ML120450828
| ML120450828 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 02/14/2012 |
| From: | Allen D NRC/RGN-IV/DRP/RPB-E |
| To: | Schwarz C Entergy Operations |
| References | |
| IR-11-005 | |
| Download: ML120450828 (67) | |
See also: IR 05000313/2011005
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I V
1600 EAST LAMAR BLVD
ARLINGTON, TEXAS 76011-4511
February 14, 2012
Christopher J. Schwarz, Site Vice President
Arkansas Nuclear One
Entergy Operations, Inc.
1448 SR 333
Russellville, AR 72802-0967
SUBJECT: ARKANSAS NUCLEAR ONE - NRC INTEGRATED INSPECTION REPORT
NUMBER 05000313/2011005 AND 05000368/2011005
Dear Mr. Schwarz:
On December 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at the Arkansas Nuclear One facility Units, 1 and 2. The enclosed inspection report
documents the inspection results which were discussed on January 20, 2012, with Mr. M.
Chisum, General Manager, Plant Operations, and other members of your staff.
The inspections examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Two NRC identified and four self-revealing findings of very low safety significance (Green) were
identified during this inspection.
Five of these findings were determined to involve violations of NRC requirements. Further, two
licensee-identified violations which were determined to be of very low safety significance are
listed in this report. The NRC is treating these violations as noncited violations (NCVs)
consistent with Section 2.3.2 of the Enforcement Policy.
If you contest these noncited violations, you should provide a response within 30 days of the
date of this inspection report, with the basis for your denial, to the Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the
Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at
Arkansas Nuclear One.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a
response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at
Arkansas Nuclear One.
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 available electronically for public inspection in the
C. Schwarz -2-
NRC Public Document Room or from the Publicly Available Records (PARS) component of
NRC's Agencywide Document Access and Management 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/
Donald B. Allen, Branch Chief
Project Branch E
Division of Reactor Projects
Docket Nos: 05000313, 05000368
Enclosure: Inspection Report 05000313/2011005 and 05000368/2011005
w/ Attachment: Supplemental Information
cc w/ encl: Electronic Distribution
C. Schwarz -3-
DISTRIBUTION:
Regional Administrator (Elmo.Collins@nrc.gov)
Deputy Regional Administrator (Art.Howell@nrc.gov)
DRP Director (Kriss.Kennedy@nrc.gov )
DRP Deputy Director (Troy.Pruett@nrc.gov)
DRS Director (Anton.Vegel@nrc.gov )
DRS Deputy Director (Tom.Blount@nrc.gov)
Senior Resident Inspector (Alfred.Sanchez@nrc.gov)
Resident Inspector (Jeff.Rotton@nrc.gov )
Resident Inspector (William.Schaup@nrc.gov)
Branch Chief, DRP/E (Don.Allen@nrc.gov)
Senior Project Engineer, DRP/E (Ray.Azua@nrc.gov)
Project Engineer (Jim.Melfi@nrc.gov)
Project Engineer (Dan.Bradley@nrc.gov)
ANO Administrative Assistant (Gloria.Hatfield@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Project Manager (Kaly.Kalyanam@nrc.gov)
Branch Chief, DRS/TSB (Ryan.Alexander@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
ACES (Heather.Gepford@nrc.gov)
OEMail Resource
ROPreports
OEDO RIV Coordinator (Lydia.Chang@nrc.gov)
NSIR/DPR/EP (Eric.Schrader@nrc.gov)
Regional State Liaison Officer (Bill.Maier@nrc.gov)
R:\_REACTORS\_ANO\2011\ANO2011005-RP-AS.docx
SUNSI Rev Compl. Yes No ADAMS Yes No Reviewer Initials DBA
Publicly Avail Yes No Sensitive Yes No Sens. Type Initials DBA
SRI:DRP/E RI:DRP/E RI:DRP/E SPE:DRP/E C:DRS/EB1 C:DRS/EB2
FSanchez JRotton WSchaup RAzua TFarnholtz GMiller
/RA via Email/ /RA via /RA via /RA/ /RA/ /RA/
Email/ Email/
2/10/12 2/10/12 2/10/12 2/10/12 2/13/12 2/13/12
C:DRS/OB C:DRS/PSB1 C:DRS/PSB2 C:DRS/TSB C:DRP/E
MHaire MHay GWerner DPowers DAllen
/RA/ /RA/ /RA/ /RA/ /RA/
2/13/12 2/13/12 2/13/12 2/13/12 2/14/12
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 05000313; 05000368
Report: 05000313/2011005; 05000368/2011005
Licensee: Entergy Operations Inc.
Facility: Arkansas Nuclear One, Units 1 and 2
Location: Junction of Hwy. 64 West and Hwy. 333 South
Russellville, Arkansas
Dates: October 1 through December 31, 2011
Inspectors: A. Sanchez, Senior Resident Inspector
J. Rotton, Resident Inspector
W. Schaup, Resident Inspector
G. Guerra, CHP, Emergency Preparedness Inspector
R. Kopriva, Senior Reactor Inspector
M. Williams, Reactor Inspector
Approved By: Don Allen, Chief, Project Branch E
Division of Reactor Projects
-1- Enclosure
SUMMARY OF FINDINGS
IR 05000313/2011005; 05000368/2011005; 10/1/2011-12/31/2011; Arkansas Nuclear One
Integrated Resident and Regional Report; Operability Evaluations and Functionality
Assessments; Refueling and Other Outage Activities; Problem Identification and Resolution.
The report covered a 3-month period of inspection by resident inspectors and announced
baseline inspections by region-based inspectors. Five Green noncited violations of significance
were identified. The significance of most findings is indicated by their color (Green, White,
Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process.
The cross-cutting aspect is determined using Inspection Manual Chapter 0310, Components
Within the Cross Cutting Areas. Findings for which the significance determination process
does not apply may be Green or be assigned a severity level after NRC management review.
The NRC's program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
A. NRC-Identified Findings and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green. The inspectors identified a noncited violation of Unit 1 Technical
Specification 3.8.4, DC Sources-Operating, Technical Specification 3.8.7,
Inverters- Operating, and Technical Specification 3.8.9, Distribution Systems-
Operating, due to the licensees failure to complete the associated required
action prior to the specified completion time while the associated emergency
switchgear room chillers were out of service for planned maintenance. The
licensee immediately implemented corrective actions to direct Operations to
enter the applicable technical specifications and notify ANO management. The
issue was identified to the licensee and entered into their corrective action
program as Condition Report CR-ANO-1-2012-0043.
The inspectors determined that not completing the required actions for the
applicable technical specifications prior to the specified completion time while the
associated emergency switchgear room chillers were out of service for planned
maintenance is a performance deficiency. The performance deficiency is
determined to be more than minor because it is associated with the equipment
performance attribute of the Mitigating Systems Cornerstone, and adversely
affects the associated cornerstone objective to ensure availability, reliability, and
the capability of systems that respond to initiating events to prevent undesirable
consequences and is therefore a finding. Specifically, on December 7, 2011, the
failure to complete the required actions prior to the specified completion times for
Technical Specification 3.8.4, DC Sources - Operating, Technical Specification 3.8.7, Inverters - Operating, and Technical Specification 3.8.9, Distribution
Systems - Operating, after removing the VCH-4A from service for maintenance
was a violation of technical specifications. Additionally, on December 19, 2011,
the failure to complete the required actions prior to the specified completion time
for Technical Specification 3.8.7, Inverters - Operating, after removing the
-2- Enclosure
VCH-4B from service for maintenance, was a violation of technical specifications.
Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and
Characterization of Findings, the finding was determined to require a Phase 2
analysis because removing each VCH-4 chiller from service in December 2011
did result in an actual loss of safety function of a single train for greater than its
technical specification allowed completion time. A phase 2 analysis from a
previous noncited violation that bounds this issue determined the finding to be of
very low safety significance (Green). Specifically, although the function was lost
by the designated support equipment (emergency switchgear chillers), the
licensee had an evaluation that credited compensatory measures and specific
environmental conditions that assured the overall functionality of the applicable
switchgear train was not lost. The finding was determined to have a cross-
cutting aspect in the area of human performance, associated with the decision
making component, in that the licensee did not use conservative assumptions in
decision making and adopt a requirement to demonstrate that the proposed
action is safe in order to proceed rather than a requirement that it is unsafe in
order to disapprove the action H.1(b) (Section 1R15).
