not considered the flow obstruction caused by the open louvers on the structures
access doors. Additionally, the inspectors noted that engineering personnel did not
consider restrictions in air flow caused by support beams for the missile shields on the
structures roof along with the air flow restriction caused by the placement of two of the
shields adjacent to vertical walls. The calculation assumed openings for the doors and
roof openings for the intake structure would allow a free flow area for ventilation of
30 square feet. Dimensions measured by the inspectors yielded an area of 23 square
feet. The inspectors concluded that the licensees calculation for design basis cooling of
the intake structure was nonconservative because the openings which would allow the
convection air flow were not as large as assumed in the calculation. As part of their
corrective actions, the licensee performed more precise measurements and updated
their calculation showing that heat removal was 13 percent less than previously
assumed with the openings that existed in the intake structure.
Analysis. The inspectors determined that this finding is more than minor because it is
analogous to Example 3.i of Appendix E, Examples of Minor Issues, of Manual
Chapter 0612, Power Reactor Inspection Reports, because the licensee's engineering
staff had to reperform a calculation to assure accident analysis requirements were met
after identification of a significant dimensional discrepancy. The finding affected the
mitigating systems cornerstone. Using the Phase 1 worksheets in Manual
Chapter 0609, Significance Determination Process, the issue was determined to have
very low safety significance because it did not result in an actual loss of safety function.
The inspectors determined that even though the calculation was nonconservative,
adequate convection flow would have been available to cool components in the Unit 1
intake structure.
Enforcement. Criterion III of 10 CFR Part 50, Appendix B, Design Control, states, in
part, that measures shall be established to assure that the design basis is correctly
translated into specifications. Contrary to the above, engineering personnel did not
correctly translate the design basis heat removal requirements for the Unit 1 intake
structure into the proper specifications for the size of openings in the intake structure.
Because of the very low safety significance of the finding and because the licensee has
entered these issues into their corrective action program in Condition
Report ANO-1-2004-1829, the inspectors treated this as a NCV, consistent with
Section VI.A of the NRC Enforcement Policy, NCV 05000313/2004004-01,
Nonconservative Calculation of Design Basis Intake Structure Ventilation.
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Enclosure
1R04
Equipment Alignment (71111.04)
a.
Inspection Scope
Partial System Walkdowns. The inspectors (1) walked down portions of the three below
listed risk important systems and reviewed plant procedures and documents to verify
that critical portions of the selected systems were correctly aligned; and (2) compared
deficiencies identified during the walk down to the licensee's corrective action program
to ensure problems were being identified and corrected.
July 27, 2004, Unit 2 Inverters 2Y22 and 2Y24 and their associated portion of the
AC and DC distribution systems, the inspectors performed a partial system
walkdown of accessible portions of these distribution systems during periodic
maintenance on Swing Inverter 2Y2224.
August 24, 2004, Unit 1 emergency feedwater (EFW) system, the inspectors
performed a partial system walkdown of accessible portions of the Train B
portion of the system during periodic maintenance on the steam driven EFW
pump (Train A).
September 8, 2004, Unit 1 EFW system, the inspectors performed a partial
system walkdown of accessible portions of the Train A portion of the system
during periodic maintenance on the Train B portion of the EFW system.
The inspectors completed three samples.
Complete Walkdown. The inspectors (1) reviewed plant procedures, drawings, the
Updated Final Safety Analysis Report, Technical Specifications, and vendor manuals to
determine the correct alignment of the system; (2) reviewed outstanding design issues,
operator work arounds, and corrective action program documents to determine if open
issues affected the functionality of the system; and (3) verified that the licensee was
identifying and resolving equipment alignment problems.
August 11-12, 2004, Unit 1 decay heat system, the inspectors performed a
complete system walkdown of accessible portions of the system. This walkdown
was performed during the period when Decay Heat System Pump P-34A was
taken out of service for scheduled maintenance.
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
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Enclosure
1R05
Fire Protection (71111.05AQ)
a.
Inspection Scope
Annual Inspection. The inspectors observed a fire brigade drill on August 14, 2004, to
evaluate the readiness of licensee personnel to prevent and fight fires, including the
following aspects: (1) use of protective clothing, (2) use of breathing apparatuses,
(3) placement and use of fire hoses, (4) entry into the fire area, (5) use of fire fighting
equipment, (6) brigade leader command and control, (7) communications between the
fire brigade and control room, (8) searches for fire victims and fire propagation,
(9) smoke removal, (10) use of prefire plans, and (11) adherence to the drill scenario.
The licensee simulated a fire in the Unit 2 controlled access dress out area (Fire
Zone 2136 of the 386' elevation of the auxiliary building).
The inspectors completed one sample.
Quarterly Inspection. The inspectors walked down the six below listed plant areas to
assess the material condition of active and passive fire protection features, their
operational lineup, and their operational effectiveness. The inspectors (1) verified that
transient combustibles and hot work activities were controlled in accordance with plant
procedures; (2) observed the condition of fire detection devices to verify they remained
functional; (3) observed fire suppression systems to verify they remained functional;
(4) verified that fire extinguishers and hose stations were provided at their designated
locations and that they were in a satisfactory condition; (5) verified that passive fire
protection features (electrical raceway barriers, fire doors, fire dampers, steel fire
proofing, penetration seals, and oil collection systems) were in a satisfactory material
condition; (6) verified that adequate compensatory measures were established for
degraded or inoperable fire protection features; and (7) reviewed the corrective action
program to determine if the licensee identified and corrected fire protection problems.
June 24, 2004, Unit 1 computer room, Fire Zone 160-B
August 12, 2004, Unit 1 East decay heat removal pump room, Fire Zone 10-EE
August 13, 2004, Unit 1 West decay heat removal pump room, Fire Zone 14-EE
September 9, 2004, Unit 1 control room, Fire Zone 129-F
September 20, 2004, Unit 2 North electrical equipment room, Fire Zone 2091-BB
September 20, 2004, Unit 2 lower North electrical penetration room, Fire
Zone 2112-BB
The inspectors completed six samples.
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Enclosure
b.
Findings
Introduction. The inspectors identified a Green NCV of the Unit 2 operating license for
the failure to perform hydrostatic testing of the carbon dioxide fire extinguishers.
Description. On June 24, 2004, the inspectors requested documentation of the latest
hydrostatic test for a carbon dioxide fire extinguisher in Fire Zone 160-B. In response to
this request, the licensee initiated CR ANO-1-2004-1544 which received an apparent
cause evaluation. From this evaluation, the inspectors noted that the licensee had
initiated corrective actions to determine the number of fire extinguishers with expired
hydrostatic retest dates in 2001, following the receipt of NRC Information Notice 2001-004, Neglected Fire Extinguisher Maintenance Causes Fatality. The
licensees inspection effort was stopped due to the large number of fire extinguishers
with expired hydrostatic retesting dates (approximately 80 to 90 percent). The licensee
decided that a wholesale repair/replacement plan was needed; however, the plan was
never developed and implemented. While reviewing the corrective actions associated
with CR ANO-1-2004-1544, the inspectors determined that no fire extinguishers had
received the required hydrostatic test during the past 3 years because the licensee had
suspended the maintenance work orders.
The licensees fire hazard analysis described manual fire protection features as hose
stations and carbon dioxide fire extinguishers in 97 of the 149 fire zones listed in the
analysis. Currently, there are 228 carbon dioxide fire extinguishers strategically located
in Units 1 and 2 that are afforded to fire watches and fire brigade members for the
manual suppression of fires in the above 97 fire zones.
Analysis. The inspectors determined the issue was more than minor because, if left
uncorrected, it would become a more significant safety concern in that internal
degradation of the fire extinguishers would continue without any means of detection until
the extinguisher was unable to perform its intended function as defined in the fire hazard
analysis. Using Appendix F, Determining Potential Risk Significance of Fire Protection
and Post-Fire Safe Shutdown Inspection Findings, of Manual Chapter 0609,
Significance Determination Process, the inspectors assumed that the issue affected
the mitigating systems cornerstone and had very low safety significance (Green)
because this fire protection elements performance and reliability was minimally
impacted. This issue involved problem identification and resolution crosscutting aspects
associated with fire protection technicians failing to correct adverse conditions in a
timely manner.
Enforcement. Arkansas Nuclear One, Unit 2 facility operating license
Condition 2.C.(3)(b) states, in part, that Entergy Operations, Inc. shall implement and
maintain in effect all provisions of the approved fire protection program as described in
Amendment 9A to the Safety Analysis Report and as approved in the safety evaluation
dated March 31, 1992. Arkansas Nuclear One, Unit 2 Safety Analysis Report,
Appendix 9A, Fire Protection Program, states, in part, the ANO fire protection systems
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Enclosure
consist of numerous components including portable extinguishers. Safety Analysis
Report, Section 9.5.1, Fire Protection Systems (FPS) - Codes and Standards, states,
in part, that the fire protection system is designed in substantial compliance with the
requirements of the National Fire Codes of the National Fire Protection Association
(NFPA 1977). NFPA 10, Standard for Portable Fire Extinguishers, Chapter 7,
Hydrostatic Testing, states, in part, that fire extinguishers shall be hydrostatically
retested at intervals not exceeding those specified in Table 7.2, which establishes the
test interval for carbon dioxide fire extinguishers as 5 years.
