ML053110530
| ML053110530 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 11/07/2005 |
| From: | Graves D NRC/RGN-IV/DRP/RPB-E |
| To: | Forbes J Entergy Operations |
| References | |
| IR-05-004 | |
| Download: ML053110530 (47) | |
See also: IR 05000313/2005004
Text
November 7, 2005
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
05000313/2005004 AND 05000368/2005004
Dear Mr. Forbes:
On September 23, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Arkansas Nuclear One, Units 1 and 2, facility. The enclosed integrated
report documents the inspection findings, which were discussed on September 28, 2005, 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 inspector identified and self-revealing findings of very low safety
significance (Green). Three of these findings were determined to involve violations of NRC
requirements; however, because the findings were entered into your corrective action program,
the NRC is treating these violations as noncited violations consistent with Section VI.A of the
Enforcement Policy. Additionally, a licensee identified violation which was determined to be of
very low safety significance is listed in this report. If you contest these noncited violations, you
should provide a response within 30 days of the date of this inspection report, with the basis for
your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control 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.
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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/
David N. Graves, Chief
Project Branch E
Division of Reactor Projects
Dockets: 50-313
50-368
Licenses: DPR-51
Enclosure:
NRC Inspection Report 05000313/2005004 and 05000368/2005004
w/Attachment: Supplemental Information and Phase 3 Evaluation, Damaged Reactor Coolant
Pump Seal, Arkansas Nuclear One, Unit 2
cc w/enclosure:
Senior Vice President
& Chief Operating Officer
Entergy Operations, Inc.
P.O. Box 31995
Jackson, MS 39286-1995
Vice President
Operations Support
Entergy Operations, Inc.
P.O. Box 31995
Jackson, MS 39286-1995
Manager, Washington Nuclear Operations
ABB Combustion Engineering Nuclear
Power
12300 Twinbrook Parkway, Suite 330
Rockville, MD 20852
County Judge of Pope County
Pope County Courthouse
100 West Main Street
Russellville, AR 72801
Entergy Operations, Inc.
-3-
Winston & Strawn LLP
1700 K Street, N.W.
Washington, DC 20006-3817
Bernard Bevill
Radiation Control Team Leader
Division of Radiation Control and
Emergency Management
4815 West Markham Street, Mail Slot 30
Little Rock, AR 72205-3867
James Mallay
Director, Regulatory Affairs
Framatome ANP
3815 Old Forest Road
Lynchburg, VA 24501
Technological Services Branch
Chief
FEMA Region VI
800 North Loop 288
Federal Regional Center
Denton, Texas 76201-3698
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 (DNG)
Senior Project Engineer, DRP/E (VGG)
Team Leader, DRP/TSS (RLN1)
RITS Coordinator (KEG)
Regional State Liaison Officer (WAM)
NRR/DIPM/EPB/EPHP (REK)
J. Dixon-Herrity, OEDO RIV Coordinator (JLD)
ROPreports
ANO Site Secretary (VLH)
SISP Review Completed: DNG ADAMS: / Yes G No Initials: _DNG_____
/ Publicly Available G Non-Publicly Available
G Sensitive / Non-Sensitive
R:\\_ANO\\2005\\AN2005-04RP-RWD.wpd
RIV:RI:DRP/E
RI:DRP/E
SRI:DRP/E
C:DRS/PSB
JLDixon
ELCrowe
RWDeese
MPShannon
VGGaddy for
VGGaddy for
VGGaddy for
/RA/
11/02/05
11/02/05
11/02/05
10/31/05
C:DRS/OB
C:DRS/EMB
C:DRS/PEB
C:DRP/E
TGody
CJPaulk
LJSmith
DNGraves
/RA/
/RA/
/RA/
/RA/
11/01/05
11/01/05
11/02/05
11/07/05
OFFICIAL RECORD COPY
T=Telephone E=E-mail F=Fax
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets:
50-313, 50-368
Licenses:
Report:
05000313/2005004 and 05000368/2005004
Licensee:
Entergy Operations, Inc.
Facility:
Arkansas Nuclear One, Units 1 and 2
Location:
Junction of Hwy. 64W and Hwy. 333 South
Russellville, Arkansas
Dates:
June 24 through September 23, 2005
Inspectors:
K. Clayton, Operations Engineer
E. Crowe, Resident Inspector
R. Deese, Senior Resident Inspector
J. Dixon, Resident Inspector
P. Elkmann, Emergency Preparedness Inspector
P. Goldberg, Reactor Inspector
W. McNeill, Reactor Inspector
M. Murphy, Senior Operations Engineer
Approved By:
David N. Graves, Chief, Project Branch E
Division of Reactor Projects
Enclosure
CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -1-
1R01
Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -1-
1R04
Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -2-
1R05
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -2-
1R06
Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -4-
1RO7 Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -5-
1R11
Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . -6-
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -7-
1R13
Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . -8-
1R14
Operator Performance During Nonroutine Plant Evolutions and Events . . . -11-
1R15
Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -14-
1R16
Operator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -14-
1R17
Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -15-
1R19
Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -15-
1R22
Surveillance Testing
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -16-
1R23
Temporary Plant Modifications
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -17-
1EP2 Alert Notification System Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -18-
1EP3 Emergency Response Organization Augmentation Testing (71114.03) . . . -18-
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies . . . -19-
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -19-
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -20-
4OA2 Problem Identification and Resolution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -21-
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -24-
4OA4 Crosscutting Aspects of Findings
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -24-
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -25-
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -26-
4OA7 Licensee-Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -26-
ATTACHMENT 1: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . A-2
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3
LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-12
ATTACHMENT 2: PHASE 3 EVALUATION, DAMAGED REACTOR COOLANT PUMP SEAL
ARKANSAS NUCLEAR ONE, UNIT 2
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A2-1
Enclosure
SUMMARY OF FINDINGS
IR 05000313/2005004, 05000368/2005004; 6/24/05 - 9/23/05; Arkansas Nuclear One, Units 1
and 2; Maintenance Risk Assessments, Operator Performance During Nonroutine Plant
Evolutions and Events, Problem Identification and Resolution, Other Activities.
This report covered a 3-month period of inspection by resident inspectors and regional
specialist inspectors. Five Green findings, three of which were noncited violations. 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. The inspectors reviewed a self-revealing finding for an inadequate
troubleshooting procedure for the Unit 2 pressurizer level instrumentation. When
implemented, the procedure resulted in the unplanned energizing of all
pressurizer heaters with Unit 2 operating at normal operating pressure and a
subsequent increase in reactor coolant system pressure which was not
anticipated by operators. The licensee entered the procedural failure to address
the effect of de-energizing Alarm Relay Bistable 2LC-4627-1BN on the
pressurizer heater circuitry into their corrective action program for resolution.
The cause of the finding is related to the crosscutting element of human
performance.
This finding is greater than minor because it affected the procedure quality
attribute under the initiating events cornerstone objective of limiting the likelihood
of those events that upset plant stability. Using the significance determination
process, the finding was determined to have very low safety significance
because this transient initiator did not contribute to both the likelihood of a
reactor trip and the likelihood that mitigation equipment or functions would not be
available (Section 1R14.1).
Green. The inspectors reviewed a self-revealing finding for an inadequate
maintenance procedure which resulted in Control Element Assembly 50 dropping
into the core with Unit 2 operating at 100 percent rated thermal power. During
troubleshooting efforts for a missing phase on the upper gripper for Control
Element Assembly 56, power to the only gripper holding Control Element
Assembly 50 fully withdrawn (the lower gripper) was removed by instrumentation
and control technicians. The procedure failed to contain detailed guidance to
ensure that Control Element Assembly 50 was properly being held by the upper
gripper. The licensee performed a thorough root cause of the event to
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Enclosure
determine the short and long term corrective actions. The cause of the finding is
related to the crosscutting element of human performance.
This finding is greater than minor because it affected the procedure quality
attribute under the initiating events cornerstone objective of limiting those events
that upset plant stability. Using the significance determination process, the
finding was determined to have very low safety significance because this
transient initiator did not contribute to both the likelihood of a reactor trip and the
likelihood that mitigation equipment or functions would not be available
(Section 1R14).
Cornerstone: Mitigating Systems
Green. The inspectors identified a noncited violation of 10 CFR 50.65(a)(4) for
the failure to perform an adequate risk assessment before replacement activities
associated with Unit 1 decay heat room Cooler VUC-1D. Because the work
procedure referenced an outdated engineering report, it did not include adequate
information to ensure that the required risk management actions were taken.
Mechanical maintenance personnel failed to inform operations personnel that a
Unit 1 decay heat vault door was open and incapable of being readily shut. The
licensee entered this performance deficiency into their corrective action program
for resolution. The cause of the finding is related to the crosscutting element of
human performance.
This finding is more than minor because it affected the attribute under the
mitigating systems cornerstone objective of ensuring the availability of systems
that respond to initiating events to prevent undesirable consequences, in that the
licensee failed to implement compensatory risk management measures. Using
the maintenance risk assessment and risk management significance
determination process, the finding was determined to have very low safety
significance because the performance deficiency was associated only with
inadequate risk management actions and the incremental increase in core
damage probability was negligible (Section 1R13).
Green. The inspectors identified a noncited violation of 10 CFR 50.65(a)(4) for
the failure to perform an adequate risk assessment before the isolation of the
Unit 1 electromatic relief valve. Operators considered that there would be no
impact on plant risk before isolating the electromatic relief valve, but they failed
to consider the increased probability of a pressurizer code safety valve failing to
reseat. The licensee entered this performance deficiency into their corrective
action program for resolution. The cause of the finding is related to the
crosscutting element of human performance.
This finding is greater than minor because it related to a risk assessment which
failed to consider a risk significant component that was unavailable during
maintenance and contained known errors that had the potential to change the
outcome of the assessment. Using the Maintenance Risk Assessment and Risk
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Enclosure
Management Significance determination process, the finding was determined to
have very low safety significance because the inadequate risk assessment only
had an incremental increase in core damage probability of less than 1 x 10-6
(Section 1R13).
