ML070450249
| ML070450249 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 02/14/2007 |
| From: | Clark J NRC/RGN-IV/DRP/RPB-E |
| To: | Forbes J Entergy Operations |
| References | |
| IR-06-005 | |
| Download: ML070450249 (44) | |
See also: IR 05000313/2006005
Text
February 14, 2007
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
05000313/2006005 AND 05000368/2006005
Dear Mr. Forbes:
On December 31, 2006, 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 January 17, 2007, and
again on February 8, 2007, 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.
The report documents five self-revealing findings of very low safety significance (Green). Three
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 findings as noncited violations consistent with
Section VI.A.1 of the NRC Enforcement Policy. 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 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
Entergy Operations, Inc. -2-
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/
Jeffrey A. Clark, Chief
Project Branch E
Division of Reactor Projects
Dockets: 50-313
50-368
Licenses: DPR-51
Enclosure:
NRC Inspection Report 05000313/2006005 and 05000368/2006005
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
General Manager Plant Operations
Entergy Operations, Inc.
Arkansas Nuclear One
1448 S. R. 333
Russellville, AR 72802
Director, Nuclear Safety Assurance
Entergy Operations, Inc.
Arkansas Nuclear One
1448 S. R. 333
Russellville, AR 72802
Entergy Operations, Inc. -3-
Manager, Licensing
Entergy Operations, Inc.
Arkansas Nuclear One
1448 S. R. 333
Russellville, AR 72802
Director, Nuclear Safety & Licensing
Entergy Operations, Inc.
1340 Echelon Parkway
Jackson, MS 39213-8298
Section Chief, Division of Health
Radiation Control Section
Arkansas Department of Health and
Human Services
4815 West Markham Street, Slot 30
Little Rock, AR 72205-3867
Section Chief, Division of Health
Emergency Management Section
Arkansas Department of Health and
Human Services
4815 West Markham Street, Slot 30
Little Rock, AR 72205-3867
Manager, Washington Nuclear Operations
ABB Combustion Engineering Nuclear
Power
12300 Twinbrook Parkway, Suite 330
Rockville, MD 20852
County Judge of Pope County
Pope County Courthouse
100 West Main Street
Russellville, AR 72801
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)
DRS Deputy Director (RJC1)
Senior Resident Inspector (RWD)
Branch Chief, DRP/E (ZKD)
Senior Project Engineer, DRP/E (VGG)
Team Leader, DRP/TSS (RLN1)
RITS Coordinator (MSH3)
D. Cullison, OEDO RIV Coordinator (DGC)
ROPreports
ANO Site Secretary (VLH)
SUNSI Review Completed: _JAC__ ADAMS: / Yes No Initials: __JAC____
/ Publicly Available G Non-Publicly Available G Sensitive / Non-Sensitive
R:\_REACTORS\_ANO\2006\AN2006-05RP-RWD.wpd
RIV:RI:DRP/E RI:DRP/E SRI:DRP/E C:DRS/OB
CHYoung JEJosey RWDeese ATGody
T-JAC T-JAC T-JAC /RA/
2/5/2007 2/5/2007 2/5/2007 2/4/2007
C:DRS/PSB C:DRS/EB1 C:DRS/EB2 C:DRP/E
MPShannon WBJones LJSmith JAClark
/RA/ /RA/ /RA/ /RA/
2/5/2007 2/1/2007 2/1/2007 2/14/2007
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets: 50-313, 50-368
Report: 05000313/2006005 and 05000368/2006005
Licensee: Entergy Operations, Inc.
Facility: Arkansas Nuclear One, Units 1 and 2
Location: Junction of Hwy. 64W and Hwy. 333 South
Russellville, Arkansas
Dates: September 24 through December 31, 2006
Inspectors: L. Carson II, Senior Health Physicist, Plant Support Branch
R. Deese, Senior Resident Inspector
J. Josey, Resident Inspector
J. Kirkland, Project Engineer
R. Lantz, Senior Emergency Preparedness Inspector
D. Livermore, Senior Project Engineer
C. Paulk, Senior Reactor Inspector
C. Young, Resident Inspector
Accompanying
Personnel: S. Makor, Reactor Inspector
Approved By: Jeffrey A. Clark, Chief, Project Branch E
Division of Reactor Projects
-1- Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R02 Evaluation of Changes, Tests, or Experiments . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1R07 Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
1R08 Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
1R11 Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
1R12 Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
1R13 Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 14
1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R17 Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R19 Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
1R20 Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
1EP4 Emergency Action Level and Emergency Plan Changes . . . . . . . . . . . . . . . . . 22
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
2OS1 Access Control To Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 23
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA1 PI Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
4OA3 Followup of Events and Notices of Enforcement Discretion . . . . . . . . . . . . . . 28
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-9
-2- Enclosure
SUMMARY OF FINDINGS
IR 05000313/2006005, 05000368/2006005; 09/24/2006 - 12/31/2006; Arkansas Nuclear One,
Units 1 and 2; Fire Protection, Operability Evaluations, Refueling and Outage Activities, Follow-
up of Events and Notices of Enforcement Discretion.
This report covered a 3-month period of inspection by resident and regional specialist
inspectors. Five Green findings, three of which were noncited violations 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 noncited violation of Unit 2 Technical
Specification 6.4.1.c, Fire Protection Program Implementation, was identified for
the failure of maintenance personnel to follow Procedure EN-DC-127, Control of
Hot Work and Ignition Sources, while performing hot work. Specifically, the
licensee failed to ensure that combustible material within 35 feet of the work area
was removed or protected. Consequently, torch cutting activities near the Unit 2
containment sump strainer caused a nearby plastic bag containing used
protective clothing to ignite. This issue was entered into the licensee's
corrective action program as Condition Reports ANO-2-2006-1565 and Condition
Report ANO-2-2006-1701. A number of additional examples of hot work
activities that involved inadequate implementation of applicable hot work control
procedures were also identified.
The finding is greater than minor because it is associated with the protection
against external factors attribute of the initiating events cornerstone, and it
directly affects the cornerstone objective to limit the likelihood of those events
that upset plant stability and challenge critical safety functions during shutdown
as well as power operations. Additionally, if left uncorrected, the practice of
conducting hot work in a manner that results in unintended combustion of nearby
materials would become a more significant safety concern in that it could result
in a fire in or near other risk important equipment. The finding is not suitable for
evaluation with the significance determination process neither the fire protection
significance determination process nor the shutdown operations significance
determination process address shutdown fire protection findings. However, the
finding is determined to be of very low safety significance by NRC managements
review because the finding occurred while the unit was already in a cold
shutdown condition, and the operability of equipment necessary to maintain safe
-3- Enclosure
shutdown was not challenged. The cause of the finding is related to the
crosscutting element of human performance associated with work practices
because the fire watch failed to use error prevention techniques like self
checking and peer checking which would have prevented the event
(Section 1R05).
- Green. A self-revealing noncited violation of Unit 2 Technical
Specification 6.4.1.a, Procedures, was identified when an operator failed to
close Valve 2DCH-11, resin sluice header drain valve, when securing from a
resin transfer as required by procedure. One week later, while aligning the plant
for alternate purification with Valve 2DCH-11 being out of position, an
unanticipated loss of approximately 230 gallons of reactor coolant system
inventory occurred. This issue was entered into the licensee's corrective action
program as Condition Report ANO-2-2006-1464.
The finding was determined to be more than minor because it affected the
configuration control attribute of the initiating events cornerstone objective to limit
the likelihood of those events that upset plant stability and challenge critical
safety functions during shutdown as well as power operations. Using the
shutdown operations significance determination process, the finding was
determined to have very low safety significance because the finding did not
result in a loss of 2 feet or more of reactor coolant system inventory and did not
result in a loss of reactor coolant system inventory while in reduced inventory.
The cause of the finding is related to the crosscutting element of human
performance associated with work practices because the operator failed to use
error prevention techniques like self checking and peer checking which would
have prevented the event (Section 1R20).
- Green. A self-revealing finding was identified associated with the licensees
practice of using a hammer to remove the main hook pin on the Unit 2 polar
crane. Specifically, the license failure to provide clear guidance and training
resulted in station personnel cold working by the main hook and load cell pins
and this practice resulted in both pins being deformed and not usable with
reactor vessel level lowered to just below reactor vessel flange level. As a result,
Unit 2 was exposed to an increased period of elevated likelihood of a loss of
decay heat removal while the unit remained in a lowered vessel level condition
for an additional unplanned 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br />. This issue was entered into the licensee's
corrective action program as Condition Report ANO-2-2006-1553.
The finding was determined to be more than minor because it affected the
equipment performance attribute of the initiating events cornerstone objective to
limit the likelihood of those events that upset plant stability and challenge critical
safety functions during shutdown as well as power operations. This finding was
determined to be a finding of very low safety significance using the shutdown
operations significance determination process because the event did not involve
a loss of shutdown control or a reduction in mitigation capability which would
have increased the frequency of occurrence of a loss of decay heat removal.
-4- Enclosure
The cause of this finding is related to the crosscutting element of human
performance associated with resources because the training of personnel and
procedural guidance available was adequate (Section 1R20).