Contrary to the above, the licensee failed to perform hydrostatic retesting of carbon
dioxide fire extinguishers every 5 years. Because of the very low safety significance and
because the licensee included this condition in the corrective action program as
CR ANO-1-2004-1544, this violation is being treated as an NCV, consistent with
Section VI.A of the NRC Enforcement Policy, NCV 05000368/2004004-02: Failure to
Perform Required Hydrostatic Testing of Pressurized Fire Extinguishers.
1R06
Flood Protection Measures (71111.06)
a.
Inspection Scope
Semi-annual Internal Flooding. The inspectors (1) reviewed the Updated Final Safety
Analysis Report, the flooding analysis, and plant procedures to assess seasonal
susceptibilities involving internal flooding; (2) reviewed the corrective action program to
determine if the licensee identified and corrected flooding problems; (3) verified that
operator actions for coping with flooding can reasonably achieve the desired outcomes;
and (4) walked down the below listed areas to verify the adequacy of (a) equipment
seals located below the floodline; (b) floor and wall penetration seals; (c) watertight door
seals; (d) common drain lines and sumps; (e) sump pumps, level alarms, and control
circuits; and (f) temporary or removable flood barriers.
August 12, 2004, Unit 1, decay heat removal vault
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification Program (71111.11)
.1
Quarterly Review.
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Enclosure
a.
Inspection Scope
The inspectors observed testing and training of senior reactor operators and reactor
operators on September 14, 2004, in the Unit 2 simulator to (1) identify deficiencies and
discrepancies in the training; (2) assess operator performance; and (3) assess the
evaluator's critique. The training scenario involved plant conditions where an
inadvertent containment isolation actuation signal, from a single train, resulted in a loss
of all feedwater to the steam generators. The loss of all feedwater was followed with a
faulted steam generator, requiring the crew to address increased containment
temperature and pressure during natural circulation cooldown of the reactor coolant
system.
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
.2
Biennial Inspection.
a.
Inspection Scope
The inspectors (1) evaluated examination security measures and procedures for
compliance with 10 CFR 55.49; (2) evaluated the licensees sample plan of the written
examinations for compliance with 10 CFR 55.59 and NUREG-1021, as referenced in the
facility requalification program procedures; and (3) evaluated maintenance of license
conditions for compliance with 10 CFR 55.53 by review of facility records (medical and
administrative), procedures, and tracking systems for licensed operator training,
qualification, and watchstanding. In addition, the inspectors reviewed remedial training
for examination failures for compliance with facility procedures and responsiveness to
address failed areas.
Furthermore, the inspectors (1) interviewed 10 personnel, including operators,
instructors/evaluators, and training supervisors, regarding the policies and practices for
administering requalification examinations; (2) observed the administration of two
dynamic simulator scenarios to one requalification crew; and (3) observed four
evaluators administer six performance measures, including four in the control room
simulator in a dynamic mode and two in the plant under simulated conditions.
The inspectors also reviewed the remediation process and the results of the biennial
written examination. The results of the examinations were assessed to determine the
licensees appraisal of operator performance and the feedback of performance analysis
to the requalification training program. The inspectors interviewed members of the
training department and operating crews to assess the responsiveness of the licensed
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Enclosure
operator requalification program. The inspectors also observed the examination
security maintenance for the operating tests during the examination week.
Additionally, the inspectors assessed the Arkansas Nuclear One, Unit 2,
plant-referenced simulator for compliance with 10 CFR 55.46 using Baseline Inspection
Procedure 71111.11 (Section 03.11). This assessment included the adequacy of the
licensees simulation facility for use in operator licensing examinations and for satisfying
experience requirements as prescribed by 10 CFR 55.46. The inspectors reviewed a
sample of simulator performance test records (transient tests, surveillance tests,
malfunction tests, and scenario-based tests), simulator discrepancy report records, and
processes for ensuring simulator fidelity commensurate with 10 CFR 55.46. The
inspectors also interviewed members of the licensees simulator configuration control
group as part of this review.
In addition to the biennial review for Unit 2, the inspectors reviewed the test results of
the Unit 1 annual operating examination for 2004. Since this was the first half of the
biennial requalification testing cycle, the licensee had not yet administered the written
examination. These results were assessed to determine if they were consistent with
NUREG 1021 guidance and Manual Chapter 0609, Appendix I, Operator
Requalification Human Performance Significance Determination Process,
requirements. This review included examination test results for 10 crews which included
56 licensed individuals.
b.
Findings
No findings of significance were identified.
.3
Examination Security
a.
Inspection Scope
The inspectors identified a minor violation of 10 CFR 55.49 for the licensee's failure to
provide examination security. The examiners reviewed examination security during the
onsite examination administration week for compliance with NUREG-1021 requirements.
Plans for simulator security and licensed operator control were reviewed.
b.
Findings
One examination security issue was identified by the licensee during the administration
of the simulator static section of the written examination. A licensee representative, on
the NRC examination security agreement, was inadvertently administered the same
static examination as the one the individual had previously validated. This action was
prohibited by NUREG-1021 and the security agreement. The error was immediately
identified by the individual and reported to the cognizant instructor.
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Enclosure
Subsequent to the identification of the administrative error, a static examination that the
affected individual had not been exposed to was selected and approved for
administration to the individual. The licensee performed a review of track records for all
Unit 2 licensed operators and verified no other individual was administered, or was
scheduled to be administered, any part of the biennial examination in which the
individuals had previously participated in the validation process. Immediate licensee
followup and short-term corrective actions were discussed with the inspector and
NRC regional management and conservatively confirmed that no potential for
communicating examination content existed, which would have the possible impact of
compromising the licensed operator requalification examination.
As stated, in part, in 10 CFR 55.49, the integrity of an examination is considered
compromised if any activity, regardless of intent, would have affected equitable and
consistent administration of the examination. Although this finding constitutes a
violation of minor significance that is not subject to enforcement in accordance with
Section IV of the NRCs Enforcement Policy, it is being documented as required by
NUREG-1021, Operator Licensing Examination Standards for Power Reactors,
Revision 8, Section ES 501, paragraph E.3.a. The licensee documented the problem in
CR ANO-2-2004-1370.
1R12
Maintenance Effectiveness (71111.12)
.1
Quarterly Reviews
a.
Inspection Scope
The inspectors reviewed the two below listed maintenance activities to (1) verify the
appropriate handling of structure, system, and component (SSC) performance or
condition problems; (2) verify the appropriate handling of degraded SSCs functional
performance; (3) evaluate the role of work practices and common cause problems;
and (4) evaluate the handling of SSCs issues reviewed under the requirements of the
Maintenance Rule, 10 CFR Part 50, Appendix B, and Technical Specifications.
Unit 2 engineered safety feature (ESF) inverter condition of momentary
out-of-synchronization of the power supplies.
Unit 1 auxiliary building heating, ventilation, and air conditioning system decay
heat vault cooler failures
The inspectors completed two samples.
b.
Findings
No findings of significance were identified.
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Enclosure
.2
Biennial Maintenance Rule Implementation
a.
Inspection Scope
Periodic Evaluation Reviews
The inspectors reviewed the licensee's last two Maintenance Rule (10 CFR 50.65,
Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power
Plants) periodic assessments. In addition, the inspectors reviewed the licensees
overall implementation of the Maintenance Rule. As part of the inspection, the
inspectors reviewed the licensees maintenance rule scope, (a)(1) determinations,
performance criteria, program definitions, use of industry operating experience, and
maintenance rule related self assessments. The inspectors verified the establishment of
appropriate goals, corrective actions, and the impact of risk monitoring. The inspectors
reviewed the conclusion reached by the licensee with regard to the balance of reliability
and unavailability for specific maintenance rule functions. The minimum sample for the
biennial inspection will consist of four SSCs/functions (of high risk significance to the
extent available) that have suffered degraded performance or condition. The inspectors
selected the following four problematic systems for a detailed review:
Repeated cracking of Alloy 600 nozzles
Repeated cracking of Unit 1, Control Rod Drive Mechanism Nozzle 56
Repetitive problems with emergency diesel generator starting air receivers
Failure of Reactor Coolant Pump P-32C
Identification and Resolution of Problems
The inspectors reviewed selected corrective action documents associated with
maintenance rule related findings. The inspectors verified that the licensee took, or
planned, appropriate corrective measures for identified issues.
The inspectors completed 4 samples.
b.
Findings
No findings of significance were identified.
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
Risk Assessment and Management of Risk. The inspectors reviewed the below listed
assessment activities to verify (1) the performance of risk assessments when required
by 10 CFR 50.65 (a)(4) and licensee procedures prior to changes in plant configuration
for maintenance activities and plant operations; (2) the accuracy, adequacy, and
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completeness of the information considered in the risk assessment; (3) the licensee
recognizes, and/or enters as applicable, the appropriate licensee-established risk
category according to the risk assessment results and licensee procedures; and (4) the
licensee identified and corrected problems related to maintenance risk assessments.
April 12, 2004, Unit 1, removal of fire/high energy line break Door 48 for the
Service Water Pump P-4B cable replacement
July 5, 2004, Unit 2, planned maintenance during the week
July 12, 2004, Unit 2, planned maintenance during the week
August 9, 2004, Unit 1, planned maintenance during the week
August through September 2004, site modifications affecting the local start of the
alternate AC diesel generator
The inspectors completed five samples.