- Green. The inspectors documented a self-revealing, noncited violation of
10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for the licensees
failure to promptly identify and correct a condition adverse to quality associated
with degradation of the protective wrap (brand name - Denso) installed on the
Unit 1 service water pump columns. The Denso protective wrap around the P-4C
service water pump suction column became unraveled and was drawn into the
pump suction while running and caused high differential pressure across the
pump discharge strainer. The licensee took immediate corrective action to secure
the pump and then removed the Denso protective wrap from all pump columns in
the Unit 1 service water intake structure bays. Unit 2 does not have Denso
protective wrap installed on their service water pumps. The licensee has entered
this issue into their corrective action program as Condition Report CR-ANO-1-
2011-2843.
The failure to promptly identify and correct the observed degradation of the
protective wrap installed on the Unit 1 service water pump columns is determined
to be a performance deficiency. The performance deficiency is determined to be
more than minor because it is associated with the equipment performance
attribute of the Mitigating Systems cornerstone and adversely affects the
cornerstone objective to ensure availability, reliability, and the capability of
systems that respond to initiating events to prevent undesirable consequences
and is therefore a finding. The inspectors performed the significance
determination for the failure of service water pump 4C using NRC Inspection
Manual Chapter 0609, Attachment 0609.04, Phase 1 - Initial Screening and
Characterization of Findings. The problem had occurred during an outage, but it
could have occurred at power during a system realignment. The at-power model
was more conservative, so it was used to evaluate the finding. Service water
was a two train system with a swing pump (an installed spare). The allowed
outage time for one train was 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Operators could easily align the swing
-3- Enclosure
pump to provide the train B service water loads within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Therefore, this
finding screened to Green because: 1) it was not a design or qualification
deficiency; 2) it did not result in loss of safety function of one train of equipment
for more than its technical specification allowed outage time; 3) It did not result in
a loss of one train of non-technical specification equipment; and 4) it did not
screen as potentially risk significant due to an external event. The finding was
determined to have a cross-cutting aspect in the area of problem identification
and resolution, associated with the corrective action program component in that
the licensee failed to thoroughly evaluate the degraded protective wrap such that
the resolutions addressed causes and extent of conditions, to include operability
of the service water pump P.1(c) (Section 1R20.2).
- Green. The inspectors documented a self revealing, noncited violation of Unit 1
Technical Specification 5.4.1.a for the failure to implement station procedure
OP-1015.049 Configuration Control Program, Revision 1. Specifically, on
multiple occasions, station personnel failed to maintain configuration control
through the use of valve line-ups and station procedures to ensure reactor plant
components were in required positions. In each specific example the licensee
took action to place the applicable system in a safe configuration. The licensee
is implementing long term programmatic corrective actions. The licensee has
placed that issue into their corrective action program as Condition Report
CR-ANO-C-2011-2942.
The failure of station personnel to maintain configuration control through the use of
valve line-ups and governing station procedures is a performance deficiency. The
performance deficiency is more than minor because it is associated with the
configuration control attribute of the Mitigating Systems cornerstone and adversely
affects the cornerstone objective to ensure the availability, reliability and capability
of systems that respond to initiating events to prevent undesirable consequences
and is therefore a finding. Using Manual Chapter 0609.04, Phase 1 - Initial
Screening and Characterization of Findings, the examples included an actual loss
of safety function of a non-technical specification train of equipment designated as
risk-significant per 10CFR50.65, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A Phase 3 significance
determination analysis was performed by a Region IV senior reactor analyst. The
dominant core damage sequences for Unit 1 were station blackouts with battery
depletion and transients with loss of feedwater and feed and bleed capability. The
dominant core damage sequences for Unit 2 were station blackout with loss of
emergency feedwater and once-through-cooling, loss of 4160 volt vital bus 2A4
with loss of feedwater and once-through-cooling, and station blackout with an 8-
hour battery depletion. Based on both units having the capability to operate a
steam driven emergency feedwater pump during the dominate core damage
sequences the finding was determined to have very low safety significance
(Green). The finding was determined to have a cross-cutting aspect in the area of
human performance, associated with the work practices component in that the
licensee failed to define and effectively communicate expectations regarding
procedural guidance and personnel follow procedures when performing component
positioning H.4(b) (Section 4OA2.4).
-4- Enclosure
Cornerstone: Barrier Integrity
- Green. The inspectors documented a self-revealing, noncited violation of Unit 1
Technical Specification 5.4.1.a for the failure to implement station procedure
OP-1104.006 Spent Fuel Cooling System, Revision 51. Specifically, SF-10,
flow control to purification loop valve, was found 3 turns open when it was
required to be closed. This resulted in the spent fuel pool level lowering by
0.6 feet, which was below procedural limits, when the fuel transfer canal was
placed in purification and SF-45, transfer tube isolation valve, was closed to
support diving operations in the Unit 1 spent fuel pool tilt pit. After receiving the
spent fuel pool low level alarm, operations personnel secured purification, and
opened SF-45 which allowed water level to return to normal. Additional actions
taken by the licensee included identifying that SF-10 requires a torque amplifying
device to operate. The issue was entered into the licensees corrective action
program as Condition Report CR-ANO-1-2011-2498.
The failure of operations personnel to follow the requirements of procedure
OP-1104.006 and close SF-10 prior to initiating fuel transfer canal on purification,
which resulted in an unexpected loss of approximately 4500 gallons of water
from the spent fuel pool, is a performance deficiency. The performance
deficiency is more than minor because it is associated with the configuration
control attribute of the Barrier Integrity cornerstone and adversely affects the
cornerstone objective to provide reasonable assurance that physical design
barriers protect the public from radionuclide releases caused by accidents or
events and is therefore a finding. Using Manual Chapter 0609.04, Phase 1 -
Initial Screening and Characterization of Findings, the finding was determined to
have very low safety significance (Green) because the finding did not result in the
loss of spent fuel cooling, did not result from fuel handling errors that caused
damage to the fuel clad integrity or a dropped assembly and did not result in a
loss of spent fuel inventory of greater than 10 percent of the spent fuel pool
volume. The finding was determined to have a cross-cutting aspect in the area
of human performance, associated with the work control component in that the
licensee failed to ensure that work activities were appropriately coordinated to
support long term equipment reliability by limiting operator work-arounds when a
torque amplifying device was required to shut SF-10 H.3(b) (Section 1R20.1).
- Green. The inspectors identified a noncited violation of 10 CFR 50, Appendix B,
Criterion XVI for failure to identify and correct a condition adverse to quality.
Specifically, on November 1, 2011, the licensee failed to identify and correct a
condition associated with seating an irradiated fuel bundle into a reactor building
storage location during core re-loading activities. The licensee failed to
thoroughly evaluate a discrepancy associated with an unexpected vertical
measurement when inserting an irradiated fuel bundle prior to unlatching the fuel
-5- Enclosure
bundle. This resulted in the bundle dropping 1 1/8 inches when the licensee
attempted to retrieve it. After the bundle dropped, the licensee immediately
performed a visual inspection and, with vendor analysis support, removed the
bundle from service. The licensee entered this issue into the corrective action
program as Condition Report CR-ANO-1-2012-0110.
The failure to identify and correct the discrepancy in the vertical position of an
irradiated fuel bundle during fuel handling operations is a performance
deficiency. The performance deficiency is determined to be more than minor
because it is associated with the human performance attribute of the Barrier
Integrity cornerstone and adversely affects the cornerstone objective to provide
reasonable assurance that physical design barriers protect the public from
radionuclide releases caused by accidents or events. Specifically, the
performance deficiency resulted in a dropped fuel bundle that was subsequently
removed from service due to possible fuel pellet damage. The event also took
place while the reactor building was open to the atmosphere. Using Manual
Chapter 0609, Appendix G, Attachment 1, Checklist 4, PWR Refueling
Operation: RCS Level >23, the finding was determined to have very low safety
significance (Green) because the finding did not adversely affect: 1) core heat
removal, 2) inventory control, 3) electrical power, 4) containment control, or 5)
reactivity control. The finding was determined to have a cross-cutting aspect in
the area of human performance, associated with decision making component in
that the licensee failed to use conservative assumptions and adopt a requirement
to demonstrate that the proposed action is safe in order to proceed when
deciding to accept the discrepancy in the vertical measurement when storing a
fuel bundle in the reactor building storage rack H.1(b) (Section 1R20.3).