- Green. A self-revealing finding was identified when the Unit 1 main feedwater
Pump A tripped, resulting in a plant run back to 40 percent reactor power. The
trip occurred due to electromagnetic interference from an air conditioning unit
recently installed on top of the main feedwater pump cabinet. This interference
caused an overspeed trip signal on the digital speed monitor for the main
feedwater pump turbine when no such actual condition occurred. This issue was
entered into the licensee's corrective action program as Condition
Report ANO-1-2006-1399.
The finding was determined to be more than minor because it affected the
design control attribute of the initiating events cornerstone objective to limit the
likelihood of those events that upset plant stability and challenge critical safety
functions during shutdown as well as power operations. Using Manual
Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the
finding is determined to have very low safety significance because the condition
only affected the initiating events cornerstone and did not contribute to both the
likelihood of a reactor trip and the likelihood that mitigation equipment or
functions will not be available. The finding had crosscutting aspects in the area
of problem identification and resolution associated with operating experience
because the licensees failure to implement and institutionalize OE through
changes to station processes and procedures (Section 4OA3).
Cornerstone: Mitigating Systems
- Green. A self-revealing noncited violation of ANO Unit 2 License
Condition 2.C.(3)(b), Fire Protection, was identified for failure of the licensee to
maintain the lube oil collection system for Reactor Coolant Pumps C and D in an
operable condition. Specifically, the licensee failed to perform a modification on
the motor installed on Reactor Coolant Pump C which resulted in the oil
collection tank and its associated overfill berm being filled with water from the
component cooling water system. This issue was entered into the licensee's
corrective action program as Condition Report ANO-2-2006-1407.
The finding was determined to be more than minor because it affected the
protection against external factors attribute of the mitigating systems cornerstone
objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. Using the fire
protection significance determination process, the finding is determined to have
very low safety significance because the condition constituted a low degradation
of a fire prevention and administrative controls feature (Section 1R15).
B. Licensee-Identified Violations
None.
-5- Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at 100 percent rated thermal power (RTP) and remained
there until November 9, 2006, when a trip of the Main Feedwater Pump A occurred due to a
malfunction associated with the electronic overspeed trip device. The trip resulted in an
automatic runback to 40 percent RTP. Unit 1 returned to 100 percent RTP on
November 10 and remained there for the remainder of the inspection period.
Unit 2 began the inspection period with the reactor shut down for Refueling Outage 2R18.
Following the refueling outage, the Unit 2 reactor achieved criticality on October 27 and main
generator output breakers were closed on October 28. Approximately 67 percent RTP was
achieved on October 30 when the unit performed a Technical Specification (TS) required
shutdown to hot standby in response to a fire in 480-volt Motor-Control Center 2B-53. Unit 2
was restarted, and main generator output breakers were closed on November 1. The unit
achieved 100 percent RTP on November 3 and remained there for the remainder of the
inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1 Readiness for Impending Adverse Weather Conditions
On November 30 the inspectors completed a review of the licensee's readiness for
impending adverse weather involving icy weather. The inspectors: (1) reviewed plant
procedures, the Updated Final Safety Analysis Reports (UFSAR), and TSs to ensure
that operator actions defined in adverse weather procedures maintained the readiness
of essential systems; (2) walked down portions of the below listed two systems to
ensure that adverse weather protection features (heat tracing, space heaters,
weatherized enclosures, temporary chillers) were sufficient to support operability,
including the ability to perform safe shutdown functions; (3) reviewed maintenance
records to determine that applicable surveillance requirements were current before the
anticipated ice storm developed; and (4) reviewed plant modifications, procedure
revisions, and operator work arounds to determine if recent facility changes challenged
plant operation.
C November 30, 2006, Units 1 and 2, offsite electrical distribution systems
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample.
-6- Enclosure
1R02 Evaluation of Changes, Tests, or Experiments (71111.02)
a. Inspection Scope
The inspectors reviewed the effectiveness of the licensees implementation of changes
to the facility structures, systems, and components (SSCs); risk-significant normal and
emergency operating procedures; test programs; and the UFSAR in accordance with
10 CFR 50.59, Changes, Tests, and Experiments. The inspectors reviewed the safety
evaluations performed by the licensee dealing with the Unit 2 pressurizer replacement.
The evaluations were reviewed to verify that licensee personnel had appropriately
considered the conditions under which the licensee may make changes to the facility or
procedures or conduct tests or experiments without prior NRC approval. Procedures,
evaluations, screenings, and applicability determinations reviewed are listed in the
attachment to this report.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment (71111.04)
.1 Partial Walkdown
The inspectors: (1) walked down portions of the two 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 walkdown to the licensees UFSAR and corrective action program (CAP) to ensure
problems were being identified and corrected.
- October 3, 2006, Unit 1, Emergency Diesel Generator (EDG) K-4A
- December 13, 2006, Unit 1, reactor building spray system Train A
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed two samples.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
.1 Quarterly Inspection
The inspectors walked down the six below listed plant areas to assess the material
condition of active and passive fire protection features and their operational lineup and
readiness. 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
-7- Enclosure
suppression systems to verify they remained functional and that access to manual
actuators was unobstructed; (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 that the
compensatory measures were commensurate with the significance of the deficiency;
and (7) reviewed the UFSAR to determine if the licensee identified and corrected fire
protection problems.
- September 25, 2006, Unit 2, Fire Zone 2032-K, containment building (south side)
- October 17, 2006, Unit 1, Fire Zone 98-J, EDG access corridor
- December 13, 2006, Unit 1, Fire Zones 4-EE, 12-EE, and 14-EE, Elevation 317
feet of the auxiliary building, west decay heat removal pump room
- December 26, 2006, Unit 2, Fire Zone 2040-JJ, access corridor; charging pump;
radwaste and boron management system area
- December 27, 2006, Unit 1, Fire Zone 67-U, lab and demineralizer access area
- December 27, 2006, Unit 1, Fire Zone 79-U, upper north piping penetration room
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six samples.
b. Findings
Introduction. A self-revealing, Green noncited violation of TS 6.4.1.c was identified for
the licensees failure to adequately implement their procedure for the control of hot work
and ignition sources while performing hot work activities.
Description. On September 25, 2006, hot work activities were being performed on the
Unit 2 containment sump strainer. A plastic bag was being utilized at a nearby step-off
pad at the high contamination area boundary as a receptacle for used protective
clothing. While torch cutting on the west containment sump strainer door was in
progress, sparks from the activity caused the plastic bag to ignite. The inspectors
identified the fire to the firewatch, who was in the vicinity. The bag was extinguished by
smothering soon thereafter by the workers that were involved in the hot work activity.
Procedure EN-DC-127, Control of Hot Work and Ignition Sources, Revision 2, requires
that combustible material within 35 feet of the work area that could become ignited from
the hot work shall be removed or protected. Procedure EN-DC-127, Attachment 9.1,
Hot Work Permit, was issued for this activity and showed that this requirement to be
checked off by the hot work supervisor as being completed. The inspectors noted that
the bag was within 35 feet of the work area and had not been removed.
-8- Enclosure
Corrective actions that were taken by the licensee in response to this event to prevent
recurrence included: moving the step-off pad farther away from the work area, clearing
the area near the door of unnecessary equipment and materials, coaching the firewatch
and his supervisor concerning the responsibility of the firewatch and how to deal with
distractions, discussing alternatives to more effectively contain sparks from the cutting
operation, discussing the event with craft personnel, and conducting more frequent area
inspections.
A number of additional deficiencies were identified through a review of recent licensee
performance in the conduct of related hot work activities. Section 4OA2 of this
enclosure contains some details of other instances that occurred during the Unit 2
Refueling Outage 2R18. Also, three examples involving circumstances similar to the
subject of this finding occurred during the prior refueling outages for each of the two
units. On March 25, 2005, fallen welding slag caused the smoldering of debris below
Containment Cooler D inside the Unit 2 containment building. On September 29 torch
cutting resulted in falling hot metal and slag that caused combustible materials in the
work area to catch on fire. On October 14 three small fires of trash bags containing
combustible materials in the Unit 1 turbine building basement were caused by hot work
activities that were being performed on the levels above. There was no firewatch posted
on the basement level.
Each of these instances was entered into the licensees CAP. These occurrences
represent instances of inadequate implementation of applicable hot work control
procedures. The inspectors concluded that the recent increase in the number of related
findings when compared to past occurrences represented a trend which, if left
uncorrected, could become a more significant safety concern in that it could result in a
fire in or near risk important equipment.
Analysis. The performance deficiency associated with this finding involved the failure of
maintenance personnel to adequately implement the licensees procedure for control of
hot work and ignition sources. The finding is greater than minor because it is
associated with the protection against external factors attribute of the initiating events
cornerstone, and affects the cornerstone objective to limit the likelihood of those events
that upset plant stability and challenge critical safety functions during shutdown as well
as power operations. Additionally, if left uncorrected, the practice of conducting hot
work in a manner that results in unintended combustion of nearby materials would
become a more significant safety concern in that it could result in a fire in or near risk
important equipment. Manual Chapter (MC) 0609, Significance Determination
Process, Appendix F, Fire Protection Significance Determination Process, does not
address the potential risk significance of shutdown fire protection findings. Additionally,
MC 0609, Appendix G, Shutdown Operations Significance Determination Process,
does not address fire protection findings. Thus, the finding is not suitable for
significance determination process evaluation, but has been reviewed by NRC
management and is determined to be of very low safety significance because the finding
occurred while the unit was already in a cold shutdown condition; and the operability of
equipment necessary to maintain safe shutdown was not challenged. The cause of the
finding is related to the crosscutting element of human performance in that maintenance
personnel failed to follow procedures.