Emergent Work Control. The inspectors (1) verified that the licensee performed actions
to minimize the probability of initiating events and maintained the functional capability of
mitigating systems and barrier integrity systems; (2) verified that emergent work-related
activities such as troubleshooting, work planning/scheduling, establishing plant
conditions, aligning equipment, tagging, temporary modifications, and equipment
restoration did not place the plant in an unacceptable configuration; and (3) reviewed
the corrective action program to determine if the licensee identified and corrected risk
assessment and emergent work control problems for the below listed activity:
July 21, 2004, Unit 2, emergent maintenance to replace a degraded cell on
ESF Battery 2D11
The inspectors completed one sample.
b.
Findings
Introduction. The inspectors identified two examples of a Green NCV of
10 CFR 50.65(a)(4) for the failure to perform adequate risk assessments.
Description. The licensee failed to consider the external risk from changing weather
conditions in previous risk assessments. During the week of July 5, 2004, the licensee
performed maintenance on the Unit 2 Emergency Diesel Generator (EDG) 2K-4A. On
July 7, 2004, the licensee tagged out the EDG and subsequently the National Weather
Service issued a thunderstorm warning. The inspectors questioned licensee personnel
on how their risk assessments took into account weather as an external event
contributor to risk during maintenance activities. In addition, the inspectors reviewed
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Enclosure
Common Operations Directive COPD024, Risk Assessment Guidelines, Change 12,
which the licensee uses to implement 10 CFR 50.65 (a)(4), Operating
Procedure 1107.001, Electrical System Operations, Revision 60, and Operating
Procedure 2107.001, Electrical System Operations, Revision 48. The inspectors
determined that, except for the specific instances of a missile or external flood barrier
being removed, the licensee had not considered the increase in risk from changing
weather conditions during maintenance activities. The inspectors noted that Regulatory
Guide 1.160, "Monitoring the Effectiveness of Maintenance in Nuclear Power Plants,"
endorsed NUMARC 93-01, "Nuclear Energy Institute Industry Guideline for Monitoring
the Effectiveness of Maintenance at Nuclear Power Plants." Section 11 of
NUMARC 93-01 specified that emergent conditions (weather) could change the
conditions of previously performed assessments and that the evaluation should be
reperformed to address the changed conditions.
The inspectors determined that the licensee's corrective actions in response to
NCV 05000313/2004003-03, Failure to adequately assess risk due to external
conditions, were incomplete. While the inspectors noted that the licensee had updated
COPD024, Risk Assessment Guidelines, and both units natural emergencies
procedures (Operating Procedures 1203.025 and 2203.008), the inspectors found that
the revised procedures were still deficient because, even with the changes, the potential
still existed for risk to not be re-evaluated based on changing weather conditions.
The inspectors determined that the licensee failed to consider the additional risk to the
plant from having a high energy line break (HELB) door removed. During the week of
April 12, 2004, the licensee removed Door 48 to facilitate the installation of new power
cables for the Unit 1 Service Water Pump P-4B. HELB Door 48 provided a barrier
between the turbine building and the Unit 1 South switchgear room. The inspectors
reviewed Common Operations Directive COPD024, Risk Assessment Guidelines,
Change 12, and found that the document stated that HELB door requirements are not
modeled quantitatively or qualitatively. Upon questioning the licensee, the inspectors
determined that the licensee addressed HELB doors being removed through an
engineering request, which included impact statements and contingency actions. As the
licensee documented in CR ANO-C-2004-1402, the engineering request may not in all
cases address an increase in risk from a 10 CFR 50.65(a)(4) perspective. While the
licensee did station a continuous fire watch (Door 48 is also a fire barrier door), the
engineering request did not address the increase in overall plant risk due to the lack of
separation between the turbine building and a safety-related switchgear room.
Analysis. The inspectors determined that both examples affected the mitigating
systems cornerstone and that the finding was more than minor because, if left
uncorrected, it would become a more significant safety concern in that actions to
manage increases in risk may not be implemented. Using the Phase 1 worksheets in
Manual Chapter 0609, Significance Determination Process, the example involving
changing weather conditions was determined to have very low safety significance
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Enclosure
because the finding did not result in a loss of function per Generic Letter 91-18,
Revision 1, Information to Licensees Regarding NRC Inspection Manual Section on
Resolution of Degraded and Nonconforming Conditions.
The example involving the high energy line break door was analyzed using the Phase 1
worksheets in Manual Chapter 0609, Significance Determination Process, from which
the inspectors determined that the finding affected the mitigating systems and barrier
integrity cornerstones. As a result, the inspectors performed a Phase 2 analysis using
Appendix A, "Technical Basis For At Power Significance Determination Process, of
Manual Chapter 0609, Significance Determination Process, and the Phase 2
worksheets from Risk-Informed Inspection Notebook for Arkansas Nuclear
One - Unit 1. In this determination, the inspectors postulated a break which would
disable the Train A 4160 VAC switchgear and that operations personnel would not be
able to recover the switchgear. The inspectors assumed that the only affected event
was a main steam line break and that the exposure time for the condition was 5 days.
The Phase 2 analyses demonstrated that the finding was of very low safety significance.
Using Appendix H, Containment Integrity Significance Determination Process, of
Manual Chapter 0609, the inspectors determined that the finding was of very low safety
significance because of the low core damage probability determined from the Phase 2
analysis.
Enforcement. 10 CFR 50.65(a)(4) requires, in part, that the licensee shall assess and
manage the increase in risk that may result from proposed maintenance activities.
Contrary to this, the licensee did not adequately assess risk from maintenance activities
during adverse weather conditions and following the removal of a HELB barrier.
Because of the very low safety significance and because the licensee included this
condition in the corrective action program as ANO-C-2004-1279 and ANO-C-2004-1402,
this violation is being treated as an NCV, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000313/2004004-03; 05000368/2004004-03, Failure to
Adequately Assess Risk.
1R14
Operator Performance During Nonroutine Plant Evolutions and Events
a.
Inspection Scope
The inspectors (1) reviewed operator logs, plant computer data, and/or strip charts for
the below listed evolutions to evaluate operator performance in coping with nonroutine
events and transients; (2) verified that operator response was in accordance with the
response required by plant procedures and training; and (3) verified that the licensee
has identified and implemented appropriate corrective actions associated with personnel
performance problems that occurred during the nonroutine evolutions sampled.
July 21, 2004, Unit 2, the licensee replaced a degraded cell in ESF Battery 2D11
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Enclosure
August 29, 2004, Unit 2, the licensee reduced reactor power to 10 percent rated
thermal power and removed the turbine generator from operation to allow
replacement of the degraded stator water cooling filter which was causing
reduced cooling flow to the main turbine generator
The inspectors completed two samples.
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors (1) reviewed plants status documents such as operator shift logs,
emergent work documentation, deferred modifications, and standing orders to
determine if an operability evaluation was warranted for degraded components;
(2) referred to the Updated Final Safety Analysis Report and design basis documents to
review the technical adequacy of licensee operability evaluations; (3) evaluated
compensatory measures associated with operability evaluations; (4) determined
degraded component impact on any Technical Specifications; (5) used the significance
determination process to evaluate the risk significance of degraded or inoperable
equipment; and (6) verified that the licensee has identified and implemented appropriate
corrective actions associated with degraded components.
CR ANO-1-2004-0989
Unit 1 source range Nuclear Instrument NI-502
failure during core alterations of the reactor vessel
CR ANO-1-2004-1705
Unit 1 EDG K-4B lube oil leak at temperature
switch TSH-5271
CR ANO-1-2004-2076
Unit 1 service water pumps corrosion at wet end to
CR ANO-2-2004-0779
Alternate AC diesel generator DC Battery 2D-55
service capacity concerns
CR ANO-2-2004-1235
Unit 2 Excore C DC power supply voltage on plant
protection system cabinet indicating low
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Enclosure
CR ANO-2-2004-1277
Unit 2 ESF Battery 2D11 low cell voltage on Cell 25
The inspectors completed six samples.
b.
Findings
Introduction. An unresolved item was identified for the repeated failures of licensee
personnel to promptly identify and correct degraded conditions associated with Unit 1
EDG K-4B Temperature Switch TSH-5271.
Description. In 1990, the temperature switch for the lubricating oil scavenging pump
discharge (TSH-5271) was discovered leaking by the licensee. A leak repair was
attempted by tightening the fitting which resulted in the threaded fitting breaking.
Licensee personnel attempted to replace the switch fitting, but because no exact
replacement fittings were readily available, they implemented a different fitting
arrangement. The replacement fitting arrangement consisted of two 1/2 to 3/8-inch
fittings coupled together to replace one 1/2 to 1/2-inch fitting. This new arrangement
was smaller in diameter at the 3/8-inch threaded coupling and consequently not as
robust. The replacement occurred without engineering personnel questioning the
adequacy of the strength of the smaller fitting. The cantilever configuration of the fitting
and switch in a high vibration environment was also not questioned by engineering
personnel. The inspectors questioned the licensee concerning the EDG manufacturer's
involvement related to the replacement configuration. No evidence was found that the
EDG manufacturer was contacted.
The new fittings prevented oil leakage until 1995 when a leak was discovered and
corrected. No additional problems were noted until June 2003 when a 3 drop per minute
(dpm) leak was noticed by operations personnel during an EDG surveillance test. In
September 2003 maintenance personnel disassembled and tightened the fitting using
sealant to stop the leak. No leakage was observed during the next four surveillance
runs.
During the January 12, 2004, surveillance run, the fitting developed a 10 dpm leak,
which prompted licensee personnel to initiate another work order for repair of the leak.