- Green. The inspectors documented a self-revealing finding for the failure to take
adequate corrective actions for known deficiencies associated with the Unit 1 fuel
transfer system. Specifically, the licensee failed to investigate and correct issues
that had been identified by site and vendor personnel from 1996 through 2010.
This led to repeated fuel transfer system failures and significant core offload and
reload delays during the 1R23 refueling outage, which placed the plant in an
unplanned configuration for an extended period of time. After the failure of the
fuel transfer equipment, multiple corrective actions were performed which
included the installation of a temporary modification which allowed fuel
movement to continue to support core reloading. The issue was entered into the
licensees corrective action program as Condition Report CR-ANO-1-2011-2558.
The failure of the licensee to take effective corrective action for known
deficiencies related to the Unit 1 fuel transfer system is determined to be a
performance deficiency. The performance deficiency is determined to be more
than minor because, if left uncorrected, the performance deficiency could
become a more safety significant issue. Specifically, the continued failure of the
licensee to correct known deficiencies in the fuel transfer system could lead to
damage to a fuel bundle. Using Manual Chapter 0609, Appendix G,
Attachment 1, Checklist 4, PWR Refueling Operation: RCS Level >23, the
-6- Enclosure
finding was determined to have very low safety significance (Green) because the
finding did not adversely affect: 1) core heat removal, 2) inventory control, 3)
electrical power, 4) containment control, or 5) reactivity control. The finding was
determined to have a cross-cutting aspect in the area of human performance,
associated with decision making component in that the licensee failed to use
conservative assumptions and adopt a requirement to demonstrate that the
proposed action is safe in order to proceed rather than a requirement to
demonstrate that it is unsafe in order to disapprove the action. Specifically, the
decision making efforts affecting the fuel transfer system did not reflect a safety
minded culture as past experience and vendor recommendations were
disregarded H.1(b) (Section 1R20.4).
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 licensees corrective action program. These violations and
corrective action tracking numbers (condition report numbers) are listed in
Section 4OA7.
-7- Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 began the period at 93 percent reactor power in coastdown to refueling outage 1R23. On
October 16, 2011, Unit 1 entered Mode 3 to begin refueling outage 1R23. On November 22,
2011, Unit 1 closed the main generator breaker to end refueling outage 1R23. On
November 26, 2011, Unit 1 reached 100 percent reactor power and remained there for the
remainder of the period.
Unit 2 began the period at 100 percent reactor power. On December 20, 2011, Unit 2 reduced
power to 47 percent reactor power due to securing the 2P-8A heater drain pump and to address
a main condenser tube leak that was causing high sodium levels above 50 ppb in both steam
generators. On December 21, 2011, Unit 2 raised power to 80 percent reactor power after
returning the 2P-8A heater drain pump to operation. On December 22, 2011, following repair of
the condenser tubes, Unit 2 reached 100 percent reactor power and remained there for the
remainder of the period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors performed a review of the adverse weather procedures for seasonal
extreme low temperature preparations. The inspectors verified that weather-related
equipment deficiencies identified during the previous year were corrected prior to the
onset of seasonal extremes, and evaluated the implementation of the adverse weather
preparation procedures and compensatory measures for the affected conditions before
the onset of, and during, the adverse weather conditions.
During the inspection, the inspectors focused on plant-specific design features and the
procedures used by plant personnel to mitigate or respond to adverse weather
conditions. Additionally, the inspectors reviewed the Safety Analysis Report (SAR) and
performance requirements for systems selected for inspection, and verified that operator
actions were appropriate as specified by plant-specific procedures. Specific documents
reviewed during this inspection are listed in the attachment. The inspectors also
reviewed corrective action program items to verify that plant personnel were identifying
adverse weather issues at an appropriate threshold and entering them into their
corrective action program in accordance with station corrective action procedures. The
inspectors reviews focused specifically on the following plant systems:
- Unit 1 and Unit 2 emergency diesel generator fuel storage vaults
-8- Enclosure
- Unit 1 and Unit 2 service water intake structures
- Unit 2 refuel water tank and Unit 1 borated water storage tank
These activities constitute completion of one (1) readiness for seasonal adverse weather
sample as defined in Inspection Procedure 71111.01-05.
b. Findings
No findings were identified.
1R04 Equipment Alignments (71111.04)
.1 Partial Walkdown
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
- October 18, 2011, Unit 1 spent fuel pool cooling with temporary power modification
- October 19, 2011, Unit 2 service water bay A and bay C while bay B and the
emergency cooling pond were unavailable
- November 2, 2011, alternate AC diesel generator and Unit 1 emergency diesel
generator 2 while emergency diesel generator 1 was out of service for maintenance
The inspectors selected these systems based on their risk significance relative to the
reactor safety cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could affect the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, SAR, technical specification requirements, administrative technical
specifications, outstanding work orders, condition reports, and the impact of ongoing
work activities on redundant trains of equipment in order to identify conditions that could
have rendered the systems incapable of performing their intended functions. The
inspectors also inspected accessible portions of the systems to verify system
components and support equipment were aligned correctly and operable. The
inspectors examined the material condition of the components and observed operating
parameters of equipment to verify that there were no obvious deficiencies. The
inspectors also verified that the licensee had properly identified and resolved equipment
alignment problems that could cause initiating events or impact the capability of
mitigating systems or barriers and entered them into the corrective action program with
the appropriate significance characterization. Specific documents reviewed during this
inspection are listed in the attachment.
These activities constitute completion of three (3) partial system walkdown samples as
defined in Inspection Procedure 71111.04-05.
-9- Enclosure
b. Findings
No findings were identified.
.2 Complete Walkdown
a. Inspection Scope
On December 22, 2011, the inspectors performed a complete system alignment
inspection of the Unit 2 fire water system to verify the functional capability of the system.
The inspectors selected this system because it was considered both safety significant
and risk significant in the licensees probabilistic risk assessment. The inspectors
inspected the system to review mechanical and electrical equipment line ups, electrical
power availability, system pressure and temperature indications, as appropriate,
component labeling, component lubrication, component and equipment cooling, hangers
and supports, operability of support systems, and to ensure that ancillary equipment or
debris did not interfere with equipment operation. The inspectors reviewed a sample of
past and outstanding work orders to determine whether any deficiencies significantly
affected the system function. In addition, the inspectors reviewed the corrective action
program database to ensure that system equipment-alignment problems were being
identified and appropriately resolved. Specific documents reviewed during this
inspection are listed in the attachment.
These activities constitute completion of one (1) complete system walkdown sample as
defined in Inspection Procedure 71111.04-05.
b. Findings
No findings were identified.
1R05 Fire Protection (71111.05)
Quarterly Fire Inspection Tours
a. Inspection Scope
The inspectors conducted fire protection walkdowns that were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
- October 17, 2011, Unit 1, Fire Zone FZ-1063 through FZ-1067 north and south,
reactor building
- October 18, 2011, Unit 1, Fire Zone FZ-1030, service water intake structure during
hot work
- 10 - Enclosure
- December 30, 2011, Unit 2, Fire Zone 2200-MM, electrical switchgear, feedwater
heaters and turbine area, elevation 386
- December 30, 2011, Unit 2 , Fire Zone 2076-HH, electrical equipment (motor
generator set) room
The inspectors reviewed areas to assess if licensee personnel had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant; effectively maintained fire detection and suppression capability; maintained
passive fire protection features in good material condition; and had implemented
adequate compensatory measures for out of service, degraded or inoperable fire
protection equipment, systems, or features, in accordance with the licensees fire plan.
The inspectors selected fire areas based on their overall contribution to internal fire risk
as documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to affect equipment that could initiate or mitigate a
plant transient, or their impact on the plants ability to respond to a security event. Using
the documents listed in the attachment, the inspectors verified that fire hoses and
extinguishers were in their designated locations and available for immediate use; that
fire detectors and sprinklers were unobstructed; that transient material loading was
within the analyzed limits; and fire doors, dampers, and penetration seals appeared to
be in satisfactory condition. The inspectors also verified that minor issues identified
during the inspection were entered into the licensees corrective action program.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four (4) quarterly fire-protection inspection
samples as defined in Inspection Procedure 71111.05-05.
b. Findings
No findings were identified.