-9- Enclosure
Enforcement. Unit 2 TS 6.4, Procedures, requires that written procedures be
established, implemented, and maintained covering fire protection program
implementation. Procedure EN-DC-127, Control of Hot Work and Ignition Sources, is
one of those procedures and requires that combustible material within 35 feet of the
work area that could become ignited from the hot work shall be removed or protected.
Contrary to this, on September 25, 2006, maintenance personnel failed to remove or
protect combustible material within 35 feet of the work area. Because the finding is of
very low safety significance and has been entered into the licensees CAP as Condition
Reports (CRs) ANO-2-2006-1565 and CR ANO-2-2006-1701, this violation is being
treated as an NCV consistent with Section VIA of the Enforcement Policy:
NCV 05000368/2006005-01, Fire During Hot Work Activities on the Containment Sump
Strainer.
1R07 Heat Sink Performance (71111.07)
a. Inspection Scope
The inspectors reviewed licensee programs, verified performance against industry
standards, and reviewed critical operating parameters and maintenance records for the
Unit 1 EDG A cooling water heat exchanger. The inspectors verified that:
(1) performance tests were satisfactorily conducted for heat enchanters/heat sinks and
reviewed for problems or errors; (2) the licensee utilized the periodic maintenance
method outlined in EPRI NP-7552, Heat Exchanger Performance Monitoring
Guidelines; (3) the licensee properly utilized befalling controls; (4) the licensees heat
exchanger inspections adequately assessed the state of cleanliness of their tubes; and
(5) the heat exchanger was correctly categorized under the Maintenance Rule.
- September 5, 2006, Unit 1 EDG A cooling water heat exchanger
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R08 Inservice Inspection Activities (71111.08)
Inspection Procedure 71111.08 requires four samples size as identified in
Sections 02.01, 02.02, 02.03, and 02.04.
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a. Inspection Scope
.1 Performance of Nondestructive Examination (NDE) Activities Other than Steam
Generator Tube Inspections, Pressurized Water Reactor (PWR) Vessel Upper Head
Penetration Inspections, Boric Acid Corrosion Control
The inspection procedure requires the review of NDE activities consisting of two or three
different types (i.e., volumetric, surface, or visual). The inspectors observed the
performance of three ultrasonic examinations (volumetric) (one on a section of service
water piping for wall thickness and two on field welds in the pressurizer spray line). The
inspectors also reviewed the radiographic examinations (volumetric) of the two spray
line welds. (The welds are identified in the attachment to this report.)
For each of the observed NDE activities, the inspectors verified that the examinations
were performed in accordance with the specific site procedures and the applicable
American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME
Code) requirements.
During review of each examination, the inspectors verified that appropriate
NDE procedures were used, examinations and conditions were as specified in the
procedure, and test instrumentation or equipment was properly calibrated and within the
allowable calibration period. The inspectors also verified the NDE certifications of the
personnel who performed the above volumetric examinations. Finally, the inspectors
observed that indications identified during the radiographic examinations were
dispositioned in accordance with the ASME Code-qualified NDE procedures used to
perform the examinations.
The inspection procedure requires review of one or two examinations with recordable
indications that were accepted for continued service to ensure that the disposition was
made in accordance with the ASME Code. The inspectors were informed that no
indications exceeding ASME Code allowables were known to be in service.
The inspection procedure further requires verification of one to three welds on Class 1
or 2 pressure boundary piping to ensure that the welding process and welding
examinations were performed in accordance with the ASME Code. The inspectors
observed welding performed on a safety injection system valve in the prefabrication
shop. The inspectors verified that the welding was performed in accordance with
Sections IX and XI of the ASME Code. This included review of welding material issue
slips to establish that the appropriate welding materials had been used and verification
that the welding procedure specification (WPS E-P8-T-A8,Ar, Manual Gas Tungsten
Arc Welding (GTAW) of P-No. 8 Stainless Steels, Revision 0) had been properly
qualified.
The inspectors completed the one sample required by Section 02.01.
.2 Reactor Vessel Upper Head Penetration Inspection Activities
The inspection requirements for this section parallel the inspection requirement steps in
Section 02.01. The inspectors observed the NDEs on nine reactor vessel upper head
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penetrations. There were eight control element drive mechanism penetrations (Nos. 12,
21, 58, 59, 60, 61, 72, and 79) and one incore instrumentation penetration (No. 82).
The inspectors verified that the nondestructive activities were performed in accordance
with the requirements of NRC Order EA-03-009. The NDEs performed during the NRC
inspection did not reveal any defects or indications.
The inspectors completed the one sample required by Section 02.02.
.3 Boric Acid Corrosion Control Inspection Activities (PWRs)
The inspectors evaluated the implementation of the licensees boric acid corrosion
control program for monitoring degradation of those systems that could be deleteriously
affected by boric acid corrosion. The inspection procedure requires review of a sample
of boric acid corrosion control walkdown visual examination activities through either
direct observation or record review. The inspectors reviewed the documentation
associated with the licensees boric acid corrosion control walkdown. Additionally, the
inspectors performed independent observations of piping containing boric acid during
walkdowns of the containment building and the auxiliary building.
The inspection procedure requires verification that visual inspections emphasize
locations where boric acid leaks can cause degradation of safety significant
components. The inspectors verified through direct observation and program/record
review that the licensees boric acid corrosion control inspection efforts are directed
towards locations where boric acid leaks can cause degradation of safety-related
components.
The inspection procedure requires both a review of one to three engineering evaluations
performed for boric acid leaks found on reactor coolant system (RCS) piping and
components and one to three corrective actions performed for identified boric acid
leaks. The licensee had identified a boric acid leak on the containment spray header
during an inspection for materials that could come loose and clog the sump screens
during a loss-of-coolant accident or steam line rupture inside containment. The
inspectors reviewed the licensees analysis of the condition to evaluate the assessment
of the condition and proposed corrective actions.
The inspectors completed the one sample required by Section 02.03.
.4 Steam Generator Tube Inspection Activities
There were no steam generator tube inspections performed during this outage. The
inspectors reviewed Evaluation ER-2005-0469-001, Operational Assessment of ANO-2
Steam Generator Tubing for Cycles 18-20, dated August 31, 2006. The evaluation
concluded that no tube examinations were required to be performed during
Cycles 18-20. The inspectors noted that the basis was the condition of the tubes from
the previous inspections that were performed after the steam generators were replaced.
This sample was not completed because there was no activity to observe.
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.5 Identification and Resolution of Problems
The inspection procedure requires review of a sample of problems associated with
inservice inspections documented by the licensee in the CAP for appropriateness of the
corrective actions. The inspectors reviewed three CRs, which dealt with inservice
inspection and welding activities. From this review, the inspectors concluded that the
licensee has an appropriate threshold for entering issues into the CAP and has
procedures that direct a root cause evaluation when necessary. The licensee also had
an effective program for applying industry operating experience.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11)
a. Inspection Scope
On December 14, 2006, the inspectors observed testing and training of Unit 1 senior
reactor operators and reactor operators to identify deficiencies and discrepancies in the
training, to assess operator performance, and to assess the evaluator's critique. The
training was a simulator training scenario.
Documents reviewed by the inspectors included:
- ANO Unit 1 Dynamic Exam Scenario SES-1-008, Revision 5
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors reviewed the two below listed maintenance activities to: (1) verify the
appropriate handling of SSCs performance or condition problems; (2) verify the
appropriate handling of degraded SSC functional performance; (3) evaluate the role of
work practices and common cause problems; and (4) evaluate the handling of SSC
issues reviewed under the requirements of the Maintenance Rule, 10 CFR Part 50,
Appendix B, and TSs.
- November 28, 2006, Unit 1, turbine building ventilation
- December 5, 2006, Unit 2, 480-volt electrical distribution
Documents reviewed by the inspectors are listed in the attachment.
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The inspectors completed two samples.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
.1 Risk Assessment and Management of Risk
a. Inspection Scope
Risk Assessment and Management of Risk
The inspectors reviewed the six below listed assessment activities to verify:
(1) 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 completeness of the information
considered in the risk assessment; (3) that 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) that the licensee identified and
corrected problems related to maintenance risk assessments.
- September 19 through October 27, 2006, Unit 2, pressurizer replacement
- September 19 through October 27, 2006, Unit 2, containment sump modification
- November 13-17, 2006, Unit 1, planned maintenance for the week
- November 27 through December 1, 2006, Unit 1, planned maintenance for the
week
- December 4-8, 2006, Unit 2, planned maintenance for the week
- December 11-15, 2006, Unit 1, planned maintenance for the week
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six samples.
b. Findings
No findings of significance were identified.
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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 UFSAR 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 TSs; (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.