This work order was scheduled to be completed during the EDG outage in
February 2005. The leak rate remained at 10 dpm during the next four surveillance
runs.
On May 18, 2004, 1 week following the May surveillance run, the fitting began leaking at
4 dpm with the engine secured. CR ANO-1-2004-1442 was generated to document the
condition and was closed without adjusting the priority to the last existing work order,
which was still scheduled to be performed in February 2005.
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Enclosure
During the May 31, 2004 surveillance run, operations personnel quantified the new leak
rate at 136 dpm with the engine running. CR ANO-1-2004-1520 was generated to
document the increased leak rate. This CR did not adequately address the significance
of the increased leak rate on the operability of the EDG and the possibility of the leak
becoming worse. Corrective actions assigned by this CR rescheduled leak repairs to
August 2004.
During the June 28, 2004, surveillance run, the leak rate increased to 400 dpm with the
engine running. A system engineer present during the surveillance run of the EDG was
asked by operations personnel to evaluate the leakage by writing an additional CR. No
CR was written and the repair activity was not rescheduled.
On July 2, 2004, operations personnel noted an increase in the leak rate from 6 to
14 dpm with the engine secured and generated CR ANO-1-2004-1700. In response to
this CR, the licensee began planning for immediate repairs. During a walkdown on
July 3, 2004, operations personnel discovered the fitting leaking at 600 dpm with the
engine secured. Operations personnel declared the EDG inoperable and began repairs.
Maintenance personnel discovered a 300 degree circumferential crack in the 3/8-inch
section of one of the two fittings upon disassembly of the temperature switch. The
licensee sent the fitting to an independent lab for failure analysis. The independent lab
determined the failure of the fitting to be caused by high torque and vibration fatigue.
The inspectors reviewed the licensees actions in response to the increasing leak rates
and determined that after the observation of leakage on May 18, 2004, the licensee did
not promptly identify a degrading leak. As a result, timely action was not taken to repair
the leak.
Analysis. This finding has the potential to be more than minor because it affected the
mitigating systems cornerstone objective of ensuring the availability and reliability of
systems that respond to initiating events to prevent undesirable consequences. Using
the Phase 1 worksheets in Manual Chapter 0609, Significance Determination Process,
the inspectors determined that the finding may represent a loss of one train of a
Technical Specification component for greater than the allowed outage time. As a
result, the inspectors performed a Phase 2 analysis using Appendix A, Technical Basis
For At Power Significance Determination Process, of Manual Chapter 0609,
Significance Determination Process, and the Phase 2 worksheets from Risk-Informed
Inspection Notebook for Arkansas Nuclear One - Unit 1. The inspectors assumed that
(1) the leak rate would have increased on EDG K-4B as the amount of run time
accumulated on the engine between September 23, 2003 and July 3, 2004, (2) the EDG
would not have performed its safety function without exigent corrective actions to repair
the fitting or replenish the lube oil, (3) the duration for not meeting the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> offsite
power recovery time, given the leak rate, was approximately 32 days, (4) licensee
personnel would not have acted to replenish lube oil inventory until it manifested itself in
a large leak at the temperature switch, and (5) licensee actions to replenish lube oil
inventory were not credited because of the difficulty in retrieving the oil, transporting the
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Enclosure
oil, and filling the sump. Using these assumptions, the inspectors determined that the
finding had potentially greater than Green safety significance. The dominate core
damage sequence involved a loss of offsite power with a failure of the EDGs and the
failure to recover offsite power.
The duration of the condition and the application of the assumptions is under review by
the regional senior risk analysts. Therefore, this finding is considered an unresolved
item. This issue is not an immediate safety concern because on July 3, 2004, the
licensee removed the EDG from service and repaired the degraded fitting with the
original design, thereby restoring structural integrity to the EDG K-4B lube oil system.
This finding involved problem identification and resolution crosscutting aspects
associated with operations and engineering personnel not recognizing the significance
of the degraded condition and not implementing timely corrective actions to repair the
leak.
Enforcement. From May 18 to July 2, 2004, the licensee did not promptly identify and or
implement actions to repair a degrading fitting on Temperature Switch TSH-5271. The
licensee entered this condition in their corrective action program as
CR ANO-1-2004-1705. Pending the determination of the duration of the condition and a
review of the safety significance by the regional senior reactor analyst, this finding is
considered an unresolved item (URI)05000313/2004004-04, Untimely Corrective
Action to Fix Oil Leak Renders Emergency Diesel Generator Inoperable.
1R16
Operator Workarounds (71111.16)
a.
Inspection Scope
Selected Operator Workarounds: The inspectors reviewed the two below listed operator
workarounds to (1) determine if the functional capability of the system or human
reliability in responding to an initiating event is affected; (2) evaluate the effect of the
operator workaround on the operators ability to implement abnormal or emergency
operating procedures; and (3) verify that the licensee has identified and implemented
appropriate corrective actions associated with operator workarounds.
Selected Operator Workarounds 1-04-09, Unit 1 Train A and B decay heat check
valve back leakage
CR ANO-2-2004-1624, Unit 2 high pressure safety injection pressurization
system pump operation
The inspectors completed two samples.
b.
Findings
No findings of significance were identified.
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Enclosure
1R19
Post-Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors selected the five below listed postmaintenance test activities of risk
significant systems or components. For each item, the inspectors (1) reviewed the
applicable licensing basis and/or design-basis documents to determine the safety
functions; (2) evaluated the safety functions that may have been affected by the
maintenance activity; and (3) reviewed the test procedure to ensure it adequately tested
the safety function that may have been affected. The inspectors either witnessed or
reviewed test data to verify that acceptance criteria were met, plant impacts were
evaluated, test equipment was calibrated, procedures were followed, jumpers were
properly controlled, the test data results were complete and accurate, the test
equipment was removed, the system was properly realigned, and deficiencies during
testing were documented. The inspectors also reviewed the corrective action program
to determine if the licensee identified and corrected problems related to
post-maintenance testing.
Week of August 9, 2004, Unit 2 EDG 2K-4A, reviewed Work Order
Package 0004283802 for replacement of Cylinder 5 and 9 temperature elements
August 26, 2004, Unit 1 EFW Pump P-7A, reviewed Procedure 1106.006,
Emergency Feedwater Pump Operation, Supplement 12, Steam Driven
Emergency Feedwater Pump Test (Quarterly), Revision 64, which was
performed following maintenance on the turbine driven pump
September 2, 2004, Unit 1 Decay Heat Pump P-34A, reviewed
Procedure 1104.004, Decay Heat Removal Operating Procedure,
Supplement 1, Low Pressure Injection (Decay Heat) Pump and Components
Quarterly, Revision 71, which was performed following maintenance on the
pump
September 22, 2004, Unit 2 High Pressure Injection Pump 2P-89A, reviewed
Procedure 2104.039, HPSI System Operation, Supplement 1, 2P-89A
Quarterly Test, Revision 42, which was performed following maintenance on the
pump
September 23, 2004, Unit 1 Reactor Building Spray Pump P-35A, reviewed
Procedure 1104.005, Reactor Building Spray System Operation, Supplement 3,
RB Spray Pump P-35A Quarterly Test (Red Train), Revision 42, which was
performed following maintenance on the pump
The inspectors completed five samples.
-19-
Enclosure
b.
Findings
No findings of significance were identified.
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report, procedure
requirements, and Technical Specifications to ensure that the eight below listed
surveillance activities demonstrated that the SSCs tested were capable of performing
their intended safety functions. The inspectors either witnessed or reviewed test data to
verify that the following significant surveillance test attributes were adequate:
(1) preconditioning; (2) evaluation of testing impact on the plant; (3) acceptance criteria;
(4) test equipment; (5) procedural adherence; (6) jumper/lifted lead controls; (7) test
data; (8) testing frequency and method demonstrated Technical Specification
operability; (9) test equipment removal; (10) restoration of plant systems; (11) fulfillment
of ASME Code requirements; (12) updating of performance indicator data,
(13) engineering evaluations, root causes, and bases for returning tested SSCs not
meeting the test acceptance criteria were correct; (14) reference setting data;
and (15) annunciator and alarm setpoints. The inspectors also verified that the licensee
identified and implemented any needed corrective actions associated with the
surveillance testing.
September 5, 2003, alternate AC diesel generator 18 month surveillance test per
Procedure 2104.037, Revision 6
April 13, 2004, Unit 1, source range channel linear amplifier calorimetric
calibration per Procedure 1304.055, Revision 12
May 21, 2004, Unit 2, Containment Spray Pump 2P-35A Quarterly Test per
Procedure 2104.005, Supplement 1, Revision 42
May 27, 2004, Unit 1, EFW Steam Admission Valve CV-2663 stroke testing per
Procedure 1106.006, Revision 64
July 9, 2004, Unit 2, low pressure safety injection and refueling water tank
motor-operated valve stroke testing per Procedure 2104.040, Revision 35
July 11, 2004, Unit 2, service water valve quarterly stroke test performed per
Procedure 2104.029, Revision 54
July 15, 2004, Unit 1, Continuous Air Monitors RE-7460 and RE-7461 quarterly
testing per Procedure 1304.181, Revision 8, (RCS leakage detection
surveillance)
-20-
Enclosure
July 27, 2004, Unit 2, Swing Inverter 2Y2224 periodic testing performed per
Procedure/Work Plan 2416.046, Revision 3. During the performance of this
procedure, the technicians increased the Inverter Output Overvoltage Alarm,
setpoint per ER ANO-2003-0644-000 (Work Order Package 0038659,
Revision 1) and replaced critical status lights per ER ANO-2003-0618-000 (Work
Order Package 00035555, Revision 1). The installation of the new lights
addressed existing problems of short bulb life and the inability of operators to
replace burned bulbs
The inspectors completed eight samples.
b.