Green. The inspectors reviewed a self-revealing noncited violation of Unit 2
Technical Specification 6.4.1, "Procedures," when reactor coolant pump seal
injection flow was established with the reactor coolant pump uncoupled from its
motor. This activity led to damage of the seal for Reactor Coolant
Pump 2P-32C. This damage required conducting an additional reduced reactor
coolant system inventory maintenance period to replace the seal. The licensee
performed a thorough root cause of the event to determine the short and long
term corrective actions. The cause of the finding is related to the crosscutting
element of human performance.
This finding is greater than minor because it affected the procedural quality
attribute under the mitigating systems cornerstone objective of ensuring the
availability and reliability of the reactor coolant system inventory, such that the
licensee had to enter a higher risk plant operating state to repair the seal. Using
the shutdown operations significance determination process, the inspectors
determined the finding required a Phase 2 analysis. In the Phase 2 analysis, risk
analysts determined the finding to be of very low safety significance because
(1) the seal replacement activity only required establishing reduced inventory
conditions (not midloop) and (2) the time needed to replace the seal was not
extensive (Section 4OA5).
Cornerstone: Barrier Integrity
B.
Licensee-Identified Violations
Violations of very low safety significance which were identified by the licensee have
been reviewed by the inspectors. Corrective actions taken or planned by the licensee
have been entered into the licensee's corrective action program. These violations and
their corrective actions are listed in Section 4OA7 of this report.
Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 began the inspection period at 100 percent rated thermal power and remained there
throughout the inspection period.
Unit 2 began the inspection period at 100 percent rated thermal power and remained there until
September 8, 2005, when the unit down powered to approximately 65 percent rated thermal
power as a result of a dropped control element assembly (CEA). The unit subsequently
returned to 100 percent rated thermal power on September 10, 2005, and remain there for the
rest of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R01
Adverse Weather Protection (71111.01)
a.
Inspection Scope
Readiness for Seasonal Susceptibilities. The inspectors completed a review of the
licensee's readiness of seasonal susceptibilities involving extreme high temperatures.
The inspectors: (1) reviewed plant procedures, the Updated Safety Analysis Report,
and Technical Specifications to ensure that operator actions defined in adverse weather
procedures maintained the readiness of essential systems; (2) walked down portions of
the systems listed below to ensure that adverse weather protection features were
sufficient to support operability including the ability to perform safe shutdown functions;
(3) evaluated operator staffing levels to ensure the licensee would maintain the
readiness of essential systems required by plant procedures; and (4) reviewed the
corrective action program (CAP) to determine if the licensee identified and corrected
problems related to adverse weather conditions.
August 10, 2005, Unit 1 high pressure injection (HPI) and emergency
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
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Enclosure
1R04
Equipment Alignment (71111.04)
a.
Inspection Scope
Partial System Walkdowns. The inspectors: (1) walked down portions of the three risk
important systems listed below 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 licensee's CAP to ensure problems
were being identified and corrected.
August 4, 2005, Unit 1 HPI system
August 10, 2005, Unit 1 EFW system
August 22-23, 2005, Unit 1 safety-related DC electrical system
The inspectors completed three samples.
Complete Walkdown. The inspectors: (1) reviewed plant procedures, drawings, the
Updated Safety Analysis Report, Technical Specifications, and vendor manuals to
determine the correct alignment of the system; (2) reviewed outstanding design issues,
operator work arounds, and CAP documents to determine if open issues affected the
functionality of the system; and (3) verified that the licensee was identifying and
resolving equipment alignment problems.
July 27-29, 2005, Unit 2 containment spray system
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection (71111.05)
a.
Inspection Scope
Routine Inspection. The inspectors walked down the seven plant areas listed below to
assess the material condition of active and passive fire protection features, their
operational lineup, and their operational effectiveness. The inspectors: (1) verified that
transient combustibles and hot work activities were controlled in accordance with plant
procedures; (2) observed the condition of fire detection devices to verify they remained
functional; (3) observed fire suppression systems to verify they remained functional;
(4) verified that fire extinguishers and hose stations were provided at their designated
locations and that they were in a satisfactory condition; (5) verified that passive fire
protection features (electrical raceway barriers, fire doors, fire dampers, steel fire
proofing, penetration seals, and oil collection systems) were in a satisfactory material
condition; (6) verified that adequate compensatory measures were established for
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Enclosure
degraded or inoperable fire protection features; and (7) reviewed the CAP to determine
if the licensee identified and corrected fire protection problems.
June 30, 2005, Unit 1 Fire Zone 38-Y, EFW pump room
July 12, 2005, Unit 1 Fire Zone 97-R, integrated control system (ICS) relay room
and cable spreading room
July 15, 2005, Unit 2 Fire Zone 2101-AA, north switchgear room
July 19, 2005, Unit 2 Fire Zone 2096-M, motor control center room
July 29, 2005, Unit 1 Fire Zone Area N, intake structure
July 29, 2005, Unit 1 Fire Zone 112-I, lower north electrical penetration room
August 31, 2005, Unit 1 Fire Zone 98-J, emergency diesel generator corridor
b.
Findings
Unit 1 EFW Pump Room Sprinklers
The inspectors identified an unresolved item (URI) for the Unit 1 EFW pump room fire
sprinklers. On June 30, 2005, the inspectors reviewed the licensees commitment for
train separation in Fire Zone 38-Y, Unit 1 EFW pump room. The inspectors learned that
since the licensee could not demonstrate train separation per 10 CFR Part 50,
Appendix R,Section III.G.2, for the as-built configuration, the licensee requested an
exemption from Appendix R in 1988. The exemption was required because the
turbine-driven and motor-driven EFW pumps and cables share a common room and
have as little as 4 feet of electrical separation. One of the requirements from the
granted exemption was that a fire sprinkler system be built and designed per National
Fire Protection Association (NFPA) 15, 1985 Edition, around the turbine-driven
EFW pump. NFPA 15, defined a water spray system as a normally open sprinkler head.
However, upon inspection of Fire Zone 38-Y, the EFW pump room, the inspectors
noticed that the licensees installed sprinkler system had frangible bulb sprinkler heads
installed. The inspectors then reviewed the licensees design change package that
installed the sprinkler system and discovered it stated that the system was designed and
installed using the guidelines of NFPA 13 and 15, 1985 Edition. The licensee could not
provide to the inspectors supporting documentation to show that the installed sprinkler
system met NFPA 15, 1985 Edition, or that a deviation to the NFPA code was
established due to the sprinkler heads being frangible bulb type. The licensee
contracted an NFPA code expert to determine the status of the installed sprinkler
system with regard to the requirements of NFPA 15, 1985 Edition, and is awaiting the
completion of the report. In response to this issue, the licensee established alternate
suppression and hourly fire watch compensatory measures ensuring an on-going safety
concern did not exist. The licensee entered this condition into their CAP as Condition
Report (CR) ANO-1-2005-0954. Pending completion and review of the licensees code
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Enclosure
compliance document and a review of the safety significance by the regional senior
reactor analyst, this finding is considered unresolved (URI 05000313/2005004-01,
"Failure to Comply with Licensing Basis for Emergency Feedwater Pump Room Fire
Sprinklers.")
Unit 1 ICS Relay Room Sprinklers
On July 12, 2005, in preparation for inspection of the ICS relay room, the inspectors
referenced the applicable section of "Arkansas Nuclear One - Units 1 and 2 Fire
Hazards Analysis," Revision 9. The inspectors determined from this review that the
ICS relay room was contained within Fire Zone 97-R which was to be protected by an
automatic deluge suppression system. The inspectors then conducted their walkdown
and noted that no sprinkler systems were in the ICS relay room. The inspectors
questioned licensee fire protection engineers who could not readily explain the
discrepancy and, subsequently, generated CR ANO-1-2005-1158 to explore the
discrepancy. Because the corrective action to explain this discrepancy was still
incomplete, the inspectors identified this condition as a URI 05000313/2005004-02,
"Absence of ICS Relay Room Fire Sprinklers."
1R06
Flood Protection Measures (71111.06)
a.
Inspection Scope
Annual External Flooding. For the building listed below, the inspectors: (1) reviewed
the Updated Safety Analysis Report, the flooding analysis, and plant procedures to
assess seasonal susceptibilities involving external flooding; (2) reviewed the CAP to
determine if the licensee identified and corrected flooding problems; (3) inspected
underground bunkers/manholes to verify the adequacy of: (a) sump pumps, (b) level
alarm circuits, (c) cable splices subject to submergence, and (d) drainage for
bunkers/manholes; (4) verified that operator actions for coping with flooding can
reasonably achieve the desired outcomes; and (5) walked down the areas listed below
to verify the adequacy of (a) equipment seals located below the floodline, (b) floor and
wall penetration seals, (c) watertight door seals, (d) common drain lines and sumps,
(e) sump pumps, level alarms, and control circuits, and (f) temporary or removable flood
barriers.
C
August 29, 2005, Unit 2 auxiliary building
The inspectors completed one sample.
Semiannual Internal Flooding. For the area listed below, the inspectors: (1) reviewed
the Updated Safety Analysis Report, the flooding analysis, and plant procedures to
assess seasonal susceptibilities involving internal flooding; (2) reviewed the CAP to
determine if the licensee identified and corrected flooding problems; (3) inspected
underground bunkers/manholes to verify the adequacy of (a) sump pumps; (b) level
alarm circuits; (c) cable splices subject to submergence; and (d) drainage for
bunkers/manholes; (4) verified that operator actions for coping with flooding can
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Enclosure
reasonably achieve the desired outcomes; and (5) walked down the areas listed below
to verify the adequacy of: (a) equipment seals located below the floodline, (b) floor and
wall penetration seals; (c) watertight door seals; (d) common drain lines and sumps;
(e) sump pumps, level alarms, and control circuits; and (f) temporary or removable flood
barriers.