- September 22, 2006, Unit 2, reactor coolant pump (RCP) oil collection system
- October 3, 2006, Unit 2, Electrical Bus 2B-5
- October 28, 2006, Unit 2, containment spray header
- December 19, 2006, Unit 2, containment sump
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed four samples.
b. Findings
Introduction. A Green self-revealing noncited violation of the Unit 2 license condition for
fire protection was identified for failure of the licensee to maintain the RCP oil collection
system for RCPs C and D in an operable condition. Specifically, the licensee failed to
perform a modification on the motor installed on RCP C, which resulted in the oil
collection tank and its associated overfill berm filling up and overflowing with water from
the component cooling water (CCW) system.
Description. On September 20, 2006, while the licensee was conducting a hot
shutdown walkdown in containment during the start of Refueling Outage 2R18, the
licensee discovered that the RCP oil collection system drain tank for RCPs C and D,
(2T-110) and its associated overfill berm were filled and overflowing with water. The
licensee determined that the drain tank and associated berm were inoperable because
the licensee could not perform their intended function of providing a collection and
holding point for possible oil leakage from RCPs C and D.
The licensee obtained a sample of the water and determined that it was from the CCW
system. Based on this, the licensee then identified and performed inspections of all
interface points of the CCW system with the RCP oil collection system. During this
inspection, two leakage points were identified: the outlet flange of lube oil
Cooler 2E-25D, and the interface of the threaded supply and return piping nipples for
the lower bearing oil cooler on RCP C. The leakage from the lower bearing oil cooler
was determined to be the source that was leaking into the oil collection system through
the drip pans below the motor.
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During their investigation to determine the cause of this failure, the licensee identified
the cause of the leakage to be fatigue at the root diameter of the threaded schedule
40 pipe nipple. They also determined that this type of failure had previously occurred on
the motor installed on RCP B in December of 1995. This failure was documented in
CR ANO-2-1995-0555 and was also determined to be due to fatigue at the root diameter
of the threaded schedule 40 pipe nipple. The licensee determined, during their review
of the RCP B failure of December 1995, that Modification PEAR 9-0330, Revision 1, had
been developed and implemented to replace the schedule 40 threaded pipe nipple on
the RCPs with schedule 80 threaded pipe nipples. This modification was performed on
the motors of all installed RCPs but not the Unit 2 spare motor. Completion of the
modification on the spare RCP motor was to be accomplished during motor
refurbishment; however, the modification was never performed. In 2005 during
Refueling Outage 2R17, the spare RCP motor was installed as the RPC C motor without
the modification.
In reviewing this issue, the inspectors noted that the licensee had trend data for the
volume of oil in RCPs C and D which indicated that oil volume in RCPs C and D had
gone down over the cycle. The inspectors determined through interviews that this oil
was not contained in the oil collection system or the overflow berm as per design but
had most likely overflowed the berm and gone to the containment sump via the floor
drain system. During the operating cycle, the sump had been pumped to the auxiliary
building for processing.
Analysis. The inspectors determined that the failure to maintain the oil collection system
drain tank for RCPs C and D in an operable condition was a performance deficiency.
The finding was determined to be more than minor because it affected the protection
against external factors attribute of the mitigating systems cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Using MC 0609, Significance
Determination Process, Phase 1 Worksheet, the finding is assumed to degrade fire
protection defense-in-depth strategies involving barriers; therefore, the significance of
the finding is determined by using Appendix F, Fire Protection Significance
Determination Process, of MC 0609. Using the Phase 1 Worksheet of Appendix F, the
inspectors assumed the condition represented a low degradation of the fire prevention
and administrative controls category since the oil collection would have kept oil from
contacting hot surfaces in the containment building. Additionally, the inspectors
assumed that no intervening combustibles were present between the overflow path and
adjacent fire areas and that the containment sump, to which the floor drains installed in
the area of the berm transported any oil that overflowed, lacked a significant ignition
source.
Enforcement. ANO Unit 2 License Condition 2.C.(3)(b), Fire Protection, states, in part,
that the licensee shall implement and maintain all provisions of the approved fire
protection program. ANO Unit 1 and Unit 2 - Fire Hazards Analysis, Revision 9, is part
of the ANO Unit 2 fire protection program. Section 6.4.5, Fire Barriers, Seals, and
Penetrations, of the Fire Hazards Analysis states, in part, that the fire barrier system at
ANO has been designed to ensure that fires will be confined or adequately retarded
from spreading to adjacent portions of the facility. Contrary to this, the filling to overflow
of the oil collection system tank and overflow berm with water from the CCW system
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during Operating Cycle 18 prevented a potential RCP oil fire in the containment
basement from being confined per the fire protection program. Because the finding is of
very low safety significance and has been entered into the licensees CAP as
CR ANO-2-2006-1407, this violation is being treated as an NCV consistent with
Section VIA of the Enforcement Policy: NCV 05000368/2006005-02, Failure to Perform
Modification Resulted in an Inoperable RCP Oil Collection System.
1R17 Permanent Plant Modifications (71111.17)
.1 Annual Review
The inspectors reviewed key affected parameters associated with energy needs,
materials/replacement components, timing, heat removal, control signals, equipment
protection from hazards, operations, flowpaths, pressure boundary, ventilation
boundary, structural, process medium properties, licensing basis, and failure modes for
the modification listed below. The inspectors verified that: (1) modification preparation,
staging, and implementation does not impair emergency/abnormal operating procedure
actions, key safety functions, or operator response to loss of key safety functions;
(2) postmodification testing maintained the plant in a safe configuration during testing by
verifying that unintended system interactions will not occur, SSC performance
characteristics still meet the design basis, the appropriateness of modification design
assumptions, and the modification test acceptance criteria has been met; and (3) the
licensee has identified and implemented appropriate corrective actions associated with
permanent plant modifications.
- September 19 through October 26, 2006, Unit 2, pressurizer replacement
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
The inspectors selected the six 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 UFSAR to determine if the
licensee identified and corrected problems related to postmaintenance testing.
- October 17, 2006, Unit 1, Emergency Feedwater Pump P-7A
- October 22, 2006, Unit 2, pressurizer heater capacity
- October 24, 2006, Unit 2, replacement pressurizer relief valve monitor test
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- October 25, 2006, Unit 2, containment spray header repairs
- October 27, 2006, Unit 2, replacement pressurizer leakage
- November 1, 2006, Unit 2, containment building personnel hatch leakage rate
testing
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six samples.
b. Findings
No findings of significance were identified.
1R20 Refueling and Outage Activities (71111.20)
1. Unit 2 Forced Outage Caused by Fire in Motor Control Center 2B-53
a. Inspection Scope
The inspectors reviewed the following risk significant outage activities to verify defense
in depth commensurate with the outage risk control plan and compliance with the TSs:
(1) the risk control plan, (2) tagging/clearance activities, (3) heatup and cooldown
activities, and (4) restart activities.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
2. Refueling and Pressurizer Replacement Outage 2R18
a. Inspection Scope
The inspectors reviewed the following risk significant refueling items or outage activities
to verify defense in depth commensurate with the outage risk control plan, compliance
with the TSs, and adherence to commitments in response to Generic Letter 88-17, Loss
of Decay Heat Removal: (1) the risk control plan, (2) tagging/clearance activities,
(3) RCS instrumentation, (4) electrical power, (5) decay heat removal, (6) spent fuel pool
cooling, (7) inventory control, (8) reactivity control, (9) containment closure, (10) reduced
inventory conditions, (11) refueling activities, (12) heatup and cooldown activities,
(13) restart activities, and (14) licensee identification and implementation of appropriate
corrective actions associated with refueling and outage activities. The inspectors
containment inspections included observation of the containment sump for damage and
debris, supports, braces, and snubbers for evidence of excessive stress, water hammer,
or aging.
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The inspectors completed one sample.
b. Findings
.1 Inadvertent RCS Draining While in Mode 5
Introduction. A Green self-revealing noncited violation of the licensees TS requirement
for procedures was identified when an operator failed to close a resin sluice header
drain valve as required by procedure. Later, while operators were aligning the unit for
alternate reactor coolant purification, a loss of approximately 230 gallons of RCS
inventory occurred.
Description. On September 14, 2006, operations personnel performed
Procedure OP-2104.019, Clean Resin Transfer, to add clean resin to Purification Ion
Exchanger 2T-36B. During this procedure, Valve 2DCH-11 was opened as part of the
system lineup. Subsequently, when the evolution was completed and the plant lineup
was being restored, station personnel failed to properly perform Step 22.2 of the
procedure leaving Valve 2DCH-11 in the open position.
Subsequently, on September 21, 2006, with Unit 2 in Mode 5, the licensee was in the
process of aligning alternate purification in accordance with Procedure OP-2104.004,
Shutdown Cooling System, Attachment J, Alternate Purification. When Step 2.11 of
this procedure was performed, the control room operators noted that pressurizer level
began to lower. The evolution was stopped and the lineup was secured. At this point,
pressurizer level stopped lowering. Station personnel performed a system walkdown
and discovered that Valve 2DCH-11 was in the open position. Operations personnel
determined that approximately 230 gallons were drained from the RCS through the open
valve.
During their review, the inspectors noted that Procedure OP-2104.004, Attachment J,
directed personnel to prepare a caution tag for components to prevent the loss of RCS
inventory. However, the procedure contained a note that preceded Step 1.11 which
directed the caution tag be hung on the room door instead of Valve 2DCH-11 and two
other valves. This tag stated that, since the valves were normally closed, any
misalignment would be detected by system abnormalities. The inspectors determined
that this note contributed to Valve 2DCH-11 not being discovered out of position prior to
initiating alternate purification since the licensee did not perform a valve lineup
verification.