Findings
Introduction. The inspectors identified an Apparent Violation of 10 CFR Part 50,
Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, for the
licensee's failure to establish controls to prevent a breaker with a loose connection from
being installed in Unit 2.
Description. During a quarterly surveillance test on May 20, 2004, Unit 2 Containment
Spray Pump 2P-35A failed to start. This was the first instance of this pump failing to
start since the licensee replaced the 4160 VAC breaker in 2001. Licensee personnel
conducted troubleshooting to diagnose the cause of the pump failure and found
elevated resistance across the contacts for Relay LS-9 in the breaker's closing circuit.
Convinced that this was the cause of the breaker failure, the licensee replaced
Relay LS-9 and returned the breaker and pump to service. During postmaintenance
testing, the breaker was cycled satisfactorily 11 times and the pump started with the
breaker racked-in.
On June 3, 2004, engineering personnel contacted the breaker vendor, Siemens, to
inform them of their findings with the high resistance across the contacts. The vendor
refuted the licensee's finding stating that any resistance would have been burned
through by the 250 volts DC supplied to the breaker's closing circuit during the start
sequence. The vendor recommended that the licensee check other parts of the circuit
to identify the cause of the failed breaker.
On August 9, 2004, the licensee racked out the containment spray pump breaker for
further troubleshooting and discovered that a spade-lug connection leading to the
anti-pump relay in the closing circuitry was loose. The spade was not completely
inserted into the lug, giving intermittent elevated resistance readings to the relay
technicians who were troubleshooting the breaker. The inspectors noted that the
licensee delayed additional inspections of the breaker even though the vendor had
provided information which contradicted their cause of the breaker's failure mechanism.
-21-
Enclosure
During conversations after the discovery, one licensee technician noted that he had
discovered five or six similar loose connections while performing receipt inspections of
this group of breakers in 2000. The inspectors questioned whether a condition report
had been written to document the discovery of loose connections during the receipt
inspection process. The licensee explained that the receipt inspection procedure for the
breakers instructed the technicians to tighten loose connections as necessary. As a
result, the technician simply inserted the spade into the lug for the loose connections he
discovered and did not document the deficiency on the receipt inspection sheet. The
technician did inform other technicians performing receipt inspections of the deficiency.
Because the loose connections were not recorded individually, a deficiency report was
not generated, and corrective actions to inspect all other spade-lug connections in the
group of breakers was not initiated. As a result, a breaker with a loose connection was
installed into the plant for the Unit 2 Containment Spray Pump 2P-35A.
The inspectors noted that Maintenance Action Item 26147 (used to inspect the
breakers) required that all deficiencies be recorded. The inspectors concluded that the
loose connections should have been documented. The inspectors noted that after the
failure of the pump to start on May 21, 2004, the degraded circuit connection was not
discovered and was left in place for 2 additional months, until August 9, due to licensee
personnel incorrectly considering Relay LS-9 as the cause of the failure of the
containment spray pump to start.
Analysis. The inspectors determined that this finding is more than minor because it is
analogous to Example 5.c of Appendix E, Examples of Minor Issues, of Manual
Chapter 0612, Power Reactor Inspection Reports, because a nonconforming
component was installed in the plant and the system it was in was returned to service.
Using the Phase 1 worksheets in Manual Chapter 0609, Significance Determination
Process, the inspectors determined that the finding effected the mitigating systems and
barrier integrity cornerstones. As a result, the inspectors performed a Phase 2 analysis
using Appendix A, "Technical Basis For At Power Significance Determination Process,
of Manual Chapter 0609, Significance Determination Process, and the Phase 2
worksheets from Risk-Informed Inspection Notebook for Arkansas Nuclear
One - Unit 2. The Phase 2 analysis determined that the finding was potentially of
greater than Green safety significance. The inspectors assumed that the duration was
greater than 30 days and that operations personnel would be able to recover the
containment spray pump by starting it from the switchgear room. The dominate core
damage sequences involved a loss of AC or DC busses, a failure of emergency
feedwater, and a failure of containment spray recirculation. Specifically, the small break
loss of coolant accident and stuck open relief valve sequences were most limiting. A
review of the Phase 2 analysis and performance of a Phase 3 analysis by a regional
senior reactor analyst is needed to determine the final safety significance of the finding.
This issue is not an immediate safety concern because on August 9, 2004, the licensee
removed the Containment Spray Pump from service and repaired the loose connection,
thereby restoring electrical continuity to the containment spray pump 2P-35A breaker
-22-
Enclosure
circuitry. This issue involved problem identification and resolution crosscutting aspects
associated with maintenance technicians not identifying the cause of the breaker failure
and not documenting deficiencies in the corrective action program.
Enforcement. 10 CFR Part 50, Appendix B, Criterion XV, requires that licensees
establish measures to control components which do not conform to requirements in
order to prevent their inadvertent use. Contrary to the above, licensee personnel did not
establish adequate measures during the breaker receipt inspection process in
October 2000 to prevent breakers with loose circuit connections from being installed in
the plant. As a result, the breaker was installed in the cubicle for the Unit 2 containment
spray pump breaker in February 2001. Pending determination of the findings final
safety significance, this violation is being treated as Apparent Violation (AV), consistent
with Section VI.A of the NRC Enforcement Policy: AV 05000368/2004004-05, Failure to
Identify and Correct a Loose Circuit Connection in Containment Spray Pump Circuitry.
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report, plant drawings,
procedure requirements, and Technical Specifications to ensure that the one temporary
modification listed below was properly implemented. The inspectors (1) verified that the
modification did not have an affect on system operability/availability; (2) verified that the
installation was consistent with the modification documents; (3) ensured that the
post-installation test results were satisfactory and that the impact of the temporary
modification on permanently installed SSCs were supported by the test; (4) verified that
the modifications were identified on control room drawings and that appropriate
identification tags were placed on the affected drawings; (5) verified that appropriate
safety evaluations were completed; and (6) examined drawings, procedures, and
operations logs for temporary modifications that have not been so designated. The
inspectors verified that the licensee identified and implemented any needed corrective
actions associated with temporary modifications.
Weeks of August 2 and 9, 2004, Unit 2 green train high pressure safety injection
header, temporary alteration of a high pressure safety injection pressurization
system. The pressurization system was evaluated under Engineering Request
ER ANO-2000-3275-003.
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
-23-
Enclosure
1EP6 Drill Evaluation (71114.06)
a.
Inspection Scope
For the below listed drill and simulator-based training evolutions contributing to
drill/exercise performance and emergency response organization performance
indicators, the inspectors (1) observed the training evolution to identify any weaknesses
and deficiencies in classification, notification, and protective action requirements
development activities; (2) compared the identified weaknesses and deficiencies against
licensee identified findings to determine whether the licensee is properly identifying
failures; and (3) determined whether licensee performance is in accordance with the
guidance and acceptance criteria of NEI 99-02, Regulatory Assessment Indicator
Guidelines, Revision 2.
September 15, 2004, the inspectors evaluated the licensees performance in the
Unit 2 simulator, emergency operating facility, and the technical support center
during a quarterly emergency plan drill that involved a loss of lake level, loss of
the emergency cooling pond, degradation of the service water system, and a
reactor coolant system leak into the component coolant water system which
resulted in the release of radioactivity from the containment building to the
environment.
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
a.
Inspection Scope
The inspectors sampled licensee submittals for the two performance indicators listed
below on both units for the period from July 1, 2003, through June 30, 2004. The
inspectors verified (1) the accuracy of the performance indicator data reported during
that period; and (2) used the performance indicator definitions and guidance contained
in NEI Document 99-02, Regulatory Assessment Indicator Guidelines, Revision 2, to
verify the basis in reporting for each data element.
-24-
Enclosure
Reactor Safety Performance Indicators
Safety system unavailability, auxiliary feedwater system
Safety system unavailability, residual heat removal system
The inspectors reviewed operator log entries, daily shift manager reports, plant
computer data, CRs, maintenance action items, maintenance rule data, and
performance indicator data sheets to determine whether the licensee adequately verified
the performance indicators listed above. This number was compared to the number
reported for the performance indicator during the past 3 quarters. Also, the inspectors
interviewed licensee personnel responsible for compiling the information.
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1
Annual Sample Review
a.
Inspection Scope
The inspectors chose one issue for more in depth review to verify that licensee
personnel had taken corrective actions commensurate with the significance of the
issues. The issues and their bases for their selection are described below:
The 10 CFR 50.65(a)(4) implementation procedure, COPD024, Risk
Assessment Guidelines, has had a number of revisions during the past quarter
due to both NRC and licensee identified weaknesses and violations.
CR ANO-C-2004-0548 documented the changes as a result of failing to
reperform risk assessments due to changing external events (weather related
issues).
When evaluating the effectiveness of the licensees corrective actions for these issues,
the following attributes were considered:
Complete and accurate identification of the problem in a timely manner
commensurate with its significance and ease of discovery
Evaluation and disposition of operability and reportability issues
Consideration of extent of condition, generic implications, common cause, and
previous occurrences
-25-
Enclosure
Classification and prioritization of the resolution of the problem commensurate
with its safety significance
Identification of root and contributing causes of the problem for significant
Identification of corrective actions which are appropriately focused to correct the
problem
Completion of corrective actions in a timely manner commensurate with the
safety significance of the issue
b.