C
July 27-29, 2005, Unit 2 Train B high pressure safety injection (HPSI), low
pressure safety injection, and containment spray pump room and gallery
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
1RO7 Heat Sink Performance (71111.07)
a.
Inspection Scope
Biennial Inspection. The inspectors reviewed design documents (e.g., calculations and
performance specifications), program documents, implementing documents (e.g., test
and maintenance procedures), and corrective action documents. The inspectors
discussed various corrective action items, heat exchanger testing and cleaning, and
design verification with licensee personnel.
For heat exchangers directly connected to the safety-related service water system, the
inspectors verified whether thermal performance testing, or heat exchanger inspection,
maintenance and cleaning, and the chemistry monitoring program provided sufficient
controls to ensure proper heat transfer. Specifically, the inspectors reviewed: (1) heat
exchanger test methods and test results from performance testing, (2) heat exchanger
inspection and cleaning methods and results, (3) chemical water treatment and results,
and (4) verification of design including flow balancing to ensure sufficient heat
exchanger flow.
For heat exchangers directly or indirectly connected to the safety-related service water
system, the inspectors verified the: (1) condition and operation were consistent with
design assumptions in the heat transfer calculations, (2) potential for water hammer, as
applicable, (3) chemistry controls for heat exchangers indirectly connected to the
safety-related service water system, and (4) redundant and infrequently used heat
exchangers are flow tested periodically to ensure sufficient flow.
If available, the inspectors reviewed additional nondestructive examination results for
the selected heat exchangers that demonstrated structural integrity.
The inspectors selected heat exchangers that ranked high in the plant specific risk
assessment and were directly or indirectly connected to the safety-related service water
system. The inspectors selected the following heat exchangers:
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Enclosure
Unit 1 shutdown cooling heat exchanger
Unit 1 reactor building coolers
Unit 2 engineered safety feature room coolers
The inspectors selected and completed three heat exchanger samples, which meets the
inspection procedure requirement of two to three samples.
The inspectors verified that the licensee had entered significant heat exchanger/heat
sink problems into the CAP. The inspectors reviewed 11 corrective action documents.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification Program (71111.11)
a.
Inspection Scope
Quarterly Inspection. On August 9, 2005, 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. Training Scenario A1SPGLOR060101, "New OTSGs," Revision 0,
was used and involved a main steam line break inside containment concurrent with an
EFW malfunction which led to overcooling of the reactor coolant system. The main
steam line break was modeled using the once-through SGs which are scheduled for
installation in the upcoming refueling outage.
The inspectors completed one sample.
Biennial Inspection for Unit 1 and Annual Inspection for Unit 2. The inspectors:
(1) evaluated examination security measures and procedures for compliance with
10 CFR 55.49; (2) evaluated the licensees sample plan of the written examinations for
compliance with 10 CFR 55.59 and NUREG-1021, "Operator Licensing Examiner
Standards," as referenced in the facility requalification program procedures; and
(3) evaluated maintenance of license conditions for compliance with 10 CFR 55.53 by
review of facility records (medical and administrative), procedures, and tracking systems
for licensed operator training, qualification, and watchstanding. In addition, the
inspectors reviewed remedial training for examination failures for compliance with facility
procedures and responsiveness to address failed areas.
Furthermore, the inspectors: (1) interviewed six personnel (two operators, two
instructors, the training supervisor, and one evaluator) regarding the policies and
practices for administering examinations, (2) observed the administration of two
dynamic simulator scenarios to one requalification crew; and (3) observed four
evaluators administer six job performance measures, four in the control room simulator
in a dynamic mode and two in the plant under simulated conditions.
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Enclosure
The inspectors also reviewed the remediation process and the results of the biennial
written examination. The results of the examinations were assessed to determine the
licensees appraisal of operator performance and the feedback of performance analysis
to the requalification training program. The inspectors interviewed members of the
training department and operating crews to assess the responsiveness of the licensed
operator requalification program. The inspectors also observed the examination
security maintenance for the operating tests during the examination week.
Additionally, the inspectors assessed the Arkansas Nuclear One, Unit 1,
plant-referenced simulator for compliance with 10 CFR 55.46 using Inspection
Procedure 71111.11 (Section 03.11). This assessment included the adequacy of the
licensees simulation facility for use in operator licensing examinations and for satisfying
experience requirements as prescribed by 10 CFR 55.46. The inspectors reviewed a
sample of simulator performance test records (transient tests, surveillance tests,
malfunction tests, and scenario-based tests), simulator discrepancy report records, and
processes for ensuring simulator fidelity commensurate with 10 CFR 55.46. The
inspectors also interviewed members of the licensees simulator configuration control
group as part of this review.
In addition to the biennial review for Unit 1, the inspectors reviewed the test results of
the Unit 2 annual operating examination for 2005. Since this was the first half of the
biennial requalification testing cycle, the licensee had not yet administered the written
examination. These results were assessed to determine if they were consistent with
NUREG-1021 guidance and Manual Chapter (MC) 0609, Appendix I, "Operator
Requalification Human Performance Significance Determination Process,"
requirements. This review included examination test results for 56 licensed individuals.
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 maintenance activities listed below to: (1) verify the
appropriate handling of structure, system, and component (SSC) 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 Technical Specifications.
September 21, 2005, Units 1 and 2 control room emergency ventilation system
inoperabilities
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Enclosure
September 23, 2005, Unit 2 HPSI pump performance
The inspectors completed two samples.
b.
Findings
No findings of significance were identified.
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
Risk Assessment and Management of Risk. The inspectors reviewed the assessment
activities listed below 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.
June 13-16, 2005, Unit 2 steam bypass Valve 2CV-0306 and planned
maintenance during the week
June 23, 2005, Unit 1 decay heat room Cooler VUC-1D replacement and
planned maintenance during the week
August 1-5, 2005, Unit 1 HPI Pump P-36A overhaul and planned maintenance
during the week
July 6 through September 23, 2005, Units 1 and 2 preparations inside the
protected area for the Unit 1 replacement outage
The inspectors completed four samples.
Emergent Work Control. The inspectors: (1) verified that the licensee performed
actions to minimize the probability of initiating events and maintained the functional
capability of mitigating systems and barrier integrity systems; (2) verified that emergent
work-related activities such as troubleshooting, work planning/scheduling, establishing
plant conditions, aligning equipment, tagging, temporary modifications, and equipment
restoration did not place the plant in an unacceptable configuration; (3) reviewed the
CAP to determine if the licensee identified and corrected risk assessment and emergent
work control problems.
July 8, 2005, Unit 1 condenser vacuum Pump C-5A inoperability
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Enclosure
August 25, 2005, Unit 1 isolation of the pressurizer electromatic relief
valve (ERV)
The inspectors completed two samples.
b.
Findings
Unit 1 Decay Heat Room Cooler Maintenance
Introduction. The inspectors identified a Green noncited violation (NCV) of
10 CFR 50.65(a)(4) for the failure to perform an adequate risk assessment before the
replacement of Unit 1 decay heat room Cooler VUC-1D.
Description. On June 23, 2005, during the decay heat room Cooler VUC-1D
replacement activities, the licensee opened the Green Train decay heat vault door,
Door 5, to allow for the old cooler to be rigged out of the room. The inspectors noted
that Door 5 was a high energy line break (HELB), fire, and flooding door and then
questioned operators about the status of the equipment in the room and what risk
management actions were being performed as a result of Door 5 being blocked open.
Operations personnel were not aware that the door was blocked open. The inspectors
learned that Maintenance personnel had failed to ensure that Operations personnel had
been informed that they opened Door 5 to remove the old room cooler.
Upon further review, the licensee discovered that the work order package for the job
was outdated and incomplete. The work order package was initially written in 2001 and
referenced an engineering request (ER) which had been superceded since the time the
work order package was written. As a result, the operational impact concerns were out
of date and the appropriate notification points to inform and/or request permission from
operations was not included. The superceded ER that was referenced only addressed
the door from a HELB perspective. Had the licensees up-to-date ER been referenced,
fire and flooding concerns, in addition to HELB concerns, would have been addressed.
The inspectors concluded that as a result of using an outdated work order and a
superceded ER, operations did not ensure that the required risk management actions
were taken, specifically, controls to ensure the establishment of a firewatch and
ensuring that flood mitigation hatches remained closed.
Analysis. The inspectors determined that the failure to ensure proper risk management
actions were taken was a performance deficiency. This finding is greater than minor
because it affected the availability objective of the equipment performance attribute
under the mitigating systems cornerstone, in that, the finding related to the licensee
failing to implement and effectively manage compensatory measures. Using
Appendix K, "Maintenance Risk Assessment and Risk Management Significance
Determination Process," of MC 0609, "Significance Determination Process," the finding
was determined to have very low safety significance (Green) because the performance
deficiency was associated only with inadequate risk management actions and the
incremental increase in core damage probability was negligible (less than 1 x 10-6). This
issue had human performance crosscutting aspects associated with having an
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Enclosure
inadequate work package and maintenance personnel not communicating with
operations personnel which resulted in risk management actions not being
implemented.
Enforcement. 10 CFR 50.65(a)(4) requires, in part, that the licensee shall assess and
manage the increase in risk that may result from proposed maintenance activities.
Contrary to this, on June 23, 2005, the licensee did not adequately assess risk from
maintenance activities that resulted in a HELB, fire, and flooding door being open and
incapable of being readily shut. Because of the very low safety significance and
because the licensee included this condition in the CAP as CR ANO-C-2005-1205, this
violation is being treated as an NCV, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000313/2005004-03, "Failure to Adequately Assess Risk
for a Blocked Decay Heat Vault Door."
Unit 1 ERV Isolation
Introduction. The inspectors identified a Green NCV of 10 CFR 50.65(a)(4) for the
failure to perform an adequate risk assessment associated with the manual isolation of
the Unit 1 ERV.