1R06 Flood Protection Measures (71111.06)
a. Inspection Scope
The inspectors reviewed the SAR, the flooding analysis, and plant procedures to assess
susceptibilities involving internal flooding; reviewed the corrective action program to
determine if licensee personnel identified and corrected flooding problems; inspected
underground bunkers/manholes to verify the adequacy of sump pumps, level alarm
circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and
verified that operator actions for coping with flooding can reasonably achieve the desired
outcomes. The inspectors also inspected the areas listed below to verify the adequacy
of equipment seals located below the flood line, floor and wall penetration seals,
watertight door seals, common drain lines and sumps, sump pumps, level alarms, and
control circuits, and temporary or removable flood barriers. Specific documents
reviewed during this inspection are listed in the attachment.
- 11 - Enclosure
- December 19, 2011, Unit 1 and 2 emergency diesel generator fuel oil storage vaults
during fire water deluge actuation
- December 22, 2011, manhole MH-9 and manhole MH-10,which contain two trains of
Unit 1 emergency diesel generator fuel oil transfer pump electrical power, and
manhole MH-4, which contains two trains of Unit 1 service water electrical power
cables
- December 30, 2011, Unit 1 west decay heat vault
These activities constitute completion of two (2) flood protection measures inspection
samples and one (1) bunker/manhole sample as defined in Inspection Procedure
71111.06-05.
b. Findings
No findings were identified.
1R07 Heat Sink Performance (71111.07)
a. Inspection Scope
The inspectors reviewed licensee programs, verified performance against industry
standards, and reviewed critical operating parameters and maintenance records for the
Unit 1 train B decay heat system heat exchanger. The inspectors verified that
performance tests were satisfactorily conducted for heat exchangers/heat sinks and
reviewed for problems or errors; the licensee utilized the periodic maintenance method
outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines;
the licensee properly utilized biofouling controls; the licensees heat exchanger
inspections adequately assessed the state of cleanliness of their tubes; and the heat
exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring
the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents
reviewed during this inspection are listed in the attachment.
These activities constitute completion of one (1) heat sink inspection sample as defined
in Inspection Procedure 71111.07-05.
b. Findings
No findings were identified.
- 12 - Enclosure
1R08 Inservice Inspection Activities (71111.08)
.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water
Reactor Vessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control
(71111.08-02.01)
a. Inspection Scope
The inspectors observed 16 nondestructive examination activities and reviewed five
nondestructive examination activities that included seven types of examinations. The
licensee did not identify any relevant indications accepted for continued service during
the nondestructive examinations.
The inspectors directly observed the following nondestructive examinations:
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
Reactor Coolant Let-down Heat Exchanger, Solvent Soluble
System Drawing # 6600-M1J-3-7, Contrasting Dye
Component ID # 37-005, Liquid Penetrant Examination
Penetrant Exam # 1-ISI-PT-11- (PT)
003
Reactor Coolant Component ID: 1FCB-1 Piping, Solvent Soluble
Core Flood Description: FW-11C1, Drawing # Contrasting Dye
CF-200, Liquid Penentrant Exam Penetrant Examination
- 1-BOP-PT-11-012 (PT)
Reactor Coolant Component ID: 1FCB-1 Piping, Solvent Soluble
Core Flood Description: FW-12C1, Drawing # Contrasting Dye
CF-200, Liquid Penentrant Exam Penetrant Examination
- 1-BOP-PT-11-012 (PT)
Containment Containment building spray valve Radiograph Examination
Building Spray and elbow, Drawing # 5-BS-1, (RT)
System Component ID # BS-4B,
Radiograph Exam # 1-BOP-RT-
Reactor Coolant Steam Generator A, E-24A Lower Ultrasonic Examination
System Head to Lower Ring Head Weld. (UT)
Drawing # M1D-295, Component
- 03-102, Ultrasonic Exam # 1-
ISI-UT-11-012
Reactor Coolant Steam Generator A, E-24A Lower Ultrasonic Examination
System Head Ring to Lower Tubesheet (UT)
Component # 03-103, Ultrasonic
- 13 - Enclosure
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
Exam # 1-ISI-UT-11-014
High Pressure Pipe to Elbow Circumference Ultrasonic Examination
Injection System Seam. Drawing # 17-MU-27 (UT)
Sheet 1. Component ID # 23-063,
Ultrasonic Exam # 1-ISI-UT-11-
008
High Pressure Pipe to Pipe Circumference Ultrasonic Examination
Injection System Seam. Drawing # 17-MU-27 (UT)
Sheet 1. Component ID # 23-107,
Ultrasonic Exam # 1-ISI-UT-11-
009
Steam Generator Letdown pipe, Elbow to Pipe Ultrasonic Examination
Seam. Drawing # 17-MU-1 Sheet (UT)
2, Component ID # 24-009,
Ultrasonic Exam # 1-ISI-UT-11-
010
Reactor Coolant Pressurizer Relief Nozzle Enhanced Visual
System Between Z-W Axis. Examination (VT-1)
Drawing # M1G-69, Component
ID # 05-15IR, Visual
Exam # 1-ISI-VT-11-034
Steam Generator Steam Generator B Upper Head Visual Examination (VT-1)
Manhole studs, washers, and
nuts, Drawing # M1D-295 and
M1D-251, Component ID # 03-
120, Visual Exam # 1-ISI-VT-11-
069
Steam Generator Steam Generator B Lower Head Visual Examination (VT-1)
Manhole studs, washers, and
nuts, Drawing # M1D-295 and
M1D-251, Component ID # 03-
119, Visual Exam # 1-ISI-VT-11-
068
Reactor Coolant Steam Generator Upper Primary Visual Examination (VT-2)
System Inspection Port (Hand Hold)
Access E-24A, WO 244173-01,
Component ID 3 6.4, Visual Exam
- 1-ISI-VT-11-023
Reactor Coolant Steam Generator Upper Primary Visual Examination (VT-2)
- 14 - Enclosure
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
System Inspection Port (Hand Hold)
Access E-24B, WO 244951-01,
Component ID # 6.7, Visual Exam
- 1-ISI-VT-11-024
Reactor Coolant Reactor lower head bottom Enhanced Visual
System mounted in-core instrumentation Examination (VT-2)
Alloy 600 bare metal inspection,
Drawing # M-77 and M1B-231,
Visual Exam # 1-ISI-VT-11-053
Service Water Spring Can Hanger HCD-111-H3. Visual Examination (VT-3)
System Drawing # 13-SW-110,
Component # 54-059, Visual
Exam # 1-ISI-VT-11-059
The inspectors reviewed records for the following nondestructive examinations:
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
Main Steam E-24A Steam outlet nozzle to Dry, Color Contrast,
System shell weld (@26 degrees), Magnetic Particle
Drawing # M1D-295m Examination (MT)
Component # 03-117, Magnetic
Particle Exam # 1-ISI-MT-11-001
Containment Containment building spray valve Radiograph Examination
Building Spray and elbow, Drawing # ISO 5-BS-1 (RT)
System and 5-BS-101, Component ID #
BS-4B, Radiograph Exam # 1-
BOP-RT-11-012
Containment Containment building spray valve Radiograph Examination
Building Spray and elbow, Drawing # ISO 5-BS-1 (RT)
System and 5-BS-101, Component ID #
BS-4B, Radiograph Exam # 1-
BOP-RT-11-013
Containment Containment building spray valve Radiograph examination
Building Spray and elbow, Drawing # ISO 5-BS-1 (RT)
System and 5-BS-101, Component ID #
BS-4B, Radiograph
Exam # 1-BOP-RT-11-014
Reactor Coolant Reactor lower head bottom Enhanced Visual
System mounted in-core instrumentation Examination (VT-2)
- 15 - Enclosure
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
Alloy 600 bare metal inspection,
Drawing # M-77 and M1B-231,
Visual Exam # 1-ISI-VT-11-053
During the review and observation of each examination, the inspectors verified that
activities were performed in accordance with the ASME Code requirements and
applicable procedures. The inspectors also verified the qualifications of all
nondestructive examination technicians performing the inspections were current.
The inspectors observed two welds and reviewed the documentation on two welds on
the reactor coolant system pressure boundary.