Findings
The inspectors determined that the licensee's corrective actions in response to NCV 05000313/2004003-03, Failure to adequately assess risk due to external conditions,
were incomplete. While the inspectors noted that the licensee had updated COPD024,
Risk Assessment Guidelines, and both units natural emergencies procedures
(Operating Procedures 1203.025 and 2203.008), the inspectors found that the revised
procedures were still deficient because, even with the changes, the potential still existed
for risk to not be re-evaluated based on changing weather conditions (See
Section 1R13).
.2
Cross-References to Problem Identification and Resolution Findings Documented
Elsewhere
Section 1R05 documents a condition where the licensee failed to identify and correct
conditions adverse to safety in that carbon dioxide fire extinguishers were not being
hydrostatically retested on a 5-year interval as required by NFPA 10 requirements.
Section 1R13 and 4OA2 documents a condition where operations and engineering
personnel did not implement corrective actions to address the extent of condition from a
previous maintenance rule noncited violation documented in NRC Inspection Report 05000313/2004003 and 05000368/2004003.
Section 1R15 documents a condition where the licensee did not take timely corrective
actions to assure that oil leakage was repaired on the Unit 1 Emergency Diesel
Generator K-4B.
Section 1R22 documents a condition where maintenance technicians did not document
loose connections in circuitry associated with the breaker for the Unit 2 Containment
Spray Pump 2P-35A or identify the cause of the breaker failure in a timely manner.
-26-
Enclosure
.3
Observations with the Substantive Crosscutting Issue in Problem Identification and
Resolution
As a result of numerous findings dealing with the licensees corrective action program
(CAP), the NRC staff identified a substantive crosscutting issue in the area of problem
identification and resolution during its annual assessment for inspections conducted
in 2003. In this inspection quarter, inspectors made the following observations
pertaining to the specific areas listed below, which were identified as areas with
implementation problems.
Problem Identification and Entry into the CAP. The inspectors noted that the issue with
Unit 2 Containment Spray Pump 2P-35A was never entered into the corrective action
program or its counterpart for the licensees receipt inspection program. As a result, a
breaker with a loose connection was installed into the plant as described in
Section 1R22.
Prioritizing and Evaluating Conditions in the CAP. The inspectors noted that a leaking
oil condition from a fitting on the Unit 1 EDG K-4B was not adequately prioritized or
evaluated which affected the reliability of the EDG as described in Section 1R15.
Implementing Effective Corrective Actions. The inspectors identified an example where
a plan to ensure all fire extinguishers were adequately hydrostatically tested per
NFPA code was not implemented and, therefore, the periodicity of these tests had
lapsed as described in Section 1R05. Additionally, the inspectors identified an example
where operations and engineering personnel did not implement corrective actions to
address the extent of condition from a previous maintenance rule noncited violation
documented in NRC Inspection Report 05000313/2004003.
4OA3 Event Followup (71153)
.1
(Closed) LER 05000313/2004001-01, Operation Prohibited by Technical Specifications
due to an Undetected Inoperable Channel of Required Source Range Nuclear
Instrumentation during Core Alterations Caused by a Signal Processing Unit Circuit
Breaker Failure
a.
Inspection Scope
The inspectors reviewed the LER, corrective action documents CR ANO-1-2004-0645
and CR ANO-1-2004-0989, Unit 1 station operating logs, plant procedures, and plant
computer trends. This review verified that the cause of the April 29, 2004 source range
nuclear neutron monitor failure was identified and corrective actions were appropriate.
The monitor failure was caused by a faulty circuit breaker which provided power to the
process panel that drives the source range instrument. The inspectors also reviewed
the corrective action database for other past failures related to source range nuclear
neutron monitors.
-27-
Enclosure
b.
Findings
Introduction. A self-revealing Green NCV of Unit 1 Technical Specification 3.9.2 was
identified due to an inoperable source range nuclear neutron monitor which reduced the
number of operable instruments below the requirements of Technical Specifications
during core alterations.
Description. On April 29, 2004, at 10:51 p.m. shortly after completion of core offload for
Refueling Outage 1R18, operators discovered that one of two redundant trains of
source range nuclear neutron monitors was inoperable. The operators reviewed plant
computer historical data and determined the green train source range nuclear neutron
monitor had failed at 10:52 a.m. on April 29, 2004. As a result, for approximately
11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />, movement of spent fuel assemblies from the reactor vessel had occurred with
only one of the required two source range nuclear neutron monitors operable.
Operators stationed to monitor the source range instruments did not notice the failure of
the green train instrument.
Analysis. The finding is more than minor because it affects the barrier integrity
cornerstone objective of providing reasonable assurance that physical design barriers
protect the public from radionuclide releases caused by accidents or events attributable
to configuration control. Using Appendix G, Shutdown Operations Significance
Determination Process, of Manual Chapter 0609, Significance Determination Process,
the finding was determined to have very low safety significance (Green) because it did
not affect the licensee's ability to maintain reactor coolant system inventory, terminate a
leak path, or recover decay heat removal.
Enforcement. Unit 1 Technical Specification 3.9.2, Nuclear Instrumentation, requires
that one source range neutron nuclear monitor be operable in Mode 6. Additionally,
Technical Specification 3.9.2 requires that one additional source range neutron nuclear
monitor be operable during core alterations. Contrary to the above, on April 29, 2004,
the licensee performed core alterations (removed fuel from the reactor vessel) with only
one source range neutron nuclear monitor operable for 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />. Because the finding
was determined to have very low safety significance and has been entered in the
licensee's corrective actions program as CR ANO-1-2004-0989, this violation is being
treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000313/2004004-06, Core Alterations with Less than Two Operable Source
Range Neutron Nuclear Monitors.
-28-
Enclosure
.2
(Closed) LER 05000368/2002002-00, Automatic Actuation of the Reactor Protection
System Caused by a Main Turbine Trip due to Failure of the Main Generator Reverse
Power Relay Resulted in a Reactor Trip
a.
Inspection Scope
The inspectors reviewed the LER and corrective action document CR ANO-2-2002-2173
to verify the cause of the December 19, 2002, Unit 2 reactor trip and that corrective
actions were reasonable. The reactor trip was caused by a main turbine trip which
resulted from the failure of the main generator reverse power relay. The inspectors
reviewed plant parameters and verified that licensee staff properly implemented the
appropriate plant procedures and that plant equipment performed as required. The
inspectors also reviewed the cause of the sequence of events dating back to the original
procurement of the failed relay and associated operational experience.
b.
Findings
Introduction. A self-revealing Green finding was identified for an inadequate
maintenance procedure which did not include vendor recommended maintenance for
the Unit 2 main generator reverse power relay.
Description. The licensee installed General Electric (GE) Model GGP relays for their
reverse power relays in Unit 2. These relays were designed to receive input from
current and voltage transformers on the main generator output which in turn were
designed to provide rotary motion of a vertical shaft. An arm containing a moving
contact at its end was attached to the shaft using a clutch (essentially a set screw).
Rotary action was designed to occur instantly upon sensing a reverse power condition.
On December 19, 2002, while the plant was operating at 100 percent rated thermal
power, the reverse power relay inadvertently operated with no reverse power condition
present, resulting in a Unit 2 reactor trip. Inspection of the relay identified that the clutch
had been slipping. This slippage eventually wore the shafts pivot bearing completely
away and allowed the contact on the arm to close, which caused the relay to actuate on
reverse power even though no reverse power condition existed.
Follow-up correspondence between GE and the licensee uncovered that the licensee
had not been performing the clutch tightness test required by GE
Document GEK-34117, Polyphase Power Directional Relay for Anti-Motoring
Protection. Consequently, maintenance personnel were not aware that the clutch on
the relay was slipping. This GE document was used to develop master preventative
Maintenance Procedure ANO PM-070, Protective Relays, and the specific
maintenance procedures for these reverse power relays. A review of these documents
revealed that the clutch tightness check recommended by Document GEK-34117 was
not included in the applicable ANO preventative maintenance engineering evaluation or
maintenance procedures.
-29-
Enclosure
Analysis. This finding is greater than minor because it was analogous to Example 4.b in
Appendix E, Examples of Minor Issues, of Manual Chapter 0612, Power Reactor
Inspection Reports, in that a procedural error caused a reactor trip. This finding
affected the initiating events cornerstone. Using the Phase 1 worksheet in Manual
Chapter 0609, Significance Determination Process, the finding was determined to
have very low safety significance (Green) because, although it resulted in a reactor trip,
all mitigating systems remained available to the operators.
Enforcement. No violation of regulatory requirements occurred. The inspectors
determined that the finding did not represent a noncompliance because it occurred on
nonsafety secondary plant equipment. Licensee personnel entered this issue into the
corrective action program as CR ANO-2-2002-2173: FIN 05000368/2004004-07,
Inadequate Maintenance Procedure for the Main Generator Reverse Power Relays.