Description. On August 25, 2005, Unit 1 operators noticed that the acoustic monitor
indication for the Unit 1 pressurizer ERV was not operable. Operators decided to isolate
the ERV by shutting its isolation Valve CV-1000 since the ERV was considered to be
inoperable with its acoustic monitoring indication out of service. Discussions among
operations personnel concluded that the licensee's risk management assessment
program modeled both opened and closed failure modes. They reasoned that since the
ERV was isolated, it could not fail to reseat and that failure mode should not be
accounted for in a risk assessment. The operators also reasoned that, since the valve
was inoperable because of an indication issue, the valve was available and that failure
mode should not be accounted for in the risk assessment model either. As a result, the
operators assumed no impact on risk would be made when isolating the ERV.
The inspectors reviewed the licensee's assessment for the existing plant conditions and
concluded that the licensee had correctly used their risk management program to
assess the risk with the ongoing maintenance with HPI Pump P-36A, low pressure
injection Valve CV-1429, and Inverter Y-25. The inspectors then discovered in the
licensees risk assessment program that fault trees existed which showed that with the
ERV isolated, the pressurizer code safety valves would be the method of preventing
reactor coolant system overpressure since they would open first on any fast breaking
pressure increase transient. Additionally, the inspectors learned that the probability that
the pressurizer code safety valves would not close after lifting would be increased since
their probability of opening increased. From this the inspectors concluded that the
licensees risk assessment was incomplete since it did not incorporate the added risk
from the increased likelihood that a pressurizer code safety valve would stick open.
Analysis. The inspectors considered that the failure to account for the risk of an isolated
ERV was a performance deficiency. The inspectors determined this finding was greater
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Enclosure
than minor because it related to a licensees risk assessment which had known errors
that had the potential to change the outcome of the assessment. Using Appendix K,
"Maintenance Risk Assessment and Risk Management Significance Determination
Process," of MC 0609, "Significance Determination Process," the finding was
determined to have very low safety significance (Green) because the incremental
increase in core damage probability was less than 2.24 X 10-8. In this determination, the
inspectors assumed Inverter Y-25 and HPI Pump P-36A were already out of service for
maintenance when the ERV was isolated. Also, the inspectors used 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (between
6:59 a.m. and 3:04 p.m. on August 25, 2005) as the time of the inaccurate risk
assessment, which was the time when both the ERV was isolated and Green Train of
the low pressure injection system was removed from service. This issue had human
performance crosscutting aspects associated with operations personnel incorrectly
assuming a component had no risk significance which resulted in a non-conservative
risk assessment.
Enforcement. 10 CFR 50.65(a)(4) requires, in part, that the licensee shall assess and
manage the increase in risk that may result from proposed maintenance activities.
Contrary to this, the licensee did not adequately assess risk from isolating the Unit 1
pressurizer ERV. Because of the very low safety significance and because the licensee
included this condition in the CAP as CR ANO-C-2005-1257, this violation is being
treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000313/2005004-04, "Failure to Adequately Assess Risk for an Isolated
Pressurizer Electromatic Relief Valve."
1R14
Operator Performance During Nonroutine Plant Evolutions and Events (71111.14
and 71153)
a.
Inspection Scope
The inspectors: (1) reviewed operator logs, plant computer data, and/or strip charts for
the evolutions listed below to evaluate operator performance in coping with nonroutine
events and transients; (2) verified that the operator response was in accordance with the
response required by plant procedures and training; and (3) verified that the licensee
has identified and implemented appropriate corrective actions associated with personnel
performance problems that occurred during the nonroutine evolutions sampled.
April 24, 2005, Unit 1 loss of auxiliary cooling water flow
June 16, 2005, Unit 2 inadvertent energization of all pressurizer heaters
August 7, 2005, Unit 1 nuclear instrumentation power excursion to
101.87 percent nuclear instrument power
September 8, 2005, Unit 2 dropped Controlled Element Assembly 50
The inspectors completed four samples.
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Enclosure
b.
Findings
.1 Inadvertent Energization of All Unit 2 Pressurizer Heaters
Introduction. The inspectors reviewed a Green self-revealing finding involving the
unplanned energization of all Unit 2 pressurizer heaters caused by an inadequately
researched maintenance procedure.
Description. On June 1, 2005, the licensee was troubleshooting spiking in the Unit 2
pressurizer level indication using a preplanned work procedure. While in the process of
replacing Alarm Relay Bistable 2LC-4627-1BN in the indication circuitry, instrumentation
and control (I&C) technicians lifted electrical Lead 7 per the work procedure. Lifting this
lead caused a daisy chain of power losses which caused power to be lost to
Relay 63X/LC-110H in the pressurizer heater circuitry. This action in turn energized all
of the backup heaters and shunted the output of the pressurizer heater hand controller
station, thereby, fully energizing all proportional heaters. Lifting of Lead 7 also caused
the Channel 1 high pressurizer level alarm annunciator to alarm unexpectedly. With all
pressurizer heaters energized, reactor coolant system pressure rose to approximately
15 psig above normal operating pressure. In the diagnosis of the high pressurizer level
annunciator, operators recognized that all pressurizer heaters were energized, took
manual control, and restored pressure to normal. Additionally, I&C technicians
re-landed Lead 7. During inspection of this occurrence, the inspectors discovered that
the scope of the work package was inadequate, because lifting the lead had not been
properly researched by system engineers or work planners causing the unexpected
plant response.
Analysis. The inspectors determined that the licensees failure to adequately research
the effects of their maintenance on the pressurizer level circuitry was a performance
deficiency. This finding is greater than minor because it affected the human
performance attribute under the initiating events cornerstone objective of limiting the
likelihood of those events that upset plant stability and challenge critical safety functions.
Using the Phase 1 worksheets in MC 0609, "Significance Determination Process," the
issue was determined to have very low safety significance (Green) because the finding
did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation
equipment would not be available. This finding had crosscutting aspects of human
performance, in that, the engineers and planners did not adequately research a
procedure prior to its use on the plant.
Enforcement. No violation of regulatory requirements occurred. The inspectors
determined that the finding did not represent a noncompliance because it occurred on
nonsafety-related plant equipment. Licensee personnel entered this issue into the CAP
as CR ANO-2-2005-1678. This issue is being treated as a finding:
FIN 05000368/2005004-05, "Failure to Adequately Scope the Effects of Maintenance on
Pressurizer Level Instrumentation."
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Enclosure
.2 Dropped Unit 2 CEA
Introduction. The inspectors reviewed a self-revealing Green finding for an inadequate
maintenance procedure and troubleshooting plan which resulted in a dropped CEA on
Unit 2.
Description. On September 8, 2005, during troubleshooting efforts for CEA 56, CEA 50
dropped to the bottom of the core. At the time of the event, Subgroup 13, which contain
CEAs 50 and 56, was being transferred to the hold bus to allow for replacement of the
opto-isolator card for CEA 56. Control Element Assembly 56 troubleshooting indicated
that a phase on the upper gripper was firing all the time. The troubleshooting plan that
was being used allowed for I&C maintenance personnel to transfer the rods to the hold
bus by skill of the craft. However, if operations personnel were to perform the same
task, they had specific guidance contained in Operating Procedure 2105.009, "CEDM
Control System Operation," Revision 21. As a result of not having detailed guidance in
the troubleshooting plan, not using the operations procedure as a reference and not
having familiarity from performing transfers to the hold bus on frequent bases,
I&C maintenance personnel failed to ensure that CEA 50 was latched by the upper
gripper. When I&C transferred Subgroup 13 to the hold bus, the automatic CEA timer
module detected a voltage imbalance on CEA 50 and transferred CEA 50 to the lower
gripper. Subsequently, when the contact for the normal supply to CEA 50 was opened,
power to the lower gripper was removed resulting in CEA 50 dropping to the bottom of
the core.
Analysis. The inspectors considered that the failure to provide adequate procedural
guidance for CEA transfers to I&C technicians was a performance deficiency. This
finding is greater than minor because it affected the procedure quality attribute under
the initiating events cornerstone objective of limiting those events that upset plant
stability. Using the Phase 1 worksheets in MC 0609, "Significance Determination
Process," the finding was determined to have very low safety significance (Green)
because this transient initiator does not contribute to both the likelihood of a reactor trip
and the likelihood that mitigation equipment or functions will not be available. This issue
had human performance crosscutting aspects associated with an inadequate
maintenance procedure.
Enforcement. No violation of regulatory requirements occurred. The inspectors
determined that the finding did not represent a noncompliance because it occurred on
nonsafety-related equipment. The licensee included this condition in the CAP as
CR ANO-2-2005-2191. This issue is being treated as a finding:
FIN 05000368/2005004-06, "Inadequate Maintenance Procedure Results in Dropped
CEA."
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Enclosure
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
For the four operability evaluations listed below, the inspectors: (1) reviewed plants
status documents such as operator shift logs, emergent work documentation, deferred
modifications, and standing orders to determine if an operability evaluation was
warranted for degraded components; (2) referred to the Updated Safety Analysis Report
and design basis documents to review the technical adequacy of licensee operability
evaluations; (3) evaluated compensatory measures associated with operability
evaluations; (4) determined degraded component impact on any Technical
Specifications; (5) used the significance determination process to evaluate the risk
significance of degraded or inoperable equipment; and (6) verified that the licensee has
identified and implemented appropriate corrective actions associated with degraded
components.
CR-ANO-1-2005-0954, July 1, 2005, Unit 1 EFW water spray system
CR-ANO-1-2005-1022, July 15, 2005, Unit 1 HELB Door 62, electrical equipment
room
CR-ANO-C-2005-1472, August 2, 2005, Units 1 and 2 molded case circuit
breakers in safety-related 480 volt switchgear
CR-ANO-C-2005-1538, August 11, 2005, Units 1 and 2 emergency cooling pond
fish eradication impact on service water systems
The inspectors completed four samples.
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds (71111.16)
a.
Inspection Scope
The inspectors reviewed the two operator workarounds listed below to: (1) determine if
the functional capability of the system or human reliability in responding to an initiating
event is affected, (2) evaluate the effect of the operator workaround on the operators
ability to implement abnormal or emergency operating procedures, and (3) verify that
the licensee has identified and implemented appropriate corrective actions associated
with operator workarounds.