Analysis. The failure of station personnel to manipulate Valve 2DCH-11 in accordance
with station procedure was determined to be a performance deficiency. The finding was
determined to be more than minor because it affected the configuration control attribute
of the initiating events cornerstone objective to limit the likelihood of those events that
upset plant stability and challenge critical safety functions during shutdown as well as
power operations. The inspectors used MC 0609, Significance Determination Process,
Appendix G, Shutdown Operations Significance Determination Process, and assumed
that the administrative controls implemented to avoid operations that could lead to
perturbations in RCS level control attribute was affected. The finding was determined to
have very low safety significance because the finding did not result in a loss of 2 feet or
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more of RCS inventory and did not result in a loss of RCS inventory while the unit was in
reduced inventory. The cause of the finding is related to the crosscutting aspect of
human performance associated with work practices because the operator failed to use
error prevention techniques like self checking and peer checking which would have
prevented the event.
Enforcement. Unit 2 TS, Section 6.4.1.a, Procedures, requires, in part, that written
procedures shall be established, implemented, and maintained covering the applicable
procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A,
February 1978. Procedure OP-2104.019, Clean Resin Transfer, is a procedure
required by Regulatory Guide 1.33. Contrary to the above, on September 14, 2006, the
licensee failed to fully implement Procedure OP-2104.019, Clean Resin Transfer,
when the licensee failed to close Valve 2DCH-11. Because this finding is of very low
safety significance and has been entered into the CAP as CR ANO-2-2006-1464, this
violation is being treated as an NCV, consistent with Section VIA of the NRC
Enforcement Policy: NCV 05000368/2006005-03, Inadvertent RCS Draining While in
Mode 5.
.2 Unplanned Increase in Time with Reactor Vessel Water Level at Flange Level
Introduction. A Green self-revealing finding was identified associated with the licensees
use of a hammer to remove and reinstall both the main hook pin and the load cell pin on
the Unit 2 polar crane. Unit 2 was maintained in a condition with reactor vessel water
level being maintained just below the reactor vessel flange for an additional unplanned
27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br /> when the pins could not be used due to deformation by the hammer.
Description. On September 24, 2006, station personnel were preparing the Unit 2 polar
crane for the reactor vessel closure head removal. This involved removing the normally
installed main hook, installing a load cell, and then reinstalling the main hook. During
performance of Procedure OP-2504.005, Reactor Vessel Closure Head Removal,
Revision 12, Step 7.22, licensee personnel were unable to easily remove the polar crane
main hook pin. After the pin was removed, it was examined by the licensee and
discovered to be mushroomed at one end. When the licensee inspected the pin used to
secure the load cell into place, it was discovered to be in the same condition. The
licensee determined this condition to be caused by the practice of using a hammer, as
necessary, to both remove and install the pins during previous refueling outages.
The inspectors noted that the licensee did not have a formal procedure that controlled
the removal and installation of the pins, and that station personnel were controlling this
evolution as a skill-of-the-craft process. A review of the applicable procedures by the
inspectors revealed that Procedure OP-2504.005, Step 7.22, Reactor Vessel Closure
Head Removal, simply states, Verify that the load cell is attached to the polar crane.
The inspectors also determined that the use of hammers was a common practice being
used to remove and reinstall the pins on the polar crane, and there was no existing
evaluation for the effects of this on the integrity of the pins. The inspectors determined
that the lack of adequate procedural direction and the practice of hammering the pins in
and out directly contributed to the deformation of the pins. Finally, the inspectors were
informed by licensee personnel that the practice of using hammers to remove the pins
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was not part of the formal training received by maintenance personnel; however, in at
least one instance, a discussion between instructors and maintenance personnel
outside the formal lesson plan had occurred describing the practice of using hammers
as being acceptable.
Analysis. The inspectors determined that the licensees failure to provide clear guidance
and training on how to remove the main hook and load cell pins without causing damage
was a performance deficiency. The finding was determined to be more than minor
because it affected the equipment performance attribute of the initiating events
cornerstone objective to limit the likelihood of those events that upset plant stability and
challenge critical safety functions during shutdown as well as power operations. The
inspectors evaluated the finding using MC 0609, Significance Determination Process,
Appendix G, Shutdown Operations Significance Determination Process. The
inspectors determined that the finding was not a loss of shutdown control as defined by
MC 0609, Appendix G, Table 1, and then evaluated the issue using Checklist 3 of
MC 0609, Appendix G, Attachment 1. The inspectors determined that a quantitative
analysis was not required because the event did not represent a reduction in mitigation
capability which would have increased the frequency of occurrence of a loss of decay
heat removal. Therefore, the finding was determined to have very low safety
significance. The cause of the finding is related to the crosscutting element of human
performance associated with resources because the training of personnel and
procedural guidance available was adequate.
Enforcement. While a performance deficiency was identified, there were no violations of
NRC requirements identified during the review of this issue. The licensee has entered
this issue into the CAP as CR ANO-2-2006-1553: Finding (FIN)05000368/2006005-04,
Unplanned Increase in Time with Reactor Vessel Water Level at Flange Level.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure that
the four 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) procedures; (6) jumper/lifted lead
controls; (7) test data; (8) testing frequency and method demonstrated TS operability;
(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of ASME
Code requirements; (12) updating of performance indicator (PI) 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) annunciators and
alarms setpoints. The inspectors also verified that the licensee identified and
implemented any needed corrective actions associated with the surveillance testing.
- August 4, 2006, Unit 1, makeup system Valve MU-36A local leak rate test
- October 5, 2006, Unit 2, main steam safety valve lifts (inservice test)
- October 15, 2006, Unit 2, Valve 2SV-8271-2 local leak rate test
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- October 23, 2006, Unit 2, Containment Cooler A
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed four samples.
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
a. Inspection Scope
The inspector performed an in-office review of Revision 037-05-0 to Emergency Plan
Implementing Procedure OP-1903.010, Emergency Action Level Classification. The
revision was submitted in October 2006. The revision corrected emergency plan
guidance for transient event classification and notification practices at Arkansas Nuclear
One and was a corrective action for the NCV 05000313,368/2006003-02, Failure to
Meet Immediate Notification Requirements during Transient Events.
The revision was compared to the previous revision, to the criteria of NUREG-0654,
Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and
Preparedness in Support of Nuclear Power Plants, Revision 1; and NEI 99-01,
Methodology for Development of Emergency Action Levels, Revision 2; and to the
standards in 10 CFR 50.47(b) to determine if the revision was adequately conducted
following the requirements of 10 CFR 50.54(q). This review was not documented in a
safety evaluation report and did not constitute approval of licensee changes, therefore,
the revision is subject to future inspection.
The inspector completed one sample during the inspection.
b. Findings
No findings of significance were identified.
1EP6 Drill Evaluation (71114.06)
a. Inspection Scope
For the one below listed simulator-based training evolutions contributing to drill/exercise
performance, emergency response organization, and PIs, the inspectors: (1) observed
the training evolution to identify any weaknesses and deficiencies in classification,
notification, and protective action requirements (PAR) development activities;
(2) compared the identified weaknesses and deficiencies against licensee identified
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findings to determine whether the licensee is properly identifying failures;
and (3) determined whether licensee performance is in accordance with the guidance of
the NEI 99-02, Voluntary Submission of Performance Indicator Data, acceptance
criteria.
- December 7, 2006, Unit 2, simulator-based exercise requiring notice of unusual
event and alert declarations
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
2. RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control To Radiologically Significant Areas (71121.01)
a. Inspection Scope
This area was inspected to assess the licensees performance in implementing physical
and administrative controls for airborne radioactivity areas, radiation areas, high
radiation areas, and worker adherence to these controls. The inspectors used the
requirements in 10 CFR Part 20, the TSs, and the licensees procedures required by
TSs as criteria for determining compliance. During the inspection, the inspectors
interviewed the radiation protection manager, radiation protection supervisors, and
radiation workers. The inspectors performed independent radiation dose rate
measurements and reviewed the following items:
- PI events and associated documentation packages reported by the licensee in
the occupational radiation safety cornerstone
- Controls (surveys, posting, and barricades) of radiation, high radiation, or
airborne radioactivity areas
- Radiation work permits, procedures, engineering controls, and air sampler
locations
- Conformity of electronic personal dosimeter alarm set points with survey
indications and plant policy; workers knowledge of required actions when their
electronic personnel dosimeter noticeably malfunctions or alarms
- Barrier integrity and performance of engineering controls in airborne radioactivity
areas
- Adequacy of the licensees internal dose assessment for any actual internal
exposure greater than 50 millirem committed effective dose equivalent
-23- Enclosure
- Physical and programmatic controls for highly activated or contaminated
materials (nonfuel) stored within spent fuel and other storage pools
- Self-assessments related to the access control program since the last
inspection; there were no audits, licensee event reports, and special reports
documented.