.3
(Closed) LER 05000368/2004001-00, Wide-Range Containment Water Level
Transmitter in the off Position Rendering One of Two Technical Specification Channels
On March 16, 2004, a waste control operator found the power switch for one of the wide
range containment water level transmitters in the off position. This rendered the
corresponding Technical Specification required wide range containment water level
indicator inoperable. During the investigation, the licensee determined that the
transmitter had been secured on October 9, 2003, during the latter stages of the
previous refueling outage and, therefore, had been secured greater than the allowed
outage time per Technical Specification 3.3.3.6. The licensee determined that the most
probable cause of the mispositioning was an accidental bump by an individual exiting
the containment building. The inspectors reviewed CR ANO-2-2004-0551 and its
associated root cause evaluation report and determined this finding constituted a
violation of Unit 2 Technical Specification 3.3.3.6. The inspectors determined this
violation to be of minor safety significance that is not subject to enforcement action in
accordance with Section IV of the NRCs Enforcement Policy, because the redundant
channel was available, the containment sump level detection system was available, and
the transmitter was located in an area that is easily accessible and; had the need arisen,
an operator could have been dispatched to investigate and restore power. This LER is
closed.
4OA5 Other Activities
1.
Temporary Instruction 2515/154, Spent Fuel Material Control and Accounting at
Nuclear Power Plants
-30-
Enclosure
a.
Inspection Scope
The inspectors collected the data specified in Phases I and II of the temporary
instruction. The data was forwarded to the individuals identified in the temporary
instruction for consolidation and assessment.
b.
Findings
No findings of significance were identified.
4OA6 Meetings, Including Exit
The maintenance rule inspector presented the inspection results of the maintenance
effectiveness inspection to Mr. J. Forbes, Vice President, Operations, and other
members of licensees management staff on August 19, 2004. The licensee
acknowledge the findings presented.
The operations inspectors presented the inspection results of the operations
requalification inspection to Mr. J. Forbes, Vice President, Operations, and other
members of licensees management at the conclusion of the inspection on
September 8, 2004. The licensee acknowledged the findings presented.
The resident inspectors presented the inspection results of the resident inspections to
Mr. J. Forbes, Vice President, Operations, and other members of the licensee's
management staff on September 28, 2004. 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.
4OA7 Licensee-Identified Violations
The following violation of very low significance (Green) was identified by the licensee
and is a violation of NRC requirements which meet the criteria of Section VI.A of the
NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.
10 CFR 50.65(a)(4) requires, in part, that the licensee shall assess and manage the
increase in risk that may result from the proposed maintenance activities. Contrary to
this, while performing a routine risk assessment the licensee discovered they had not
modeled the Unit 1 decay heat vault room coolers into their equipment out of service
quantitative risk assessment program to assess plant risk, nor had they evaluated them
by any qualitative means. Consequently, the licensees risk assessments for
maintenance activities which affected the decay heat vault room coolers were
-31-
Enclosure
inadequate. This condition is described in the corrective action program as
CRs ANO-1-2004-1948, ANO-1-2004-1813, and ANO-1-2004-1283. This finding is of
very low safety significance because one of the two coolers provides 100 percent
cooling capability and one cooler was always available.
ATTACHMENT: SUPPLEMENTAL INFORMATION
A-1
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
B. Berryman, Manager, Planning and Scheduling
J. Bradford, Supervisor, Nuclear Training
R. Byford, Training
S. Cotton, Manager, Training
S. Cupp, Supervisor, Simulator Training
J. Eichenberger, Manager, Corrective Actions and Assessments
C. Eubanks, General Manager, Plant Operations
J. Forbes, Vice President, Arkansas Nuclear One
F. Forrest, Manager, Operations, Unit 1
D. Fowler, Quality Assurance
R. Gordon, Manager, System Engineering
W. Greeson, Acting Manager, Engineering Programs and Components
A. Hawkins, Licensing Specialist
A. Heflin, Manager, Operations, Unit 2
P. Higgins, Supervisor, Nuclear Training
G. Hines, Maintenance Rule Coordinator
J. Hoffpauir, Manager, Maintenance
R. Holeyfield, Manager, Emergency Planning
D. James, Acting Director, Nuclear Safety Assurance
S. Kaufmann, Access Authorization, Fitness For Duty
J. Kowalewski, Director, Engineering
T. Mayfield, Supervisor, Training, Unit 2
J. Miller, Manager, Nuclear Engineering
K. Nichols, Manager, Design Engineering
P. Partridge, Manager, Technical Support
K. Perkins, Supervisor, System Engineering
S. Pyle, Licensing Specialist
R. Scheide, Licensing Specialist
C. Tyrone, Manager, Quality Assurance
F. Vanbuskirk, Licensing
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Untimely Corrective Action to Fix Oil Leak Renders
Emergency Diesel Generator Inoperable (Section 1R15)05000368/2004004-05
Failure to Identify and Correct a Loose Circuit Connection in
Containment Spray Pump Circuitry (Section 1R22)
A-2
Attachment
Opened and Closed
Nonconservative Calculation of Design Basis Intake
Structure Ventilation (Section 1R01)05000368/2004004-02
Failure to Perform Required Hydrostatic Testing of
Pressurized Fire Extinguishers (Section 1R05)05000313/2004004-03
05000368/2004004-03
Failure to Adequately Assess Risk Due to External
Conditions or HELB Doors Removed (Section 1R13)05000313/2004004-06
Core Alterations with Less than Two Operable Source
Range Nuclear Neutron Monitors (Section 4OA3)05000368/2004004-07
Inadequate Maintenance Procedure for the Main Generator
Reverse Power Relays (Section 4OA3)
Closed
LER
Automatic Actuation of the Reactor Protection System
Caused by a Main Turbine Trip due to Failure of the Main
Generator Reverse Power Relay Resulted in a Reactor Trip
(Section 4OA3)05000313/2004001-01
LER
Operation Prohibited by Technical Specifications due to an
Undetected Inoperable Channel of Required Source Range
Nuclear Instrumentation During Core Alterations Caused by
a Signal Processing Unit Circuit Breaker Failure
(Section 4OA3)05000368/2004001-00
LER
Wide-Range Containment Water Level Transmitter in the
off Position Rendering One of Two Technical Specification
Channels Inoperable (Section 4OA3)
Discussed
None
A-3
Attachment
LIST OF DOCUMENTS REVIEWED
In addition to the documents called out in the inspection report, the following documents were
selected and reviewed by the inspectors to accomplish the objectives and scope of the
inspection and to support any findings:
Section1R01: Adverse Weather Protection
Engineering Calculation
89-D-2001-08, Intake Structure Ventilation Post Modification Evaluation With Worst Case Heat
Load Under Accident Conditions, Revision 0
89-D-2001-09, Unit 2 Intake Structure Environmental Temperature Study, Revision 0
93-D-5015-01, Unit 1 Intake Structure Natural Convection, Revision 1
Operating Procedures
1104.050, Turbine Building, Intake Structure, and Miscellaneous Ventilation, Revision 2
1203.012I, Annunciator K10 Corrective Action, Revision 40
Section 1R04: Equipment Alignment
Operating Procedures
1104.004, Decay Heat Removal Operating Procedure, Revision 71
2107.002, ESF Electrical System Operation, Revision 16
2107.003, Inverter and 120 VAC Electrical System Operation, Revision 19
Plant Drawings
209 Sheet 4, Revision 14; 210 Sheet 1, Revision 139; and 232 Sheet 1, Revision 99
Section 1R05: Fire Protection
CRs
ANO-1-2004-1544 and ANO-C-2004-0755
Engineering Calculation
85-E-0053-15, Revision 45
A-4
Attachment
Plant Documents
Arkansas Nuclear One Fire Hazards Analysis Report, Revision 8
ANO Pre-Fire Plan for Fire Zone 2136-I and 2119-H, Revision 1
Plant Drawings
FP-101, Fire Zone Fuel Handling Floor Plan El. 404 '- 0" and 422' - 6", Sheet 1, Revision 16