August 9, 2005, Units 1 and 2 ground on Unit 1 Red Train 125V dc bus isolated
to fuses which resulted in the loss of both units control room indications for
switchyard breakers
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Enclosure
August 19, 2005, Unit 2 Operator Work Around 2-05-07 safety injection
Tank 2T-2C losing inventory excessively
The inspectors completed two samples.
b.
Findings
No findings of significance were identified.
1R17
Permanent Plant Modifications (71111.17)
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 will maintain 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.
August 12, 2005, Unit 1 reactor vessel closure head replacement per
ER-ANO-2002-0638-000
The inspectors completed one sample.
b.
Findings
No findings of significance were identified.
1R19
Postmaintenance Testing (71111.19)
a.
Inspection Scope
The inspectors selected the six postmaintenance test activities of risk significant
systems or components listed below. 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
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Enclosure
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 CAP to determine if the
licensee identified and corrected problems related to postmaintenance testing.
March 21, 2005, Unit 2 HPSI Pump 2P-89C, troubleshooting to determine source
of increased vibration levels
June 21, 2005, Unit 1 HPI Pump P-36B inboard motor bearing oiler unqualified
for application
August 16, 2005, Unit 2 excore Channel B power supply switch replacement
August 18, 2005, Units 1 and 2 control room ventilation Valve SV-7910, outside
air makeup damper for control room ventilation Fan VSF-9, replacement
August 19, 2005, Unit 1 instrument air Compressor C-28A air end replacement
August 31, 2005, Unit 2 service water Valve 2CV-1519 stroke failure
The inspectors completed six samples.
b.
Findings
No findings of significance were identified.
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
For the five surveillances listed below, the inspectors reviewed the Updated Safety
Analysis Report, procedure requirements, and Technical Specifications to ensure they
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 Technical Specification operability; (9) test equipment removal;
(10) restoration of plant systems; (11) fulfillment of ASME Code requirements;
(12) updating of performance indicator data; (13) engineering evaluations, root causes,
and bases for returning tested SSCs not meeting the test acceptance criteria were
correct; (14) reference setting data; and (15) annunciators and alarms setpoints. The
inspectors also verified that the licensee identified and implemented any needed
corrective actions associated with the surveillance testing.
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Enclosure
January 1 through July 31, 2005, Unit 2 emergency cooling pond level detection
July 13, 2005, Unit 2 HPSI header check Valve 2SI-12
July 14, 2005, Unit 1 control room emergency ventilation system inlet
Damper CV-7910
August 2, 2005, Unit 2 containment air monitoring system
Instrument 2RITS-8231-1A (Leakage Detection System)
August 25, 2005, Unit 1 low pressure injection Pump P-34B (Inservice Test)
The inspectors completed five samples.
b.
Findings
No findings of significance were identified.
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
For the three temporary modifications listed below, the inspectors reviewed the Updated
Safety Analysis Report, plant drawings, procedure requirements, and Technical
Specifications to ensure that the temporary modifications were properly implemented.
The inspectors: (1) verified that the modification did not have an affect on system
operability/availability, (2) verified that the installation was consistent with the
modification documents, (3) ensured that the postinstallation test results were
satisfactory and that the impact of the temporary modification on permanently installed
SSCs were supported by the test, (4) verified that the modifications were identified on
control room drawings and that appropriate identification tags were placed on the
affected drawings, and (5) verified that appropriate safety evaluations were completed.
The inspectors verified that the licensee identified and implemented any needed
corrective actions associated with temporary modifications.
July 21, 2005, Unit 1 control room emergency ventilation system inlet
Damper CV-7910
July 28, 2005, Unit 2 pressurizer level instrumentation
August 30 through September 1, 2005, Unit 1 makeup Pump P-36A temporary
wall removal
The inspectors completed three samples.
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Enclosure
b.
Findings
No findings of significance was identified.
Cornerstone: Emergency Preparedness
1EP2 Alert Notification System Testing (71114.02)
a.
Inspection Scope
The inspector discussed with the licensee and staff from the Arkansas Department of
Health the status of offsite siren and tone alert radio systems to determine the adequacy
of methods for testing the alert and notification system in accordance with
10 CFR Part 50, Appendix E. The Arkansas Department of Healths alert and
notification system testing program was compared with criteria in NUREG-0654,
"Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and
Preparedness in Support of Nuclear Power Plants," Revision 1, Federal Emergency
Management Agency (FEMA) Report REP-10, "Guide for the Evaluation of Alert and
Notification Systems for Nuclear Power Plants," and the current FEMA-approved alert
and notification system design report. The inspector also reviewed the following
procedures:
"Procedures for Testing, Verification, and Maintenance of the Emergency
Warning System," Arkansas Department of Health, May 2004, Revision 0
Desk Guide EP-002, "Early Warning System," Revision 10
b.
Findings
No findings of significance were identified.
1EP3 Emergency Response Organization Augmentation Testing (71114.03)
a.
Inspection Scope
The inspector reviewed results from two emergency response staffing drills and
reviewed the following documents related to the emergency response organization
augmentation system to determine the licensees ability to staff emergency response
facilities in accordance with the licensee emergency plan and the requirements of
Procedure 1903.062, "Communication System Operating Procedure,"
Revision 18
Form 1903.062C, "Emergency Response Staffing Drill," Revision 18
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Enclosure
b.
Findings
No findings of significance were identified.
1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies (71114.05)
a.
Inspection Scope
The inspector reviewed the following documents related to the licensees CAP to
determine the licensees ability to identify and correct problems in accordance with
10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E.
EN-LI-102, "Corrective Action Process," Revision 1
Emergency Preparedness CR Threshold Criteria, Revision 0
Seven quarterly department assessments
Three Entergy peer group assessments
LO-ALO-2003-234, "Alert Notification System Assessment," December 8, 2003
LO-ALO-2005-033, "Emergency Preparedness Department Program
Assessment," April 2005
Five evaluation reports for full scale drills
Two evaluation reports for emergency preparedness drills
NQ 2004-0026, "Quality Assurance Audit Report QA-7-2004-ANO-1, Emergency
Planning," June 8, 2004
02C-ANO-2003-0055, Quality Assurance Observation
Summaries of 176 corrective actions assigned to the emergency preparedness
department between July 1, 2003, and June 1, 2005
b.
Findings
No findings of significance were identified.
1EP6 Drill Evaluation (71114.06)
a.
Inspection Scope
The two drills listed below contributed to drill/exercise performance and emergency
response organization (ERO) performance indicators. The inspectors: (1) observed the
-20-
Enclosure
training evolution to identify any weaknesses and deficiencies in classification,
notification, and protective action requirements development activities; (2) compared the
identified weaknesses and deficiencies against licensee identified findings to determine
whether the licensee is properly identifying failures; and (3) determined whether licensee
performance is in accordance with the guidance of NEI 99-02, "Regulatory Assessment
Indicator Guideline," Revision 2, documents acceptance criteria.
July 20, 2005, emergency response organization drill involving a station blackout
initiated from the Unit 2 simulator and activating the Technical Support Center,
Emergency Operations Facility, and Operations Support Center
July 27, 2005, emergency response organization drill involving a station blackout
initiated from the Unit 2 simulator and activating the Technical Support Center,
Emergency Operations Facility, and Operations Support Center
The inspectors completed two samples.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
a.
Inspection Scope
The inspector sampled the licensee's performance indicator submittals listed below for
the period October 1, 2004, through March 31, 2005. The definitions and guidance of
NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 2, were used to verify
the licensees basis for reporting each data element in order to verify the accuracy of
performance indicator data reported during the assessment period. Licensee
performance indicator data were also reviewed against the requirements of
Procedures EN-LI-114, "Performance Indicator Process," Revision 0; EN-EP-201,
"Emergency Planning Performance Indicators," Revision 1; and EPJA-EOF-21,
"Emergency Preparedness Performance Indicators," Revision 0.
Emergency Preparedness Cornerstone:
Drill and exercise performance
Emergency response organization participation
Alert and notification system reliability
The inspector reviewed a 100 percent sample of drill and exercise scenarios, licensed
operator simulator training sessions, notification forms, and attendance and critique
records associated with training sessions, drills, and exercises conducted during the
verification period. The inspector reviewed licensee emergency response rosters and
-21-
Enclosure
drill participation records. The inspector reviewed alert and notification system testing
procedures, maintenance records, and a 100 percent sample of siren test records. The
inspector also interviewed licensee personnel responsible for collecting and evaluating
performance indicator data.
b.
Findings
No findings of significance were identified.
4OA2 Problem Identification and Resolution
.1
Emergency Preparedness Annual Sample Review
a.
Inspection Scope
The inspector selected 30 CRs for detailed review. The reports were reviewed to
ensure that the full extent of the issues were identified, an appropriate evaluation was
performed, and appropriate corrective actions were specified and prioritized. The
inspector evaluated the CRs against the requirements of Procedure EN-LI-102,
"Corrective Action Process," Revision 1.
b.
Findings
No findings of significance were identified.
.2
Daily Reviews
a.
Inspection Scope
The inspectors performed a daily review of all condition reports entered into the licensee
corrective action program during this inspection period to identify repetitive failures and
human performance issues. These daily reviews also assessed licensee identification
of issues at the appropriate threshold and entry of these issues into their corrective
action program.