- Corrective action documents related to access controls
- Licensee actions in cases of repetitive deficiencies or significant individual
deficiencies
- Radiation work permit briefings and worker instructions
- Adequacy of radiological controls such as, required surveys, radiation protection
job coverage, and contamination controls during job performance
- Dosimetry placement in high radiation work areas with significant dose rate
gradients
- Changes in licensee procedural controls of high dose rate - high radiation areas
and very high radiation areas
- Controls for special areas that have the potential to become very high radiation
areas during certain plant operations
- Posting and locking of entrances to all accessible high dose rate - high radiation
areas and very high radiation areas
- Radiation worker and radiation protection technician performance with respect to
radiation protection work requirements
The inspectors completed 21 of the required 21 samples.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA1 PI Verification (71151)
.1 Occupational Radiation Safety Cornerstone
a. Inspection Scope
The inspectors reviewed licensee documents from April through September 2006. The
review included corrective action documentation that identified occurrences in locked high
radiation areas (as defined in the licensees TSs, very high radiation areas (as defined in
10 CFR 20.1003), and unplanned personnel exposures (as defined in NEI 99-02).
Additional records reviewed included as low as reasonably achievable records and whole
body counts of selected individual exposures. The inspectors interviewed licensee
-24- Enclosure
personnel that were accountable for collecting and evaluating the PI data. In addition, the
inspector toured plant areas to verify that high radiation, locked high radiation, and very
high radiation areas were properly controlled. PI definitions and guidance contained in
NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 4, were used to verify
the basis in reporting for each data element.
- Occupational Exposure Control Effectiveness
The inspectors completed the required sample (1) in this cornerstone
b. Findings
No findings of significance were identified.
.2 Public Radiation Safety Cornerstone
a. Inspection Scope
The inspectors reviewed licensee documents from April through September 2006.
Licensee records reviewed included corrective action documentation that identified
occurrences for liquid or gaseous effluent releases that exceeded PI thresholds and those
reported to the NRC. The inspectors interviewed licensee personnel that were
accountable for collecting and evaluating the PI data. PI definitions and guidance
contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 4, were
used to verify the basis in reporting for each data element.
- Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent
Occurrences
The inspectors completed the required sample (1) in this cornerstone
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
.1 Routine Review of Identification and Resolution of Problems
The inspectors performed a daily screening of items entered into the licensees CAP.
This assessment was accomplished by reviewing CRs and attending corrective action
review and work control meetings. The inspectors: (1) verified that equipment, human
performance, and program issues were being identified by the licensee at an appropriate
threshold and that the issues were entered into the CAP; (2) verified that corrective
actions were commensurate with the significance of the issue; and (3) identified conditions
that might warrant additional follow-up through other baseline inspection procedures.
.2 Selected Issue Follow-up Inspection
In addition to the routine review, the inspectors selected the two below listed issues for a
more in-depth review. The inspectors considered the following during the review of the
licensees actions: (1) complete and accurate identification of the problem in a timely
-25- Enclosure
manner; (2) evaluation and disposition of operability/reportability issues; (3) consideration
of extent of condition, generic implications, common cause, and previous occurrences;
(4) classification and prioritization of the resolution of the problem; (5) identification of root
and contributing causes of the problem; (6) identification of corrective actions;
and (7) completion of corrective actions in a timely manner.
- September 20, 2006, Unit 2, repeat occurrence of containment purge isolation
- October 30, 2006, Unit 2, repeat occurrence of improper electrical connections in
motor-control centers
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
- 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
Documents reviewed by the inspectors are listed in the attachment
.3 Semiannual Trend Review
a. Inspection Scope
The inspectors completed a semi-annual trend review of repetitive or closely related
issues that were documented in corrective action documents to identify trends that might
indicate the existence of more safety-significant issues. The inspectors' review consisted
of the 6-month period of June 24 through December 31, 2006. When warranted, some of
the samples expanded beyond those dates to fully assess the issue. The inspectors also
reviewed CAP items associated with deficiencies in the conduct of activities involving hot
work. The inspectors compared and contrasted their results with the results contained in
the licensees quarterly trend reports. Corrective actions associated with a sample of the
issues identified in the licensees trend report were reviewed for adequacy. Documents
reviewed by the inspectors are listed in the attachment.
-26- Enclosure
b. Findings
During the Unit 2 pressurizer replacement Refueling Outage 2R18 from September 19
through October 28, 2006, several deficiencies were noted involving the conduct of hot
work. Licensee Procedure EN-DC-127, Control of Hot Work and Ignition Sources,
contains the governing guidelines for the conduct of hot work, including Hot Work
Permit, Attachment 8.1, which serves to document that the applicable requirements for
each activity involving hot work are met. Examples of instances resulting from failures to
adequately implement the control of hot work procedure included:
- On September 24, 2006, welding activities being conducted on the Unit 2 main
condenser manway cover resulted in paint/crud smoldering that was extinguished
with a portable fire extinguisher.
- On September 25, 2006, sparks from torch cutting of the Unit 2 containment sump
strainer ignited a nearby plastic bag containing used anti-contamination clothing.
- On September 26, 2006, a substantial amount of slag from the containment sump
strainer torch cutting flowed down onto a fire blanket that was protecting the floor
and caused the fire blanket to ignite.
- On September 27, 2006, slag from the containment sump strainer torch cutting
flowed down through a fire blanket and landed on Valve 2BS-38 in the containment
sump. The slag came in contact with debris buildup on the valve locking chain and
began to smoke and smolder. A portable fire extinguisher was discharged to
extinguish the smoldering.
- On September 28, 2006, the firewatch posted for the containment sump strainer
hot work could not get to his designated fire extinguisher. The firewatch had
moved to the east side of the sump and the extinguisher remained on the west
side of the sump.
- On October 5, 2006, a small fire in the Unit 2 containment building basement
below the pressurizer was extinguished by the assigned firewatch using a portable
extinguisher.
- On October 16, 2006, welding and grinding activities above the replacement
pressurizer were being performed without proper protection to prevent sparks from
traveling down the cavity below.
The licensee entered each of these occurrences into their CAP.
.4 Access Control to Radiologically Significant Areas
Section 2OS1 evaluated the effectiveness of the licensee's problem identification and
resolution processes regarding access controls to radiologically significant areas and
radiation worker practices. The inspectors reviewed corrective action documents for root
cause/apparent cause analysis against the licensees problem identification and resolution
process. No findings of significance were identified.
-27- Enclosure
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
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 actions were 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.
- October 26, 2006, Unit 1, fish intrusion into the circulating water system
- October 30, 2006, Unit 2, fire in Motor-Control Center 2B-53
- November 9, 2006, Unit 1, unplanned loss of Main Feedwater Pump P-2A
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed three samples.
b. Findings
Introduction. A Green self-revealing finding was identified when the licensee replaced an
air conditioning unit for the Unit 1 Main Feedwater Pump (MFP) A control cabinet without
considering the effects of electromagnetic interference (EMI) on the digital speed
monitor (DSM) housed in the cabinet. Consequently, MFP A tripped, resulting in an
unplanned automatic plant power reduction from 100 percent to 40 percent RTP.
Description. In September 2006 the air conditioning unit for the Unit 1 MFP A cabinet
failed. During the procurement phase of replacement efforts, the station discovered that
the current air conditioning unit was no longer available because it had become obsolete.
The licensee contacted the cabinet manufacturer who recommended to the licensee a
replacement unit. On October 12 the licensee replaced the air conditioning unit with the
recommended replacement after evaluating it as being an equivalent unit in accordance
with Procedure EN-DC-313, Procurement Engineering Process, Revision 0.
Subsequently, on November 9, 2006, while Unit 1 was operating at 100 percent RTP
MFP A tripped, which caused the integrated control system to initiate and perform an
unplanned automatic power reduction to 40 percent RTP. Operators surveyed the
indications and concluded that the cause of the MFP trip was an overspeed condition;
however, at the time of the trip, there were no indications that the MFP had actually
experienced an overspeed.
After extensive troubleshooting, the licensee suspected that EMI from the air conditioning
unit was the cause of the faults. The licensee performed a review of the new air
conditioning unit and identified that the bottom section of the new unit was molded plastic
and not metal like the previous unit. They also discovered the configuration of this new
unit placed the blower fan directly above, and in closer proximity to, the DSM than did that
of the previous air conditioning unit. The licensee decided to remove power to the air
conditioning unit to verify that it was the initiator of the faults in the DSM. With power to
the air conditioning unit removed, the faults and trips did not recur.
-28- Enclosure
The inspectors reviewed the licensees root cause evaluation of this event, documented in
CR ANO-1-2006-1399, which determined the root cause to be that the procurement
engineering equivalency guidelines did not consider EMI as a potential failure mode.
During this review, the inspectors noted that the licensee had not questioned or
investigated any of the differences between the old and the new air conditioning units.
Instead, the licensee had relied on the manufacturers designation that the new unit was
an equivalent replacement for the old unit.
Also, during their review of the root cause analysis, the inspectors noted that there had
been previous experiences with the MFP A control system involving EMI, as well as a
substantial amount of industry operating experience concerning the topic of EMI and
digital components. During interviews with station personnel, the inspectors also
determined that station engineers received specific training on EMI related to digital
components.