The inspectors directly observed a portion of the following welding activities:
SYSTEM WELD IDENTIFICATION WELD TYPE
Reactor Coolant Component ID: 1FCB-1 Piping, Tungsten Inert Gas -
Drain Tank Description: FW-12C1, GTAW
Drawing # CF-200
Reactor Building BS-4B - 8 inch,150 pound, Tungsten Inert Gas -
Spray tilting disc check valve, GTAW
Drawing # M-236.
The inspectors reviewed records for the following welding activities:
SYSTEM WELD IDENTIFICATION WELD TYPE
Reactor Coolant Component ID: 1FCB-1 Piping, Tungsten Inert Gas -
Drain Tank Description: FW-11C1, GTAW
Drawing # CF-200
Reactor Building BS-4B - 8 inch,150 pound, Tungsten Inert Gas -
Spray tilting disc check valve. Weld GTAW
attaching 45° elbow to
downstream pipe, Drawing #
M-236.
The inspectors verified, by review, that the welding procedure specifications and the
welders had been properly qualified in accordance with ASME Code,Section IX,
requirements. The inspectors also verified, through observation and record review, that
essential variables for the welding process were identified, recorded in the procedure
qualification record, and formed the bases for qualification of the welding procedure
specifications. Specific documents reviewed during this inspection are listed in the
attachment.
- 16 - Enclosure
These actions constitute completion of the requirements for Section 02.01.
b. Findings
No findings were identified.
.2 Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)
a. Inspection Scope
The inspectors reviewed the results of the licensees bare metal visual inspection of the
Reactor Vessel Upper Head Penetrations and verified that there was no evidence of
boric acid challenging the structural integrity of the reactor head components and
attachments. The inspectors also verified that the required inspection coverage was
achieved and limitations were properly recorded.
These actions constitute completion of the requirements for Section 02.02.
b. Findings
No findings were identified.
.3 Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)
a. Inspection Scope
The inspectors evaluated the implementation of the licensees boric acid corrosion
control program for monitoring degradation of those systems that could be adversely
affected by boric acid corrosion. The inspectors reviewed the documentation associated
with the licensees boric acid corrosion control walkdown as specified in Procedure EN-
DC-319. The inspectors also reviewed the visual records of the components and
equipment. The inspectors verified that the visual inspections emphasized locations
where boric acid leaks could cause degradation of safety-significant components. The
inspectors also verified that the engineering evaluations for those components where
boric acid was identified gave assurance that the ASME Code wall thickness limits were
properly maintained. The inspectors confirmed that the corrective actions performed for
evidence of boric acid leaks were consistent with requirements of the ASME Code.
Specific documents reviewed during this inspection are listed in the attachment.
These actions constitute completion of the requirements for Section 02.03.
b. Findings
No findings were identified.
- 17 - Enclosure
.4 Steam Generator Tube Inspection Activities (71111.08-02.04)
a. Inspection Scope
Arkansas Nuclear One - Unit One (ANO1) replacement steam generators (1E-24 A&B)
are Framatome Enhanced Once Through Steam Generators (EOTSGs). They were
constructed in accordance with the 1989 ASME Boiler and Pressure Vessel Code,
Section III. They are vertically mounted once through heat exchangers with a counter-
flow design. They were installed during the Unit 1 Refueling Outage (1R19) in
October 2005. The first inservice inspection was 1R20 in March 2007. During the
1R20 outage, it was identified that locking of the upper tube support plates to the upper
shroud in Steam Generator A had occurred. This resulted in bowing of the tie rods in the
first span (Condition Report CR-1-2007-959). A second inspection was performed in
1R21 which included both primary and secondary side inspections. The amount of
tie rod bowing had increased as well as the number of tube support plate wear
indications. However the growth rate of the wear supported skipping one outage. In the
next outage, 1R22, only the tubes around the tie rods were inspected to assess the
extent of the tie rod bowing only.
The inspection criteria for 1R23 (October 2011) included the following:
- 100 percent full length bobbin testing of both generators from tube end to tube.
- X-probe of tubes full length around all 52 tie rods in both steam generators.
- Plus Point/X probe testing of all proximity signals identified from Lower Tube Sheet to
01S, and all bobbin indications.
- Visual examination of the tube plugs - (10 tubes in Steam Generator A and 6 tubes
in Steam Generator B).
- Diagnostic testing of all bobbin I-codes with the Plus Point/X-probe.
- Comparison of deposits based on X-probe data (Condition Report CR-ANO-1-2010-
922). This was accomplished by testing the previously tested tubes in both Steam
Generators (~ 69 tubes in Steam Generator A and 10 tubes in Steam Generator B).
- There were no secondary side visual inspections.
- X-probe of all tubes with tube-to-tube indications (proximity) due to tie rod bowing.
Results
There are two damage mechanisms currently associated with the Arkansas Nuclear
One, Unit 1 steam generators. These include mechanical wear at the tube support
plates and tie rod bowing which results in tube to tube contact during cold conditions.
These will be addressed separately below:
- 18 - Enclosure
Tube Support Plate Wear (Indications)
Steam Generator Percent Through Percent Through Percent Through
ID Wall Wall 20-39 Wall 40-100
1-19 Percent Percent Percent
SG A 1456 36 0
SG B 1344 68 2
Maximum Depth was 46 Percent Through Wall (previous indication)
95/50 Growth = (~ 3 Percent Through Wall per Effective Full Power Year)
Plugging was performed at > 35 Percent to justify an interval equal to three cycles. All
condition monitoring parameters were met and no in-situ testing was required.
Tie Rod Bowing
Historically, tie rod bowing was isolated to Steam Generator A only. The bowing is a
result of the edges of the tube support plates being frictionally locked to the inner shroud
during cool downs. During operation, the support plates go back to their free movement
status and the rods straighten out. This is evident by no in-service tube to tube wear.
During the 1R23 inspection, bowing was identified in both steam generators. The extent
of the bowing will be discussed below:
Refuel outage 1R21 was the fourth inspection where bowing had been identified. An
operability evaluation was developed that addresses the projected curve of bowing
based on the number of thermal cycles the unit experiences. Currently the unit has
experienced six total thermal cycles. The operability was developed based on both
laboratory testing of the tie rods and the support plates and various other analytical
models. The maximum extent of the bowing is projected to be approximately
2.0 inches of lateral bow in the first span tie rods. The first span is defined by the
area between the top of the lower tube sheet to the first support plate. This span has
the longest vertical distance and the smallest diameter tie rods. Therefore the
maximum extent of bowing is exhibited in the first span. Based on the projected
curve, at six thermal cycles, the bowing could be as much as 1.6 inches of vertical
bow. The actual results were consistent with the last inspection results of slightly
below 1.3 inches. Steam Generator A has been consistent with the previous results
and within the projected estimates in the operability.
Two tubes in Steam Generator A, with tie rod bowing in the first span, display what
appears to be geometric deformations just above the lower tube sheet, at the mid-
- 19 - Enclosure
span (point of maximum bow) and just below the first tube sheet plate. The two
tubes are Row 43 Tube 8 and Row 88 Tube 9. These deformations are seen by the
various eddy current (ET) techniques (bobbin, array and +Point) as fill factor or lift-off
variations with no evidence of tube wall loss.
The geometric indications in these two tubes are basically the same. There was one
indication just above the lower tube sheet (LTS) which responds like a bulge; multiple
indications at the mid-span which respond like a wrinkled area and one indication at
the lower edge of the first tube sheet plate (01S) which responds like a dent.
Both tubes were removed from service.
This was the first time that bowing had been identified in Steam Generator B. The
extent of the bowing was approximately 0.5 inch which is well below that of Steam
Generator A. There was a delta, in that the direction of the bowing in the first span in
Steam Generator A was typically toward the center of the generator. The bowing in
Steam Generator B is multi-directional. It is on the X side of the generator as
compared to Steam Generator A which is on the Z side of the generator. This is
being addressed through the condition report system under CR-ANO-1-2011-1925.
Repair:
The following tubes were repaired during the outage. There were seven in Steam
Generator A and nine in Steam Generator B.
These actions constitute completion of the requirements of Section 02.04.
b. Findings
No findings were identified.