4OA3 Event Followup (71153)
(Closed) Licensee Event Report (LER) 05000368/2002001-00, Reactor Coolant System
Pressure Boundary Leakage Due To Primary Water Stress Corrosion Cracking of
Pressurizer Heater Sleeves
During the Unit 2 refueling outage in April and May 2002, the licensee discovered that
the reactor coolant system had leaked through six pressurizer heater sleeves. The
inspectors previously reviewed these leaks and documented the review in NRC
Inspection Report 05000313/2004002; 05000368/2004002, but this LER was not closed
pending the characterization of the metallurgical flaws which caused these leaks. The
inspectors discovered that the licensee does not intend to characterize the flaws on the
-22-
Enclosure
Unit 2 pressurizer because the existing flaws have been repaired and because they
have planned to replace the pressurizer in Fall 2006. Additionally, the inspectors
reviewed a similar event in NRC Inspection Report 0500313/2005003;
0500368/2005003 (Section 4OA3.2) in which LER 0500368/2005001-00 was closed for
the same issue, leaking pressurizer heater sleeves. For further information of this
previously dispositioned violation, see NRC Inspection Report 0500313/2004002;
00500368/2004002 (Section 4OA3.2) NCV 050036/2004-002, "Ineffective Corrective
Actions to Prevent Recurrence of Primary Water Stress-Corrosion Cracking of Alloy 600
Material." As a result, the inspectors foresee no needed future inspection of this LER.
This LER is closed.
4OA4 Crosscutting Aspects of Findings
Cross-Reference to Human Performance Findings Documented Elsewhere
Section 1R13 describes a condition where maintenance personnel failed to
communicate to Unit 1 operations the status of Door 5, which resulted in operations not
being able to ensure that the required controls were exercised. This same finding also
documents an inadequate work package in that the correct ERs were not listed, which
resulted in risk management actions not being implemented.
Section 1R13 describes a finding where operations personnel incorrectly assumed
isolation of the Unit 1 ERV would have no impact on plant risk, which resulted in an
inadequate risk assessment.
Section 1R14 describes a condition where engineers and work planners did not
adequately research a troubleshooting procedure which resulted in energization of all
Unit 2 pressurizer heaters.
Section 1R14 describes a condition where an inadequate maintenance procedure
resulted in a Unit 2 CEA falling into the core. The procedure lacked the necessary
guidance because the task of transferring control element assemblies to the hold bus
was viewed as skill of the craft even though such evolutions are infrequently
performed.
4OA5 Other Activities
.1
Followup to Operational Readiness of Offsite Power (Temporary
Instruction (TI) 2515/163)
The inspectors conducted followup inspection to TI 2515/163, "Operational Readiness of
Offsite Power," to determine the extent of the licensees written guidance on various
aspects of the TI. The results were forwarded to the Division of Engineering in the
Office of Nuclear Reactor Regulation for further review.
-23-
Enclosure
.2
(Closed) Apparent Violation 05000368/2005003-01, Inadequate Procedure Leads To
Reactor Coolant Pump Seal Damage
Introduction. The inspectors completed the significance determination of the apparent
violation documented in NRC Inspection Report 05000313/2005003 and
05000368/2005003. The apparent violation involved an inadequate procedure related to
the alignment of reactor coolant pump (RCP) seal injection flow when the pump and
motor were uncoupled. An additional entry into reduced reactor coolant system (RCS)
inventory conditions during the refueling outage was necessary to repair the damaged
RCP seal caused by this performance deficiency.
Analysis. The inspectors considered that the failure to have an adequate procedure for
ensuring isolation of seal injection when a Unit 2 reactor coolant pump was uncoupled
was a performance deficiency. Traditional enforcement does not apply for this finding
because it did not have any actual safety consequences or potential for impacting the
NRCs ability to perform its regulatory function nor was it the result of any willful violation
of NRC requirements. The inspectors determined that this finding is greater than minor
because it was associated with the Mitigating Systems Cornerstone configuration control
attribute and affected the cornerstones objective of ensuring the availability, reliability,
and capability of systems that respond to initiating events to prevent undesirable
consequences.
The inspectors used Appendix G, "Shutdown Operations Significance Determination
Process," of MC 0609, "Significance Determination Process," to further determine the
significance of this finding.
Unplanned entry into reduced RCS inventory conditions to repair the RCP seal
represented additional risk incurred above the planned outage risk. The additional risk
associated with the reduced RCS inventory evolution constitutes the additional risk
incurred above the planned outage risk. A Phase 1 screening of the finding was
performed using Appendix G and the Attachment 1 checklists. The finding was not
considered a "Loss of Control" using Table 1. Using Checklist 3, "PWR Cold Shutdown
and Refueling Operation - RCS Open and Refueling Cavity Level < 23' Or RCS Closed
and No Inventory in Pressurizer, Time to Boiling < 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />," in Attachment 1, "Phase 1
Operational Checklists for both PWRs and BWRs," of Appendix G of MC 0609, the
inspectors determined this finding required quantitative assessment because the finding
increased the likelihood of a loss of RCS inventory by requiring an additional entry into a
reduced RCS inventory condition. Therefore, the finding was referred to the regional
senior reactor analyst for further evaluation.
Since the finding did not involve low temperature overpressure protection, nozzle dams,
or boron dilution, the analyst used Appendix G, Attachment 2, "Phase 2 SDP Template
for PWR During Shutdown." The finding involved an additional entry into a high-risk
Plant Operating State (POS). Therefore, as cautioned in Attachment 2, the senior
reactor analyst consulted with staff in the Office of Nuclear Reactor Regulation to
evaluate the change in core damage frequency associated with the finding. The
following is a summary of the analysis that was performed.
-24-
Enclosure
After review of Appendix G and its associated technical basis document MC 0308,
Attachment 3, Appendix G, the analysts concluded that the applicable initiators for this
condition were the loss of offsite power (LOOP), loss of residual heat removal (LORHR),
and loss of inventory (LOI). The analysts considered loss of level control (LOLC) as a
potential initiator, but rejected it because the LOLC worksheet was only applicable to
midloop RCS conditions and the performance deficiency resulted in an additional drain
only to RCP seal replacement elevation. The analysts concluded that solution of each
of the applicable initiator worksheets at their "base case" value was an appropriate
conservative estimation of the increase in risk due to the finding.
The additional entry into reduced inventory conditions occurred approximately 28 days
after shutdown for the refueling outage and lasted approximately 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> (< 3 days).
These conditions correlate to the Late Time Window (TW-L) of POS 2 in the SDP and
were used to solve each of the following initiators:
Worksheet 4, "Loss of Offsite Power in POS 2 (RCS Vented)," was evaluated. The
initiating event likelihood (IEL) for the LOOP initiator for exposure less than 3 days is 3.
The analyst reviewed the top event functions, equipment success criteria, and important
instrumentation identified in Worksheet 4 to determine appropriate equipment credits to
evaluate the core damage sequences. Top event function EAC was assigned a credit of
4, accounting for the emergency and alternate a.c. diesel generators. The analysts
assumed that operator credit was similar to equipment credit for this top event and
made no reduction for operator error. Gravity feed to the RCS was not credited.
Recovery of offsite power was assigned a credit of 1. Quantification of the sequences
by summing the IEL and mitigation credits for each top event function resulted in the
most limiting sequence having a result of 8.
LORHR
Worksheet 9, "Loss of RHR in POS 2 (RCS Vented)," was evaluated. The IEL for the
LORHR initiator for exposure less than 3 days is 3. The analyst reviewed the top event
functions, equipment success criteria, and important instrumentation identified in
Worksheet 9 to determine appropriate equipment credits to evaluate the core damage
sequences. Top event function RHR-S was assigned a credit of 1, which credited
operator ability to start a decay heat removal train prior to RCS boiling. Top event FEED
was assigned a credit of 4 accounting for the multi-train safety injection system and
positive displacement charging pumps. Operator credit was also 4 for this top event, so
no reduction was applied. Top event RHR-R was assigned a credit of 2, consistent with
the worksheet for being operator-action limited. Top event RWSTMU was also assigned
a credit of 2, consistent with the worksheet for being operator-action limited.
Quantification of the sequences by summing the IEL and mitigation credits for each top
event function resulted in the most limiting sequence having a result of 8.
-25-
Enclosure
Worksheet 6, "Loss of Inventory in POS 2 (RCS Vented)," was evaluated. The IEL for
the LOI initiator for exposure less than 3 days is 4. The analyst reviewed the top event
functions, equipment success criteria, and important instrumentation identified in
Worksheet 6 to determine appropriate equipment credits to evaluate the core damage
sequences. Top event function FEED was assigned a credit of 4 accounting for the
multi-train safety injection system and positive displacement charging pumps. Operator
credit was also 4 for this top event, so no reduction was applied. Top event LEAK-
STOP was assigned a credit of 3, limited by operator action. Top event RHR-R was
assigned a credit of 3, consistent with the worksheet for being operator-action limited.
Top event RWSTMU was assigned a credit of 2, consistent with the worksheet for being
operator-action limited. Quantification of the sequences by summing the IEL and
mitigation credits for each top event function resulted in the most limiting sequence
having a result of 8.
Result
The risk significance of the finding from this point is determined in the same manner as
for at-power findings. Using MC 0609, Appendix A, Step 2.4, "Estimating the Risk
Significance of Inspection Findings," the analyst summed the quantified sequences and
determined that the total increase in core damage frequency associated with this finding
due to internal initiating events was estimated as 1E-7/year using the counting rule. No
screening for potential contribution due to external events or large early release
frequency was performed because of the assumed conservative upper-bound screening
result provided by the SDP worksheets. Therefore, this was a finding of very low safety
significance (Green). Contributing to this result was that (1) the seal replacement
activity required RCS draindown to reduced inventory conditions and not to midloop
conditions, (2) the time needed to replace the seal was not extensive and, (3) the time
after shutdown provided additional time available for successful operator actions.
Enforcement. The inspectors determined that since Procedure 2103.002, "Filling and
Venting the Reactor Coolant System," Revision 39, was inadequate, it did not meet the
requirements of Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, and as
a result the licensee did not meet Unit 2 Technical Specification 6.4.1, "Procedures."
Because of the very low safety significance of this finding and because the licensee
included this condition in their CAP as CR ANO-2-2005-0545, this violation is being
treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000368/2005004-07, "Inadequate Procedure Leads To Reactor Coolant Pump
Seal Damage."
-26-
Enclosure
4OA6 Meetings, Including Exit
On July 1, 2005, the inspector presented the emergency planning inspection results to
Mr. J. Forbes, Vice President, Operations, and other members of the licensee's staff
who acknowledged the findings. The inspector confirmed that proprietary information
was not provided or examined during the inspection.