Analysis. The inspectors determined that the failure of the licensee to adequately
evaluate the new air conditioning unit with respect to design differences and possible
EMI interactions was a performance deficiency. The finding was determined to be more
than minor because it affected the design control attribute of the initiating events
cornerstone objective to limit the likelihood of those events that upset plant stability and
challenge critical safety functions during shutdown as well as power operations. Using the
MC 0609, Significance Determination Process, Phase 1 Worksheet, the finding is
determined to have very low safety significance because the condition only affected the
initiating events cornerstone and did not contribute to both the likelihood of a reactor trip
and the likelihood that mitigation equipment or functions will not be available. The cause
of the finding is related to the crosscutting element of problem identification and resolution
associated with operating experience because the licensees failure to implement and
institutionalize OE through changes to station processes and procedures.
Enforcement. While a performance deficiency was identified with regard to the trip of the
MFP A, there were no violations identified during the review of this issue. The licensee
has entered this issue into the CAP as CR ANO-1-2006-1399: FIN 05000313/2006005-5,
Trip of a MFP Due to Inadequate Design Control.
4OA5 Other Activities
.1 (Closed) Temporary Instruction (TI) 2515/169, Mitigating Systems Performance
Index (MSPI) Verification
a. Inspection Scope
During this inspection period, the inspectors completed a review of the licensees
implementation of the MSPI in accordance with the guidance provided in TI 2515/169.
The review examined the licensees MSPI Basis Documents (ANO1-A-6-0001, Revision 1,
and ANO2-SA-06-00001, Revision 0) and verified the established system boundaries and
monitored components were consistent with guidance provided in NEI 99-02, Reactor
Oversight Process Performance Indicators, Revision 4. The inspectors verified that the
licensee did not include credit for unavailability hours for short term unavailability or
operator recovery actions to restore the risk-significant function as is allowed by
-29- Enclosure
Additionally, the inspectors reviewed the baseline MSPI unavailability time using plant
specific values for the period of 2002 through 2004. The verification included all planned
and unplanned unavailability. For Unit 1, the inspectors reviewed the baseline MSPI
unreliability data using plant specific values for the period of 2002 through 2004. Unit 2
derived its baseline unreliability on industry standard values, as is permitted by NEI 99-02.
The plant specific data for 2005 through 2006 were also reviewed to ensure the licensee
properly accounted for the actual unavailability hours of MSPI systems. For the same
period, the MSPI component unreliability data was examined to ensure the licensee
identified all failures of monitored components. The accuracy and completeness of the
reported unavailability and unreliability data was verified by reviewing operating logs, CRs,
and work order documents. The unavailability and unreliability data was compared with PI
data submitted to the NRC to ensure that any discrepancies would not result in a change
to the index color.
b. Findings
No findings of significance were identified. This completes the inspection requirements
for this TI.
.2 Institute of Nuclear Power Operations Plant Assessment Report Review
a. Inspection Scope
The inspectors reviewed the final report for the Institute of Nuclear Power Operations
plant assessment of Arkansas Nuclear One, Units 1 and 2, conducted in July and
August 2006. The inspectors reviewed the report to ensure that issues identified were
consistent with the NRC perspectives of licensee performance and to verify if any
significant safety issues were identified that required further NRC followup.
b. Findings
No findings of significance were identified.
.3 (Closed) Unresolved Item (URI)05000313/2006003-01, Failure to Retrieve Required
Records of Activities Affecting Quality
In response to inspectors questioning the seismic capability of the Tendon Surveillance
Cranes L-28 on Unit 1, the licensee could not locate the appropriate documentation. The
licensee evaluated the as found conditions of the cranes against the uniformed building
code. The licensee concluded that the cranes would be able to withstand the design
basis earthquake without affecting mitigating equipment. These evaluations were
reviewed by the inspectors. No findings of significance were identified, and no violations
of NRC requirements were identified. The licensee documented the evaluations
demonstrating the seismic qualification in CR ANO-1-2005-3109. This unresolved
item (URI) is closed.
-30- Enclosure
.4 NRC TI 2515/166, PWR Containment Sump Blockage
The inspectors reviewed ANOs Unit 2 implementation of plant modifications and
procedure changes committed to in their response to Generic Letter 2004-02, Potential
Impact of Debris on Emergency Recirculation During Design Basis Accidents at
Pressurized Water Reactors.
The inspectors observed installation of the containment recirculation sump strainers,
debris barriers, and interceptors. In addition, the inspectors verified that ANO Unit 2 has
implemented specific procedure changes to control tags, labels, tape, and other objects
inside the containment building.
At the time of the inspection, industry testing for chemical effects on containment
recirculation sumps was not complete. Since the testing was not complete, ANO Unit 2
evaluated the new recirculation sump modifications to the original design basis,
Regulatory Guide 1.82, Water Sources for Long-Term Recirculation Cooling Following a
Loss-of-Coolant Accident, Revision 0. Final review and acceptance of the modification
will be performed by the Office of Nuclear Reactor Regulation at a later date.
4OA6 Meetings, Including Exit
On October 6, 2006, the inspectors presented the access controls inspection results to
Mr. T. Mitchell, General Manager and other members of his staff who acknowledged the
findings. The inspectors confirmed that proprietary information was not provided or
examined during the inspection.
The engineering inspectors presented the results of the inservice inspection review to
Mr. J. Kowalewski, Director, Engineering, on October 10, 2006. Mr. Kowalewski
acknowledged the inspection findings. The engineering inspector conducted a followup
exit with Mr. T. Mitchell, General Manager, Plant Operations, on December 4, 2006, to
provide updated information on the documentation associated with the review of the
containment sump modification. The inspectors identified that they had not reviewed
proprietary information.
On November 1, 2006, the inspector presented the results of the emergency plan change
inspection to Mr. R. Holeyfield, Supervisor, Emergency Preparedness. The inspector
confirmed that proprietary information was not provided or examined during the
inspection.
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 January 17, 2007. The resident inspectors conducted a followup
exit with Mr. J. Forbes, Vice President, Operations, on February 8, 2007. The licensee
acknowledged the findings presented. The inspectors noted that while proprietary
information was reviewed, none would be included in this report.
ATTACHMENT: SUPPLEMENTAL INFORMATION
-31- Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
R. Barnes, Manager, Planning, Scheduling, and Outages
S. Bennett, Project Manager, Licensing
B. Berryman, Manager, Operations Unit 1
J. Browning, Manager, Operations Unit 2
S. Cotton, Manager, Training
B. Daiber, Supervisor, Systems Engineering
J. Eichenberger, Manager, Corrective Actions and Assessments
J. Forbes, Vice President, Operations
R. Fowler, Emergency Planner
R. Freeman, Emergency Planner
J. Giles, Manager, Technical Support
M. Ginsberg, Supervisor, Engineering Programs and Components
R. Gresham, Emergency Planner
D. Harris, Emergency Planner
A. Hawkins, Licensing Specialist
J. Hoffpauir, Manager, Maintenance
R. Holeyfield, Manager, Emergency Planning
M. Huff, Supervisor, Project Engineering
D. James, Manager, Licensing
W. James, Manager, Engineering Projects
J. Kowalewski, Director, Engineering
T. Marlow, Director, Nuclear Safety Assurance
J. Miller, Jr., Manager, System Engineering
T. Mitchell, General Manager, Plant Operations
D. Moore, Manager, Radiation Protection