.5 Identification and Resolution of Problems (71111.08-02.05)
a. Inspection Scope
The inspectors reviewed 67 condition reports which dealt with inservice inspection
activities and found the corrective actions for inservice inspection issues were
appropriate. The specific condition reports reviewed are listed in the documents
reviewed section. From this review, the inspectors concluded that the licensee has an
appropriate threshold for entering inservice inspection issues into the Corrective Action
Program and has procedures that direct a root cause evaluation when necessary. The
licensee also has an effective program for applying industry inservice inspection
operating experience. Specific documents reviewed during this inspection are listed in
the attachment.
These actions constitute completion of the requirements of Section 02.05.
- 20 - Enclosure
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program (71111.11)
a. Inspection Scope
On November 29, 2011, the inspectors observed a Unit 2 crew of licensed operators in
the plants simulator to verify that operator performance was adequate, evaluators were
identifying and documenting crew performance problems and training was being
conducted in accordance with licensee procedures. The inspectors evaluated the
following areas:
- Licensed operator performance
- Crews clarity and formality of communications
- Crews ability to take timely actions in the conservative direction
- Crews prioritization, interpretation, and verification of annunciator alarms
- Crews correct use and implementation of abnormal and emergency procedures
- Control board manipulations
- Oversight and direction from supervisors
- Crews ability to identify and implement appropriate technical specification actions
and emergency plan actions and notifications
The inspectors compared the crews performance in these areas to pre-established
operator action expectations and successful critical task completion requirements.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one (1) quarterly licensed-operator
requalification program sample as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
- 21 - Enclosure
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk
significant systems:
- November 29, 2011, Alternate AC generator
- December 15, 2011, Unit 1 L-1 Turbine building crane
- December 22, 2011, Unit 2 emergency diesel generators
- December 30, 2011, Unit 1 reactor building spray
The inspectors reviewed events such as where ineffective equipment maintenance has
resulted in valid or invalid automatic actuations of engineered safeguards systems and
independently verified the licensee's actions to address system performance or condition
problems in terms of the following:
- Implementing appropriate work practices
- Identifying and addressing common cause failures
- Scoping of systems in accordance with 10 CFR 50.65(b)
- Characterizing system reliability issues for performance
- Charging unavailability for performance
- Trending key parameters for condition monitoring
- Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)
- Verifying appropriate performance criteria for structures, systems, and components
classified as having an adequate demonstration of performance through preventive
maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment
of appropriate and adequate goals and corrective actions for systems classified as
not having adequate performance, as described in 10 CFR 50.65(a)(1)
The inspectors assessed performance issues with respect to the reliability, availability,
and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the corrective action program with the appropriate
significance characterization. Specific documents reviewed during this inspection are
listed in the attachment.
- 22 - Enclosure
These activities constitute completion of four (4) quarterly maintenance effectiveness
samples as defined in Inspection Procedure 71111.12-05.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed licensee personnel's evaluation and management of plant risk
for the maintenance and emergent work activities affecting risk-significant and safety-
related equipment listed below to verify that the appropriate risk assessments were
performed prior to removing equipment for work:
- October 25, 2011, Unit 1, 1R23 outage risk assessment
- November 11, 2011 Unit 1 and Unit 2, tornado warning with Unit 1 in mode 6 and
Unit 2 at 100 percent power
The inspectors selected these activities based on potential risk significance relative to
the reactor safety cornerstones. As applicable for each activity, the inspectors verified
that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)
and that the assessments were accurate and complete. When licensee personnel
performed emergent work, the inspectors verified that the licensee personnel promptly
assessed and managed plant risk. The inspectors reviewed the scope of maintenance
work, discussed the results of the assessment with the licensee's probabilistic risk
analyst or shift technical advisor, and verified plant conditions were consistent with the
risk assessment. The inspectors also reviewed the technical specification requirements
and inspected portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of two (2) maintenance risk assessments and
emergent work control inspection samples as defined in Inspection
Procedure 71111.13-05.
b. Findings
No findings were identified.
1R15 Operability Evaluations and Functionality Assessments (71111.15)
a. Inspection Scope
The inspectors reviewed the following issues:
- 23 - Enclosure
- June 15, 2011, Unit 1 manhole MH-9 broken fire barrier inside manhole
- October 15, 2011, Unit 1, unplanned failure of D reactor protection system power
supply
- December 7 and 19, 2011, Unit 1, removal of emergency switchgear room
chillers, VCH- 4 A and B, from service for planned maintenance
- December 12, 2011, Unit 1, degraded in-core detector at IDC-32 level 1 that resulted
in a quadrant power tilt exceeding the limit for operation above 60 percent reactor
power
The inspectors selected these potential operability issues based on the risk significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that technical specification operability was
properly justified and the subject component or system remained available such that no
unrecognized increase in risk occurred. The inspectors compared the operability and
design criteria in the appropriate sections of the technical specifications and SAR to the
licensee personnels evaluations to determine whether the components or systems were
operable. Where compensatory measures were required to maintain operability, the
inspectors determined whether the measures in place would function as intended and
were properly controlled. The inspectors determined, where appropriate, compliance
with bounding limitations associated with the evaluations. Additionally, the inspectors
also reviewed a sampling of corrective action documents to verify that the licensee was
identifying and correcting any deficiencies associated with operability evaluations.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four (4) operability evaluations inspection
sample(s) as defined in Inspection Procedure 71111.15-05.
b. Findings
Introduction. The inspectors identified a Green noncited violation of Unit 1 Technical
Specification 3.8.4, DC Sources-Operating, Technical Specification 3.8.7, Inverters-
Operating, and Technical Specification 3.8.9, Distribution Systems-Operating, due to
the licensees failure to complete the associated required action prior to the specified
completion time while the associated emergency switchgear room chillers were out of
service for planned maintenance.
Description. On December 7, 2011, the licensee entered the following: (1) Technical
Specification 3.7.7 Condition A for one loop of service water being inoperable with an
associated completion time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; (2) Technical Specification 3.8.1 Condition B for
one emergency diesel generator inoperable with a 7 day completion time; and
(3) Technical Specification 3.0.6 to support VCH-4A, Train B emergency switchgear
room chiller, being out of service for planned maintenance. The licensee entered those
Technical Specifications at 5:35 a.m. on December 7, 2011 and exited the respective
technical specifications at 8:51 a.m. on December 8, 2011 after successful completion of
- 24 - Enclosure
surveillance test procedure OP-1104.027, Battery and Emergency Switchgear Cooling
System, Revision 40 for the VCH-4A chiller. On December 19, 2011 at 3:19 a.m., the
licensee entered the same technical specifications for the other loop of service water
listed above to support VCH-4B, Train A emergency switchgear room chiller, being out
of service for planned maintenance. The licensee exited those technical specifications
at 6:47 p.m. on December 19, 2011 after successful completion of surveillance test
procedure OP-1104.027 for the VCH-4B chiller.
The VCH-4 emergency switchgear chillers are non-technical specification equipment
that support safety related equipment with associated technical specification
requirements. Specifically, Technical Specification 3.8.4, DC Sources - Operating,
requires, in part, for one DC electrical power subsystem inoperable in Modes 1, 2, 3, or 4
for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, action must be taken to place Unit 1 in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Technical Specification 3.8.7, Inverters - Operating, requires, in part, that for two or
more inoperable inverters in one of the two trains, while in Modes 1, 2, 3, or 4, action
must be taken to place Unit 1 in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Technical Specification 3.8.9,
Distribution Systems - Operating, requires, in part, that for one AC, DC, or 120 VAC
electrical power distribution subsystems inoperable in Modes 1, 2, 3, or 4 for greater
than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, action must be taken to place Unit 1 in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Conversely, Technical Specification 3.7.7 for one loop of service water inoperable has a
completion time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The issue was identified to the licensee and entered into
the licensees corrective action program as Condition Report CR-ANO-1-2012-0043.