The inspectors debriefed the licensee's operator requalification inspection results with
Ms. S. Cotton, Training Manager, and other members of the licensees staff at the
conclusion of the inspection on July 15, 2005. The licensee acknowledged the findings
presented. A telephone exit was held with Mr. R. Martin, Unit 1 Operations Training
Supervisor, acting for Ms. S. Cotton, on August 17, 2005. He was advised that the
inspectors had completed reviewing the results of the annual requalification test results
for Unit 2 and the biennial requalification test results for Unit 1. The inspectors asked
the licensee whether any materials examined during the inspection should be
considered proprietary. No proprietary information was identified.
The inspectors presented the inspection results to Mr. J. Forbes, Vice President,
Operations, and other members of the licensee's staff at the conclusion of the heat sink
performance biennial inspection on September 12, 2005, during a telephonic exit. No
proprietary information was reviewed.
The resident inspectors presented the inspection results of the resident inspections to
Mr. J. Forbes, Vice President, Operations, and other members of the licensee's
management staff on September 28, 2005. The licensee acknowledged the findings
presented. The inspectors noted that while proprietary information was reviewed, none
would be included in this report.
4OA7 Licensee-Identified Violations
The following two examples of a violation of very low safety significance (Green) were
identified by the licensee and are violations of NRC requirements which meet the criteria
of Section VI of NUREG-1600, "NRC Enforcement Policy," for being dispositioned as
NCV.
10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that
measures shall be established for the selection and review of materials, parts,
equipment, and processes that are essential to safety-related functions. The licensee
violated this requirement on two occasions. The first example, which occurred on
March 21, 2005, during the Unit 2 HPSI Pump 2P-89C disassembly troubleshooting, to
determine the source of increased vibration levels, the licensee discovered that a carbon
steel set screw had been installed in place of a stainless one required by design
specifications. This event is documented in the licensees CAP as
CR ANO-2-2005-0775. This finding is of very low safety significance because the
safety-related function of the HPSI system was never lost. The second example, which
occurred on June 21, 2005, during the Unit 1 HPI Pump P-36B gearbox rebuild, the
licensee installed an unqualified bearing oiler on the inboard motor bearing which
-27-
Enclosure
caused increased vibrations of the oiler. This event is documented in the licensees
CAP as CR ANO-1-2005-0884. This finding is of very low safety significance because
the safety-related function of the HPI system was never lost.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Attachment 1
A-1
KEY POINTS OF CONTACT
Licensee Personnel
R. Barnes, Manager, Planning and Scheduling
S. Bennett, Project Manager, Licensing
B. Berryman, Manager, Unit 1 Operations
E. Blackard, Supervisor, Mechanical Design Engineering
J. Browning, Manager, Unit 2 Operations
R. Byford, Training Supervisor/Operations Training
A. Clinkingbeard, U-1 Operations Training Assistant Operations Manager
S. Cotton, Manager, Training
S. Cupp, Simulator Support Supervisor
J. Eichenberger, Manager, Corrective Actions and Assessments
J. Forbes, Vice President, Operations
N. Finney, Technical Specialist IV, Non-Destructive Examination
M. Ginsberg, Supervisor, Design Engineering
A. Hawkins, Licensing Specialist
J. Hoffpauir, Manager, Maintenance
R. Holeyfield, Manager, Emergency Planning
I. Jacobson, System Engineer
D. James, Acting Director, Nuclear Safety Assurance
W. James, Manager, Alloy 600 Group
J. Johnson, Fire Protection Technical Specialist
J. Kowalewski, Director, Engineering
R. Kowalewski, Manager, Technical Support
D. Lomax, Manager, Dry Fuels
R. Martin, U-1 Operations Training Supervisor
T. Mayfield, U-2 Operations Training Supervisor
J. Miller, Manager, Systems Engineering
T. Mitchell, Acting General Manager, Plant Operations
D. Moore, Manager, Radiation Protection
K. Nichols, Manager, Design Engineering
R. Puckett, Fire Protection Supervisor
S. Pyle, Licensing Specialist
C. Reasoner, Manager, Engineering Programs and Components
R. Scheide, Licensing Specialist
J. Sigle, U-2 Acting Operations Manager
C. Tyrone, Manager, Quality Assurance
F. Van Buskirk, Licensing Specialist/ANO Licensing
B. Williams, Director, Reactor Vessel Head/SG Replacement Project
C. Meyer, Nuclear Planning and Response Program Manager
Attachment 1
A-2
NRC
R. Kahler, NSIR/DPR/EPD, Team Leader
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Failure to Comply with Licensing Basis for EFW Pump
Room Fire Sprinklers (Section 1R05)05000313/2005004-02
Absence of ICS Relay Room Fire Sprinklers
(Section 1R05)
Opened and Closed
Failure to Adequately Assess Risk for a Blocked Decay
Heat Vault Door (Section 1R13)05000313/2005004-04
Failure to Adequately Assess Risk for an Isolated
Pressurizer ERV (Section 1R13)05000368/2005004-05
Failure to Adequately Scope the Effects of Maintenance
on Pressurizer Level Instrumentation (Section 1R14)05000368/2005004-06
Inadequate Maintenance Procedure Results in Dropped
CEA (Section 1R14)05000368/2005004-07
Inadequate Procedure Leads to Reactor Coolant Pump
Seal Damage (Section 4OA5)
Closed
05000368/2002-001-00
LER
Reactor Coolant System Pressure Boundary Leakage
Due to Primary Water Stress Corrosion Cracking of
Pressurizer Heater Sleeves (Section 4OA3)05000368/2005003-01
Inadequate Procedure Leads to Reactor Coolant Pump
Seal Damage (Section 4OA5)
Discussed
None
Attachment 1
A-3
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 1R04: Equipment Alignment
CRs
ANO-2-2004-0620
ANO-2-2004-0702
ANO-2-2004-0837
ANO-2-2004-0922
ANO-2-2004-0936
ANO-2-2004-1704
ANO-2-2004-2054
ANO-2-2004-2055
ANO-2-2004-2091
ANO-2-2005-0387
ANO-2-2005-1193
ANO-2-2005-1424
ANO-2-2005-1921
ANO-2-2005-1927
Operating Procedures
NUMBER
TITLE
REVISION
2104.005
43
Miscellaneous
NUMBER
TITLE
ULD-2-SYS-05
Arkansas Nuclear One Upper Level Document ANO
Unit 2 Containment Spray System
3
Section 1R05: Fire Protection
CRs
ANO-1-2005-0954
ANO-1-2005-1197
Engineering Calculation
85-E-0053-15, Revision 45
Miscellaneous Documents
NUMBER
TITLE
REVISION
DCP 87-D-1051
EFW Pump Room Fire Suppression System
0
Engineering
Report A-FP-2005-001
Fire Protection Appendix R Detection & Suppression
Partial 86-10 Evaluation
0
Standard for Water Spray Fixed Systems for Fire
Protection
1985
Edition
Attachment 1
A-4
Standard for Water Spray Fixed Systems for Fire
Protection
2001
Edition
NRC Information Notice 2002-24
Potential Problems with Heat Collectors on Fire
Protection, Sprinklers
July 19,
2002
0CAN088404
Results of Reanalysis Against NRC
Clarification/Interpretation of Appendix R to
August 15,
1984
0CAN088508
Results of Reanalysis Against NRC
Clarification/Interpretation of Appendix R to
10 CFR Part 50 - Supplemental Information
August 30,
1985
10 CFR Part 50 Appendix R Exemption Request
(Zone 38-Y)
April 22,
1987
10 CFR Part 50 Appendix R Exemption Request
(Zone 38-Y)
June 24,
1987
1CNA108806
Exemptions from the Technical Requirements of
Appendix R to 10 CFR Part 50 - Arkansas Nuclear
One, Unit 1 (TAC NO. 55669)
October 26,
1988
Operating Procedures
NUMBER
TITLE
REVISION
Arkansas Nuclear One Fire Hazards Analysis Report
9
Unit 1 Prefire Plans 1A-372-100-N
2
1000.152
Unit 1 & 2 Fire Protection System Specifications
3
1203.002
Alternate Shutdown
15
1203.049
Fires in Areas Affecting Safe Shutdown
2
Plant Drawings
NUMBER
TITLE
REVISION
Fire Zones Intermediate Floor Plan at Elev. 368' - 0"
and 372' - 0"
24, Sheet 1
Fire Zone Plan Below Grade Elev. 335' - 0"
18, Sheet 1
Fire Zones Intake Structure
10, Sheet 1
Fire Zones Intermediate Floor Plan Elev. 368' - 0"
26, Sheet 1
Attachment 1
A-5
Section 1R06: Flooding
Engineering Report
92-R-0024-01
Section 1R07: Heat Sink Performance
Operating Procedures
NUMBER
TITLE
REVISION
2311.002
Service Water System Flow Test
14
Corrective Action Process
2
Unit 1 and Unit 2 Service Water and Circulating Water
Optimization Plan
1
Specifications
ANO FSAR Unit 2, Section 6.3.4, "Tests and Inspections"
ERs
NUMBER
TITLE
REVISION
ANO-2004-0294-000
Decay Heat Cooler Thermal Test Evaluation
0
ANO-2005-0287-000
2R17 As Left Test Evaluation
0
991457-E205-0
Service Water Flow Testing