K. Panther, Nondestructive Examination Site Level III
C. Reasoner, Manager, Engineering Programs and Components
C. Tyrone, Manager, Quality Assurance
F. Van Buskirk, Licensing Specialist
D. White, Emergency Planner
P. Williams, Supervisor, Systems Engineering
M. Woodby, Manager, Design Engineering
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000368/2006005-01 NCV Fire During Hot Work Activities on the Containment Sump
Strainer (Section 1R05)05000368/2006005-02 NCV Failure to Perform Modification Resulted in an Inoperable
RCP Oil Collection System (Section 1R15)
A-1 Attachment
05000368/2006005-03 NCV Inadvertent RCS Draining While in Mode 5 (Section 1R20)05000368/2006005-04 FIN Unplanned Increase in Time with Reactor Vessel Water Level
at Flange Level (Section 1R20)05000313/2006005-05 FIN Trip of a MFP Due to Inadequate Design Control
(Section 4OA3)
Closed
05000313/2006003-01 URI Failure to Retrieve Required Records of Activities Affecting
Quality (Section 4OA5)
Discussed
None
LIST OF DOCUMENTS REVIEWED
In addition to the documents referred to 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:
Section 1R01: Adverse Weather Protection
NUMBER TITLE REVISION
OP-2203.008 Natural Emergencies 9
OP-1203.025 Natural Emergencies 20
Section 1R02: Evaluation of Changes, Tests, or Experiments
Engineering Requests
NUMBER TITLE REVISION
ER-ANO-2002-0836-003 Pressurizer Replacement 1
ER-ANO-2002-0836-004 Original Pressurizer Removal / Replacement 1
Pressurizer Installation
ER-ANO-2002-0836-020 Replacement Pressurizer Heater Electrical Design 0
Input
A-2 Attachment
Section 1R04: Equipment Alignment
Procedures
NUMBER TITLE REVISION
OP-1104.036 Emergency Diesel Generator Operations 45
Op-1107.002 ES Electrical System Operations 23
OP-1104.005 Reactor Building Spray System Operation 46
Section 1R05: Fire Protection
Plant Drawings
FZ-1038, Sheet 1, Revision 2
FZ-2018, Sheet 1, Revision 2
Procedures
NUMBER TITLE REVISION
Arkansas Nuclear One Fire Hazards Analysis 11
PFP-U1 ANO Prefire Plan (Unit 1) - Section 1B-357-67-U.doc, 2
Section 1B-354-79-U.doc
PFP-U2 ANO Prefire Plan (Unit 2) - Section 2B-335-2040- 2
JJ.doc
EN-DC-127 Control of Hot Work and Ignition Sources 2
CRs
ANO-1-2005-0950 ANO-2-2005-1724 ANO-2-2006-1565 ANO-2-2006-1701
ANO-1-2005-1397
Section 1R07: Heat Sink Performance
NUMBER TITLE REVISION
ULD-1-SYS-01 ANO-1 Emergency Diesel Generator (EDG) System 4
ULD-1-SYS-10 ANO-1 Service Water Systems 13
SPEC-6600-M-012 Emergency Diesel Generators for ANO Unit 1 1
ER-ANO-2004-0663-000 2004 Unit 1 EDG Thermal Test Results 0
ER-980310 EDG Coolers, E-20A/B, Service Water Flow
Requirements
CALC-91-R-2013-01 Service Water Performance Testing Methodology 14
A-3 Attachment
OP-1309.018 EDG Cooler Thermal Test Change 004-02-0
Section 1R08: Inservice Inspection (71111.08P)
CRs:
ANO-2-2005-0916 ANO-2-2006-1208 ANO-C-2006-1733
REPORT COMPONENT/LOCATION METHOD
BOP-RT-06-055 FW-50 (WDR-40631) Drawing No. 2CCA-15-1, Sheet 1 Radiographic
BOP-RT-06-056 FW-51 (WDR-40632) Drawing No. 2CCA-15-1, Sheet 1 Radiographic
ISI-UT-06-033 2-73-SWS-R-12B-30R, 2HBC-60-1 between FW-52C & Automatic
FW-6C1 Ultrasonic
ISI-UT-06-040 FW-50 (WDR-40631) Drawing No. 2CCA-15-1, Sheet 1 Ultrasonic
ISI-UT-06-042 FW-51 (WDR-40632) Drawing No. 2CCA-15-1, Sheet 1 Ultrasonic
Procedures
PROCEDURE TITLE REVISION
CEP-NDE-0110 Program Section for Certification of NDE Personnel 2
CEP-NDE-0111 Certification of Ultrasonic Personnel in Accordance 1
with ASME Section XI, Appendix VII
CEP-NDE-0400 Ultrasonic Examination 0
CEP-NDE-0404 Manual Ultrasonic Examination of Ferritic Piping 1
Welds (ASME XI)
CEP-NDE-0423 Manual Ultrasonic Examination of Austenitic Piping 1
Welds (ASME XI)
CEP-NDE-0505 Ultrasonic Thickness Examination 3
A-4 Attachment
Welding Procedures/Qualification Records
NUMBER TITLE REVISION/
DATE
PQR 107 Manual Gas Tungsten & Shielded Metal Arc 1
Welding (GTAW & SMAW), P-No. 8, SA-312 Type
304
PQR 170 Manual Gas Tungsten & Shielded Metal Arc 1
Welding (GTAW & SMAW), P-No. 8, SA-240 Type
304
WPS E-P8-T-A8,Ar Manual Gas Tungsten Arc Welding (GTAW) of 0
P-No. 8 Stainless Steels
WPS E-P8-T(M)-A8,Ar Machine Gas Tungsten Arc Welding (GTAW) of 0
P-No. 8 Stainless Steels
WP 06-121 2T-1 Surge Line October 3,
2006
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
COPD-024, Risk Assessment Guidelines, Revision 18
Section 1R15: Operability Evaluations
CRs
ANO-2-1995-0555 ANO-2-2006-1459 ANO-2-2006-1522 ANO-2-2006-1796
ANO-2-2006-1407 ANO-2-2006-1478 ANO-2-2006-1539 ANO-2-2006-1853
ANO-2-2006-1433 ANO-2-2006-1521 ANO-2-2006-1757 ANO-2-2006-1879
Procedure
OP-2305.002, Reactor Coolant System Leak Detection, Revision 14
Engineering Requests
ER-ANO-2000-2528-003, ANO Sump Operability when the RCS Temperature is Above 200 F
ER-ANO-2004-0060-000, ANO-2 Sump Operability for the RCS Temperature above 200 F
Miscellaneous Documents
2CNA108802, Safety Evaluation Report, dated October 26, 1988
0CAN088404, Station Letter to USNRC Requesting Exemption, dated August 15, 1984
A-5 Attachment
Section 1R17: Permanent Plant Modifications
Engineering Requests
NUMBER TITLE
ER-ANO-2002-0836-003 Pressurizer Replacement
ER-ANO-2002-0836-004 Original Pressurizer Removal / Replacement
Pressurizer Installation
ER-ANO-2002-0836-005 Interference Removal / Reinstallation Inside the
Pressurizer Cubicle
ER-ANO-2002-0836-006 Interference Removal / Reinstallation Outside the
Pressurizer Cubicle
ER-ANO-2002-0836-007 ANO-2 Pressurizer Replacement Rigging and
Handling
ER-ANO-2002-0836-020 Replacement Pressurizer Heater Electrical Design
Input
Section 1R20: Refueling and Outage Activities
Procedures
NUMBER TITLE REVISION
OP-2104.004 Shutdown Cooling System 031-00-0
OP-2104.019 Clean Resin Transfer 009-01-0
OP-2504.005 Reactor Vessel Closure Head Removal 012-01-0
Miscellaneous Document
Shutdown Operations Protection Plan, dated August 4, 2005
CRs
ANO-2-2006-1464 ANO-2-2006-1573 ANO-2-2006-2032 ANO-C-2006-1678
ANO-2-2006-1553 ANO-2-2006-1734 ANO-C-2006-1473
Section 2OS1: Access Controls to Radiologically Significant Areas
CRs
ANO-1-2006-0479 ANO-2-2006-1434 ANO-2-2006-1497 ANO-2-2006-1568
ANO-1-2006-0700 ANO-2-2006-1446 ANO-2-2006-1501 ANO-2-2006-1568
ANO-1-2006-1113 ANO-2-2006-1471 ANO-2-2006-1511 ANO-2-2006-1575
ANO-2-2005-1429 ANO-2-2006-1495 ANO-2-2006-1523 ANO-2-2006-1598
A-6 Attachment
ANO-2-2006-1606 ANO-2-2006-1674 ANO-2-2006-1716 ANO-2-2006-1774
ANO-2-2006-1636 ANO-2-2006-1675 ANO-2-2006-1717 ANO-2-2006-1790
ANO-2-2006-1638 ANO-2-2006-1695 ANO-2-2006-1748 ANO-C-2006-1698
ANO-2-2006-1671 ANO-2-2006-1696 ANO-2-2006-1765
Audits and Self-Assessments
Self-Assessment Report, QS-2006-ANO-007, 2R18 Radiation Protection Outage Planning
Review
Radiation Work Permits
NUMBER TITLE
RWP 2006-2420 Scaffold Activities
RWP 2006-2501 Support Activities for Pressurizer Replacement
RWP 2006-2502 Remove and Replace Pressurizer
RWP 2006-2520 Incore Instrument Thimble Tube Replacement
RWP 2005-2530 Sump Screen Modification
RWP 2006-2540 Hot Leg RTD Replacement
Procedures
NUMBER TITLE REVISION
1601.209 Whole Body Counting/Bioassay CHANGE
009-00
EN-RP-104 Personnel Contamination Events 3
EN-RP-108 Radiation Protection Posting 3
EN-RP-131 Air Sampling 1
EN-RP-203 Dose Assessment 0
EN-RP-208 Whole Body Counting and In-Vitro Bioassay 0
PL-182 Radiation Protection Expectations and Standards 1
Miscellaneous Document
Alpha Monitoring Plan, Revised August 22, 2006
A-7 Attachment
Section 4OA2: Identification and Resolution of Problems
CRs
ANO-2-2006-1535 ANO-2-2006-1655 ANO-2-2006-1891
ANO-2-2006-1625 ANO-2-2006-1693 ANO-2-2006-2174
Section 4OA3: Event Follow-up
Procedures
NUMBER TITLE REVISION
EN-DC-141 Design Inputs 2
EN-DC-313 Procurement Engineering Process 0
CRs
ANO-1-2006-1399 ANO-2-2006-1464 ANO-2-2006-2444 ANO-2-2006-2449
Section 4OA5: Other Activities (TI 2515/0166)
Safety Evaluation
FFN-06-008, Unit 2 RBS/ECCS Sump Strainer Replacement
A-8 Attachment
LIST OF ACRONYMS
ASME American Society of Mechanical Engineers Boiler and Pressure Vessel Code
CAP corrective action program
CCW component cooling water
CFR Code of Federal Regulations
CR condition report
DSM digital speed monitor
EDG emergency diesel generator
EMI electromagnetic interference
FIN finding
MC manual chapter
MSPI mitigating systems performance index
NCV noncited violation
NDE nondestructive examination
PI performance indicator
PWR pressurized water reactor
RCP reactor coolant pump
RTP rated thermal power
SSCs system, structure, and components
TI temporary instruction
TS Technical Specification
UFSAR Updated Final Safety Analysis
URI unresolved item
A-9 Attachment