Analysis. The inspectors determined that not completing the associated required actions
for the appropriate technical specifications prior to the specified completion time while
the associated emergency switchgear room chillers were out of service for planned
maintenance is a performance deficiency. The performance deficiency is determined to
be more than minor because it is associated with the equipment performance attribute of
the Mitigating Systems Cornerstone, and affects the associated cornerstone objective to
ensure availability, reliability, and the capability of systems that respond to initiating
events to prevent undesirable consequences and is therefore a finding. Specifically,
failure to complete the required actions prior to the specified completion times for
Technical Specification 3.8.4, DC Sources - Operating, Technical Specification 3.8.7,
Inverters - Operating, and Technical Specification 3.8.9, Distribution Systems -
Operating, due to removing the respective VCH-4 from service for maintenance, was a
violation of technical specifications. Using Inspection Manual Chapter 0609.04,
Phase 1 - Initial Screening and Characterization of Findings, the finding was
determined to require a Phase 2 analysis because removing each VCH-4 chiller from
service in December 2011 did result in an actual loss of safety function of a single train
for greater than its technical specification allowed completion time. A phase 2 analysis
from a previous noncited violation that bounds this issue determined the finding to be of
very low safety significance (Green). Specifically, although the function was lost by the
designated support equipment (emergency switchgear chillers), the licensee had an
evaluation that credited compensatory measures and specific environmental conditions
that assured the overall functionality of the applicable switchgear train was not lost. The
inspectors reviewed the engineering change EC-25691, Prepare EC markup to
- 25 - Enclosure
CALC-92-E-0103-01 to determine maximum outside ambient temperatures and
compensatory measures to allow one chiller train to cool DC/BATT/SWGR areas during
maintenance, and determined the overall functionality of the applicable switchgear train
was not lost, however, the compensatory measures sufficed for the function, but did not
satisfy the technical specification switchgear operability requirements. The finding was
determined to have a cross-cutting aspect in the area of human performance, associated
with the decision making component, in that the licensee did not use conservative
assumptions in decision making and adopt a requirement to demonstrate that the
proposed action is safe in order to proceed rather than a requirement that it is unsafe in
order to disapprove the action H.1(b).
Enforcement. Technical Specifications 3.8.4, DC Sources - Operating, requires, in
part, both DC electrical power subsystems shall be operable in Modes 1, 2, 3, or 4.
Technical Specification 3.8.7, Inverters - Operating, requires, in part, that two red train
inverters and two green train inverters shall be operable in Modes 1, 2, 3, or 4.
Technical Specification 3.8.9, Distribution Systems - Operating, requires, in part, that
two AC, DC, and 120 VAC electrical power distribution subsystems shall be operable in
Modes 1, 2, 3, or 4. Technical Specification 3.8.4 and 3.8.9 require that if one DC
electrical power subsystem, or one AC electrical distribution, or one DC electrical
distribution, or one 120 VAC electrical power distribution subsystem is inoperable for
greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, action must be taken to place Unit 1 in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and
Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Technical Specification 3.8.7 requires that if two or more
inverters are inoperable, Unit 1 must be placed in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 5
within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Contrary to the technical specifications required action statements, on
December 7, 2011, the B train DC electrical power subsystem, the B train inverters, and
the B train AC, DC, and 120 VAC electrical power distribution subsystems were
inoperable due to a lack of emergency switchgear cooling for greater than the allowed
completion time and the licensee failed to take the appropriate required actions. In
addition, on December 19, 2011, the A train inverters were also inoperable due to a lack
of emergency switchgear cooling and the unit was not placed in Mode 3 within the
required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Because this violation was of very low safety significance and has
been entered into the corrective action program as Condition Report
CR-ANO-1-2012-0043, this violation is being treated as a noncited violation consistent
with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000313/2011005-01,
Exceeded Technical Specification Allowed Completion Time for Electrical Power
Systems.
1R18 Plant Modifications (71111.18)
a. Inspection Scope
To verify that the safety functions of important safety systems were not degraded, the
inspectors reviewed the following temporary modifications:
- November 3, 2011, Unit 1, temporary electrical power for spent fuel pool cooling
P-40A
- 26 - Enclosure
- November 15, 2011, Unit 2, reactor coolant system temperature Thot input to core
protection calculator C
The inspectors reviewed the temporary modifications and the associated safety-
evaluation screening against the system design bases documentation, including the
SAR and the technical specifications, and verified that the modification did not adversely
affect the system operability/availability. The inspectors also verified that the installation
and restoration were consistent with the modification documents and that configuration
control was adequate. Additionally, the inspectors verified that the temporary
modification was identified on control room drawings, appropriate tags were placed on
the affected equipment, and licensee personnel evaluated the combined effects on
mitigating systems and the integrity of radiological barriers.
These activities constitute completion of two (2) samples for temporary plant
modifications as defined in Inspection Procedure 71111.18-05.
b. Findings
No findings were identified.
.2 Permanent Modifications
a. Inspection Scope
The inspectors reviewed key parameters associated with energy needs, materials,
replacement components, timing, heat removal, control signals, equipment protection
from hazards, operations, flow paths, pressure boundary, ventilation boundary,
structural, process medium properties, licensing basis, and failure modes for the
permanent modification identified as replacement of valve SW-9, and installation of
valve SW-23 to provide boundary isolation from emergency cooling pond to service
water.
The inspectors verified that modification preparation, staging, and implementation did
not impair emergency/abnormal operating procedure actions, key safety functions, or
operator response to loss of key safety functions; post-modification testing will maintain
the plant in a safe configuration during testing by verifying that unintended system
interactions will not occur; systems, structures and components performance
characteristics still meet the design basis; the modification design assumptions were
appropriate; the modification test acceptance criteria will be met; and licensee personnel
identified and implemented appropriate corrective actions associated with permanent
plant modifications. Specific documents reviewed during this inspection are listed in the
attachment.
These activities constitute completion of one (1) sample for permanent plant
modifications as defined in Inspection Procedure 71111.18-05.
- 27 - Enclosure
b. Findings
No findings were identified.
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed the following postmaintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
- October 14, 2011, Unit 2 control element assembly trip circuit breakers
- November 1, 2011, Unit 1, control valve CV-1405, train A reactor building sump outlet
valve following refurbishment
The inspectors selected these activities based upon the structure, system, or
component's ability to affect risk. The inspectors evaluated these activities for the
following:
- The effect of testing on the plant had been adequately addressed; testing was
adequate for the maintenance performed
- Acceptance criteria were clear and demonstrated operational readiness; test
instrumentation was appropriate
The inspectors evaluated the activities against the technical specifications, the SAR,
10 CFR Part 50 requirements, licensee procedures, and various NRC generic
communications to ensure that the test results adequately ensured that the equipment
met the licensing basis and design requirements. In addition, the inspectors reviewed
corrective action documents associated with postmaintenance tests to determine
whether the licensee was identifying problems and entering them in the corrective action
program and that the problems were being corrected commensurate with their
importance to safety. Specific documents reviewed during this inspection are listed in
the attachment.
These activities constitute completion of two (2) postmaintenance testing inspection
samples as defined in Inspection Procedure 71111.19-05.
b. Findings
No findings were identified.
- 28 - Enclosure
1R20 Refueling and Other Outage Activities (71111.20)
a. Inspection Scope
The inspectors reviewed the outage safety plan and contingency plans for the Unit 1
1R23 refueling outage, conducted October 16, 2011, through November 22, 2011, to
confirm that licensee personnel had appropriately considered risk, industry experience,
and previous site-specific problems in developing and implementing a plan that assured
maintenance of defense in depth. During the refueling outage, the inspectors observed
portions of the shutdown and cooldown processes and monitored licensee controls over
the outage activities listed below.
- Configuration management, including maintenance of defense in depth, is
commensurate with the outage safety plan for key safety functions and compliance
with the applicable technical specifications when taking equipment out of service.
- Clearance activities, including confirmation that tags were properly hung and
equipment appropriately configured to safely support the work or testing.
- Installation and configuration of reactor coolant pressure, level, and temperature
instruments to provide accurate indication, accounting for instrument error.
- Status and configuration of electrical systems to ensure that technical specifications
and outage safety-plan requirements were met, and controls over switchyard
activities.
- Monitoring of decay heat removal processes, systems, and components.
- Verification that outage work was not impacting the ability of the operators to operate
the spent fuel pool cooling system.
- Reactor water inventory controls, including flow paths, configurations, and alternative
means for inventory addition, and controls to prevent inventory loss.
- Controls over activities that could affect reactivity.
- Maintenance of secondary containment as required by the technical specifications.
- Refueling activities, including fuel handling and sipping to detect fuel assembly
leakage.
- Startup and ascension to full power operation, tracking of startup prerequisites,
walkdown of the drywell (primary containment) to verify that debris had not been left
which could block emergency core cooling system suction strainers, and reactor
physics testing.