0
ANO-2004-0294-000
1R18 E-35A Decay Heat Cooler Thermal Test
Evaluation
0
CRs
ANO-1-2004-0831
ANO-2-1999-0211
ANO-2-1999-0219
ANO-2-1999-0254
ANO-2-1999-0580
ANO-2-1999-0535
ANO-2-1999-0559
Calculations
NUMBER
TITLE
REVISION
88-E-0098-16
Revised Containment Cooler Data for ANO
001
94-E-0095-18
Room 2007/2009 Heat Load Evaluation
0
88-E-0098-20
Heat Load Evaluation
0
88-E-0098-20
ANO-1 DBA Analysis
1
Attachment 1
A-6
98-E-0022-05
Decay Heat Removal Cooler E-35B 1R16 Thermal
Performance Test
001
94-E-0095-2014
Heat load Evaluation
1
98-E-0022-03
Decay Heat Removal Cooler E-35A 1R15 Thermal
Performance Test
0
Decay Heat Removal Cooler E-35B 1R215 Thermal
Performance Test
0
Testing Procedures and Results
NUMBER
TITLE
REVISION
98-E-0022-02
Decay Heat Removal Cooler E-35A, Thermal
Performance Test
0
98-E-0022-04
Decay Heat Removal Cooler E35B, 1R15, Thermal
Performance Test
0
98-E-0022-03
Decay Heat Removal Cooler E-35A,1R15, Thermal
Performance Test
0
Decay Heat Removal Cooler E-35B, 1R16, Thermal
Performance Test
0
Section 1R11: Licensed Operator Requalification
OLTS Report 9 list (NRC)
ANO Unit 1 licensed operator training list
Open Simulator Discrepancy Report (reviewed all 44 records)
Closed Simulator discrepancy report from January 2003 through July 11, 2005 (reviewed
600 records) with the following detailed package reviews:
DR 05-0079, closed, topic was emergency diesel generator loading rates
DR 05-0081, closed, topic was main turbine response to loss of all steam
DR 02-0244, closed, topic was heater drain pump impact on main feed system flows
and pressures
DR 03-0073, closed, topic was heater drain tank level and recirc valve position
DR 03-0090, closed, topic was heater drain tank level control after drain pump trip
DR 03-0117, closed, topic was heater drain tank high level bypass capacity
Attachment 1
A-7
DR 03-0202, closed, topic was OTSG levels posttrip
DR 05-0075, closed, topic was reactor trip setpoints
LER 50-313-2003-001, August 29, 2003, "Reactor Trip due to Automatic Actuation of the
Reactor Protection System on High Reactor Coolant System Pressure and Actuation of the
EFW System Resulting from a Lightning-Induced Closure of the Main Turbine Governor Valves,"
Corresponding simulator file, Attachment R-15
Annual Operability Test packages
Steady state power test (100 percent)
Transients Reviewed:
Simultaneous closure of both main steam isolation valves
Trip of one reactor coolant pump
Maximum rate power ramp
Real time test package
SBT package - reviewed one scenario package with a loss of offsite power as the main event
Simulator Core Reload Acceptance Test, DG-TRNA-015-CORETEST, Revision 0, with
enclosed Unit 1 attachments
Simulator CAE file for Heater Drain Pump B trip test, Attachment R-14
STM 1-20, Figure 20-01, "Simplified Condensate System," Revision 7
PID 205, Sheet 2, "Condensate System"
Latest PSA Risk Table for Unit 1 Highest Risk Operator Actions, October 2004
Simulator Modification Control, DG-TRNA-015-SIMCONTROL, Revision 0
Simulator Configuration Control, EN-TQ-202, Revision 0
Scenarios: SES-1-004, SES-1-019
JPMs A1JPM-RO-EOP01, -EOP04, -PZR02, -EAL06, -AOP14, and -EDG05
Operations On-Shift Training Instruction Plan: "Mode 3 Operation Contingencies"
Operating Procedures
NUMBER
TITLE
REVISION
1063.008
Operations Training Sequence
34
Systematic Approach to Training
0
TQF-201-1M05
Remedial Training Plan
2
ENS-NS-112
Medical Program and Physicals
3
Attachment 1
A-8
CR ANO-1-2003-00796, P-8A heater drain pump trip on July 25, 2003
Root Cause Analysis Report, "P-8A Heater Drain Pump Motor Winding Failure,"
September 10, 2003
CR ANO-1-2003-00987, P-8B heater drain pump trip on September 19, 2003
Root Cause Analysis Report, "Failure to Meet Reactivity Management Expectations," dated
December 1, 2004
Section 1R12: Maintenance Effectiveness
CRs
ANO-2-2003-1257
ANO-2-2003-1567
ANO-2-2003-1574
ANO-2-2003-1575
ANO-2-2003-1591
ANO-2-2003-1680
ANO-2-2004-0041
ANO-2-2004-0379
ANO-2-2004-0389
ANO-2-2004-0784
ANO-2-2004-1103
ANO-2-2004-1916
ANO-2-2005-0385
ANO-2-2005-0414
ANO-2-2005-0807
ANO-2-2005-0995
ANO-2-2005-2006
ANO-2-2005-2111
Miscellaneous
Maintenance Rule Database, Unit 2 HPSI
System Performance Indicator, HPSI - Arkansas Unit 2
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
CR
ANO-C-2005-1205
ERs
963555 I103
963555 R101
963555 R112
ANO-1996-3555-056
Miscellaneous
MAI 74687
Procedures
NUMBER
TITLE
REVISION
1000.152
Unit 1 & 2 Fire Protection System Specifications
3
1000.120
ANO Fire Watch Program
10
COPD024
Risk Assessment Guidelines
16
Attachment 1
A-9
Section 1R14: Operator Performance During Nonroutine Plant Evolutions and Events
CRs
ANO-2-2005-1969
ANO-2-2005-2193
ANO-2-2005-2191
ANO-2-2005-2192
Operating Procedures
NUMBER
TITLE
REVISION
2203.003
CEA Malfunction
15
2105.009
CEDM Control System Operation
21
Section 1R16: Operator Workarounds
CR
ANO-C-2005-1520
Section 1R19: Postmaintenance Testing
CRs
ANO-1-2005-0884
ANO-1-2005-0895
ANO-1-2005-0900
ANO-1-2005-1208
ANO-2-1997-0055
ANO-2-2005-0385
ANO-2-2005-0659
ANO-2-2005-0747
ANO-2-2005-0775
ANO-2-2005-0782
ANO-2-2005-0948
ANO-2-2005-1673
ANO-2-2005-1754
ANO-2-2004-1923
ANO-C-2005-1593
ER
ANO-2002-0083-000
Work Orders
00057097 03
00063471 01
00063618 01
00064655 01
00069039 01
00071184 01
00071637 01
00071637 03
50254113 01
50967812 01
50976843 01
50976851 01
50999668 01
51006765 01
51006909 01
51007157 01
Attachment 1
A-10
Section 1R22: Surveillance Testing
CRs
ANO-C-2004-0353
ANO-C-2005-1218
ER
ANO-2003-0235, Revisions 0 and 1
Miscellaneous
NUMBER
TITLE
REVISION
TD V085.0080
Maintenance Manual for Velan 2 1/2" - 24" Forged
Bolted Bonnet Gate and Globe Valves and Bolted
Cover Check Valves
N/A
TD V085.0040
Maintenance Manual for Velan 2" - 24" Cast and
Forged Pressure Seal Gate, Globe Parallel Slide and
N/A
TD V085.0060
Instruction Manual for Installation, Operation and
Maintenance of Velan Pressure Seal Forged Gate,
Stop, Stop Check, and Check Valves
N/A
Operating Procedures
NUMBER
TITLE
REVISION
2104.005
43
2104.007
Control Room Emergency Air Conditioning and
Ventilation
27
2104.039
HPSI System Operation
42
2304.006
Unit 2 Gaseous Process Radiation Monitoring
System Calibration
17
2304.016
Unit 2 Process Radiation Monitoring Monthly Test
16
2402.143
Disassembly, Inspection and Reassembly of 2SI-12
1
Work Orders
00067969 02
50618124 01
50967615 01
50967812 01
51003781 01
Attachment 1
A-11
1EP2: Alert and Notification System Testing
Alert and Notification System Report for Arkansas Nuclear One, Revised February 13, 1996
1EP3: Emergency Response Organization Augmentation
Emergency Response Staffing Drill, December 2004
Emergency Response Staffing Drill, December 2003
1EP5: Correction of Emergency Preparedness Weaknesses and Deficiencies
Quarterly Self Assessment Report, Fourth Quarter 2003
Quarterly Self Assessment Report, First Quarter 2004
Quarterly Self Assessment Report, LO-ALO-C-2004-145
Biennial Roll-Up Report, Second and Third Quarters 2004
Quarterly Self Assessment Report, Fourth Quarter 2004
Peer Group Assessment, November 17, 2003
Peer Group Assessment, 2004 Dress Rehearsal Exercise
Peer Group Assessment, 2004 Biennial Evaluated Exercise
EP 2003-0064, Full Scale Drill, November 5, 2003
EP 2004-0037, Full Scale Drill, September 15, 2004
EP 2004-0045, Full Scale Drill, October 20, 2004
EP 2004-0053, Full Scale Drill, November 17, 2004
EP 2005-0011, Full Scale Drill, June 1, 2005
EP 2004-0050, Environmental Sampling Drill, November 19, 2004
EP 2004-0051, PASS Drill, December 1, 2004
4OA1: Performance Indicator Verification
EPIP 1903.011, "Emergency Response/Notifications," Attachment 6, "Protective Actions for
General Emergency," Revision 28-00-0
Drill Schedule, 2004
Drill Schedule, 2005
Entergy Nuclear South EP Exercise and Drill Guide, October 2001
Desk Guide EP-006, "Drill/Exercise Manual Addendum," April 2005, Revision 2
Attachment 1
A-12
LIST OF ACRONYMS
Arkansas Nuclear One
corrective action program
control element assembly
CFR
Code of Federal Regulations
CR
condition report
emergency feedwater
ER
engineering request
electromatic relief valve
GPD
gallons per day
high pressure injection
high pressure safety injection
instrumentation and control
integrated control system
LER
licensee event report
MC
manual chapter
noncited violation
National Fire Protection Association
structure, system, and component
TI
temporary instruction
unresolved item
Attachment 2
A2-1
ATTACHMENT 2
PHASE 3 EVALUATION, DAMAGED REACTOR COOLANT PUMP SEAL ARKANSAS
NUCLEAR ONE, UNIT 2