FP-105, Fire Zone Plan Below Grade EL 335' - 0", Sheet 1, Revision 18
FP-106, Fire Zone Plan at Elev. 317' - 0" & Section B-B, Sheet 1, Revision 12
FP-2103, Fire Zones Intermediate Floor Plan at Elev. 368' - 0" and 372' 0", Sheet 1,
Revision 25
FP-2104, Fire Zone Ground Floor Plan at Elev. 354' - 0", Sheet 1, Revision 29
Section 1R06: Flood Protection Measures
Engineering Calculations
92-R-0024-01 and 92-R-0034-01
Plant Drawings
FP-105, Fire Zone Plant Below Grade EL 335" - 0", Sheet 1, Revision 18
FP-106, Fire Zone Plant at Elev. 317' - 0" & Section B-B, Sheet 1, Revision 12
Section 1R11: Licensed Operation Requalification Program
Operating Procedures
1903.010, Emergency Action Level Classification, Revision 37
Training Scenario
ES-2-023, Dynamic Exam Scenario, Revision 2
Biennial
Procedures:
DG-TRNA-202-CORETEST, Simulator Core Reload Acceptance Test, Revision 1
DG-TRNA-202-EXAMSEC, Simulator Exam Security Guidelines, Revision 0
DG-TRNA-202-SIMCONTROL, Simulator Modification Control, Revision 0
ENS-TQ-201, Systematic Approach to Training Process, Revision 3
ENS-TQ-202, Simulator Configuration Control, Revision 1
A-5
Attachment
OP-1063008, Operations Training Sequence, May 29, 2003
OP-1064032, Simulator Training, November 20, 2003
Written Examinations
A2EXM-LOR-ANNUAL-RO-TEST 1
A2EXM-LOR-ANNUAL-RO-TEST 2
A2EXM-LOR-ANNUAL-RO-TEST 3
A2EXM-LOR-ANNUAL-RO-TEST 4
A2EXM-LOR-ANNUAL-RO-TEST 5
A2EXM-LOR-ANNUAL-RO-TEST 6
A2EXM-LOR-ANNUAL-SRO-TEST 1
A2EXM-LOR-ANNUAL-SRO-TEST 2
A2EXM-LOR-ANNUAL-SRO-TEST 3
A2EXM-LOR-ANNUAL-SRO-TEST 4
A2EXM-LOR-ANNUAL-SRO-TEST 5
A2EXM-LOR-ANNUAL-SRO-TEST 6
Static Scenarios (written examination)
SS-001, SS-003, SS-006, SS-008, SS-010, and SS-017
Dynamic Examination Scenarios
ES-2-008, Revision 2; ES-2-009, Revision 3; ES-2-010, Revision 4; ES-2-011, Revision 6;
ES-2-013, Revision 3; ES-2-018, Revision 8; ES-2-023, Revision 2; ES-2-024, Revision 1;
and ES-2-026, Revision 4
A2JPM-RO-SFPFL, Revision 6
A2JPM-RO-EDDCG, Revision 3
A2JPM-SRO-EAL5, Revision 0
A2JPM-RO-CVCS7, Revision 4
A2JPM-RO-RCP02, Revision 4
A2JPM-RO-EFW02, Revision 10
A2JPM-RO-FWCS1, Revision 6
A2JPM-RO-SIT05, Revision 2
A2JPM-RO-EFW03, Revision 5
A2JPM-SRO-EAL2, Revision 0
A2JPM-RO-FPEM2, Revision 10
A2JPM-RO-2RS2, Revision 4
A2JPM-RO-AAC01, Revision 2
A2JPM-RO-CCWSA, Revision 9
A2JPM-RO-CPC02, Revision 1
A2JPM-RO-CVCS2, Revision 2
A-6
Attachment
Training Evaluation Action Requests
2003-420 and 2004-146
Miscellaneous
Simulator Fidelity Report for 2003/2004
Annual Performance Testing Data for 2003
Plant Data from Loss of both Main Feedwater Pumps
Steady State Data
Transient Data
Core Performance Data
Section 1R12: Maintenance Effectiveness
CRs
ANO-1-1999-0109, ANO-2-2001-0622, ANO-2-2001-1404, ANO-1-2002-0066,
ANO-1-2002-0428, ANO-2-2002-0005, ANO-2-2002-0389, ANO-2-2002-1574,
ANO-C-2002-0151, ANO-C-2002-0395, ANO-C-2003-0640, and ANO-2-2004-0779
Operating Procedures
2107.002, ESF Electrical System Operation, Revision 16
2107.003, Inverter and 120 VAC Electrical System Operation, Revision 19
Biennial
CRs
ANO-2-2001-0092, ANO-1-2002-1155, ANO-1-2002-1191, ANO-1-2002-1489,
ANO-2-2002-1102, ANO-1-2003-0062, ANO-1-2004-1964, and ANO-2-2004-1132
Operating Procedures
1202.005, Inadequate Core Cooling, Revision 4
1203.003, Control Rod Drive Malfunction Action, Revision 20
DC-121, Maintenance Rule, Revision 1
LI-102, Corrective Action Process, Revision 4
Miscellaneous
ALO-2004-00037, Maintenance Rule Self-Assessment, July 2, 2004
Maintenance Rule (a)(1) Systems, as of August 16, 2004
Maintenance Rule Scope, as of August 16, 2004
A-7
Attachment
System Performance Criteria, August 10, 2004
Entergy Nuclear South Maintenance Rule Desk Top Guide, Revision 1
Entergy Nuclear South System Engineering Desk Guide, Revision 0
Engineering Report A-SE-2002-001-0, ANO Units 1 & 2 and Structures - 2002 Maintenance
Rule Periodic Assessment, approved October 22, 2003
Engineering Report A-SE-2004-001-0, ANO Units 1 & 2 and Structures - 2003 Maintenance
Rule Periodic Assessment, approved May 24, 2004
ANO Units 1 & 2 Availability and Reliability Data, through June, 2004
U1 & U2 Joint Expert Panel Meeting, dated March 8, 2001
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
CRs
ANO-2-2004-1188, ANO-2-2004-1302, ANO-C-2004-1279, ANO-C-2004-1402,
and ECH-2004-0307
Operating Procedures
1107.001, Electrical System Operations, Revision 60
2107.001, Electrical System Operations, Revision 48
Plant Documents
CE-P-05.07, Data Analysis for At-Power PSA Models, Revision 0
COPD024, Risk Assessment Guidelines, Change 11
COPD024, Risk Assessment Guidelines, Change 12
COPD024, Risk Assessment Guidelines, Change 13
Section 1R15: Operability Evaluations
CRs
ANO-C-2001-0018, ANO-C-2001-0678, ANO-C-2001-0698, ANO-C-2003-0360,
ANO-2-2004-0011, ANO-2-2004-0779, ANO-2-2004-1235, and ANO-C-2004-0483
Operating Procedures
1025.063, Control of Troubleshooting, Attachment 1, Revision 1
2104.037, Alternate AC Diesel Generator Operations, Revision 7
A-8
Attachment
2104.037, Alternate AC Diesel Generator Operations, Supplement 1, Revision 7
2304.102, Unit 2 High Linear and High Log Power Levels Excore Safety Channel C,
Revision 47
2304.102, Unit 2 High Linear and High Log Power Levels Excore Safety Channel C,
Supplement 2, Revision 47
Work Order Packages
00048303 01, 50284683 01, 50685110 01, and 50973125 01
Section 1R16: Operator Workarounds
CRs
ANO-1-2002-1853, ANO-1-2004-1817, ANO-1-2004-1832, ANO-1-2004-1974,
ANO-2-2004-1061, ANO-2-2004-1118, ANO-2-2004-1120, ANO-2-2004-1388,
ANO-2-2004-1558, and ANO-2-2004-1624
Operating Procedures
1104.004, Decay Heat Removal Operating Procedure, Revision 71
2104.039, HPSI System Operation, Revision 42
Section 1R19: Postmaintenance Testing
CRs
ANO-2-2004-0780
Operating Procedures
2304.134, Unit 2 EDG 2K4A Instrumentation Calibration, Sections 1 through 7, 8.10.2, and 9,
Revision 11
Work Order Packages
00042838 02, 50243449 01, 50571411 01, 50965925 01, 50965964 01, 50966657 01,
50966693 01, 50966736 01, 50966740 01, 50966830 01, 50966878 01, 50971621 01,
50972991 01, 50972992 01, and 50973104 01
Section 1R22: Surveillance Testing
CRs
ANO-1-2004-0645, ANO-1-2004-0989, ANO-2-2004-1187, ANO-2-2004-1186, and
ANO-2-2004-1200
A-9
Attachment
Engineering Calculation
ANO-2003-0618-000 and ANO-2003-0644-000
Operating Procedures
1304.181, Unit 1 RCS Radiation Leak Detection System Quarterly Test, Revision 8
2104.029, Service Water System Operations, Revision 54
2104.037, Alternate AC Diesel Generator Operations, Revision 6
2104.040, LPSI System Operations, Revision 35
2416.046, Unit 2 (2Y11, 2Y13, 2Y1113, 2Y22, 2Y24, and 2Y2224) Inverter Inspection, Test
and Maintenance Instructions, Revision 3
Work Order Packages
00035555 01, 00036437 01, 00038659 01, 50278828 01, 50336059 01, 50573018 01,
50747792 01, 50972347 01, and 50973055 01
Section 1R23: Temporary Plant Modifications
CRs
ANO-2-2004-0065, ANO-2-2004-0253, ANO-2-2004-0406, ANO-2-2004-0420,
ANO-2-2004-0446, ANO-2-2004-0472, ANO-2-2004-0671, ANO-2-2004-0694,
ANO-2-2004-0722, ANO-2-2004-0784, ANO-2-2004-1120, ANO-2-2004-1121,
and ANO-C-2004-0597
ER
ANO-2000-3275-003
Operating Procedures
1000.028, Control of Temporary Alterations, Revision 23
2104.039, HPSI System Operation, Revision 42
Work Orders
50276366 01 and 50276364 01
A-10
Attachment
Section 4OA2: Identification and Resolution of Problems
CRs
ANO-C-2004-0548
Operating Procedures
1015.047, Condition Reporting Operability and Immediate Reportability Determinations,
Revision 1
1203.025, Natural Emergencies, Revision 19
2203.008, Natural Emergencies, Revision 9
4OA3: Event Followup
CRs
ANO-1-1998-0300, ANO-1-2004-0645, and ANO-1-2004-0989
Operating Procedures
1107.003, Inverter and 120V Vital AC Distribution, Revision 12
1203.021, Loss of Neutron Flux Indication, Revision 8
1502.004, Control of Unit 1 Refueling, Revision 34
Section 4OA7: Licensee-Identified Violations
CRs
ANO-1-1998-0358, ANO-1-2004-0645, and ANO-1-2004-1373
A-11
Attachment
LIST OF ACRONYMS
Arkansas Nuclear One
apparent violation
corrective action program
CFR
Code of Federal Regulations
CR
condition report
dpm
drops per minute
emergency feedwater
engineered safety features
LER
licensee event report
noncited violation
National Fire Protection Association
structure, system, or component
unresolved item