- 29 - Enclosure
- Licensee identification and resolution of problems related to refueling outage
activities.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one (1) refueling outage and other outage
inspection sample as defined in Inspection Procedure 71111.20-05.
b. Findings
(1) Failure to Implement Procedure Results in Lowering Spent Fuel Pool Level by 0.6 Feet
Introduction: The inspectors documented a Green, self-revealing, noncited violation of
Unit 1 Technical Specification 5.4.1.a for the failure to implement station procedure
OP-1104.006 Spent Fuel Pool Cooling System, Revision 51. Specifically, SF-10, flow
control to purification loop valve, was found 3 turns open when it was required to be
closed. This resulted in the spent fuel pool level lowering by 0.6 feet, which is below
procedural limits, when the fuel transfer canal was placed in purification and SF-45,
transfer tube isolation valve, was closed to support diving operations in the Unit 1 spent
fuel pool tilt pit.
Description: On November 2, 2011, F-4A spent fuel filter was replaced and station
procedure OP-1104.006 step 27.2 was performed to fill and vent the filter to place it back
into service. During step 27.2.3.A, valve SF-10 was positioned to approximately
25 percent open to support the fill and vent of the filter. Later that day, operations
performed step 24.0 of station procedure OP-1104.006 to place the fuel transfer canal
and reactor cavity on purification. Prior to performing this operation, step 27.2.8.A.1 of
OP-1104.006 directed the closing of valve SF-10 to prevent spent fuel pool cooling
pump discharge water for cooling the pool from entering the spent fuel pool purification
loop. Flow control valve SF-10 was not fully closed prior to placing the fuel transfer
canal on purification.
On November 3, 2011, Unit 1 received a spent fuel pool low level alarm which is
received when the pool level reaches -0.5 ft. At that time the fuel transfer canal was on
purification in accordance with station procedure OP-1104.006 and SF-45 transfer tube
isolation valve was closed to isolate the spent fuel pool tilt pit to support diving
operations. Prior to closing SF-45, spent fuel pool level, as indicated by level indicator
LI- 2004, was -0.3 ft. Operations secured fuel transfer purification and indicated level
was -0.9 ft which was below the procedural limit of -0.5 ft. Operations then opened
SF-45 which allowed water to sluice back to the spent fuel pool from the reactor cavity
and the spent fuel pool level returned to -0.3 ft.
During investigation of the spent fuel pool low level alarm, operations determined that
valve SF-10 was open approximately three turns. This allowed the spent fuel pool
cooling pumps to pump water from the spent fuel pool to the suction piping for the decay
heat removal pumps. The decay heat removal pumps were operating and pumped the
water to the reactor coolant system and into the reactor cavity. When SF-45 was closed
the water could not sluice back into the spent fuel pool from the reactor cavity.
- 30 - Enclosure
Approximately 4,500 gallons of water in the spent fuel pool was transferred to the reactor
cavity
The licensee identified that a purification valve line up was performed on November 2,
2011 prior to placing the fuel transfer canal on purification during which two operators
checked SF-10 in the closed direction using normal force and verified closure by
checking stem position that only showed threads. On November 3, 2011 when
operators checked the position of SF-10 and found it to be open approximately three
turns, they had to use excessive force including a torque amplifying device to close the
valve.
The licensee performed a human performance error review in accordance with station
procedure EN-HU-103 Human Performance Error Reviews, Rev. 6. The review
determined that the condition of the valve not being closed was the result of degraded
plant equipment and not the result of a human performance error.
Additional actions taken by the licensee included: (1) documenting that SF-10 requires a
torque amplifying device to operate in CR-ANO-1-2011-2495, (2) hanging a caution card
on SF-10 stating that a torque amplifying device is required to operate the valve, and
(3) initiating a work request to address the valve condition.
Analysis: The failure of operations personnel to implement the requirements of procedure
OP-1104.006, Spent Fuel Pool Cooling System, Revision 51, and close valve SF-10 is a
performance deficiency. The performance deficiency is more than minor because it was
associated with the configuration control attribute of the Barrier Integrity cornerstone and
adversely affects the cornerstone objective to provide reasonable assurance that physical
design barriers protect the public from radionuclide releases caused by accidents or
events and is therefore a finding. Using Manual Chapter 0609.04, Phase 1 - Initial
Screening and Characterization of Findings, the finding was determined to have very low
safety significance (Green) because the finding did not result in the loss of spent fuel pool
cooling, did not result from fuel handling errors that caused damage to the fuel clad
integrity or a dropped assembly and did not result in a loss of spent fuel pool inventory of
greater than 10 percent of the spent fuel pool volume. The finding was determined to
have a cross-cutting aspect in the area of human performance, associated with the work
control component in that the licensee failed to ensure that work activities to support long
term equipment reliability limited operator work-arounds when a torque amplifying device
was required to shut valve SF-10 H.3(b).
Enforcement: Technical Specification 5.4.1.a states, in part, that written procedures shall
be implemented in accordance with Regulatory Guide 1.33, Revision 2, Appendix A,
February 1978. Section 3.h, of Appendix A, Procedures for Startup, Operation and
Shutdown of Safety-Related PWR Systems, requires procedures for operating the fuel
storage pool purification and cooling system. Station procedure OP-1104.006, Spent
Fuel Cooling System, Revision 51, step 27.2.8.A.1, stated to close valve SF-10 prior to
returning the fuel transfer canal on purification after the completion of filling and venting
spent fuel pool purification filter F-4A. Contrary to the above, valve SF-10 was not
closed prior to placing the fuel transfer canal on purification causing spent fuel pool level
- 31 - Enclosure
to decrease below procedural limits. Because this finding is of very low safety
significance and has been entered into the corrective action program as Condition
Report CR-ANO-1-2011-2498, this violation is being treated as a noncited violation
consistent with Section 2.3.2.a of the NRC Enforcement Policy:
NCV 05000313/2011005-02, Failure to Implement Procedure Results in Lowering Spent
Fuel Pool Level by 0.6 Feet.
(2) Failure to Identify and Correct Unit 1 Service Water Pump Column Protective Wrap
Installation Deficiencies.
Introduction. The inspectors documented a Green, self-revealing, noncited violation of
10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for the licensees failure to
promptly identify and correct a condition adverse to quality associated with degradation
of the protective wrap (brand name - Denso) installed on the Unit 1 service water pump
columns. The Denso protective wrap around the P-4C service water pump suction
column became unraveled and was drawn into the service water pump suction while
running, causing the pump to be secured due to pump discharge strainer high differential
pressure.
Description. On November 15, 2011, during realignment of service water suction from
the emergency cooling pond to the lake intake structure, the control room received a
P-4C service water pump discharge strainer high differential pressure alarm. The alarm
was received immediately after cross connecting the service water bays B and C via
sluice gate 4. The discharge strainer differential pressure rose to at least 25 psid
(maximum reading on the differential pressure instrument) and operations personnel
manually placed the standby P-4B service water pump in service and secured the P-4C
pump. At the time of the event, service water loop I was operable and being supplied
from the P-4A pump and met the technical specification for service water supply for
Unit 1 in Mode 6. Upon investigation, the licensee determined that the Denso protective
wrap applied to the P-4C service water pump column, per Engineering Request,
ER-963315E110 in 2005, had become unraveled and was pulled into the pump suction,
resulting in debris that clogged the pump discharge strainer. The licensee entered the
issue into the corrective action program as Condition Report CR-ANO-1-2011-2843.
The licensee took immediate corrective action and removed the Denso protective wrap
from all pump columns in the Unit 1 service water intake structure bays. Unit 2 does not
have Denso protective wrap installed on their service water pumps.
The licensee performed an apparent cause evaluation that focused on the design
change that installed the Denso protective wrap and determined that the design change
should have integrated the following items into the design change: (1) the tape product
was not specifically designed, qualified, or dedicated for nuclear application; (2) detailed
engineering instructions for installation of the product should have been provided;
(3) preventive maintenance requirements to identify degradation over time should have
been developed; and (4) an estimate for the lifetime of the product in this application
should have been determined. The apparent cause evaluation also identified that
repeated occurrences of degradation since the original installation should have
prompted numerous organizations to question the on-going integrity of the protective
wrap applied to the pump columns in the Unit 1 intake structure bays.
- 32 - Enclosure
The inspectors reviewed the apparent cause evaluation and identified three condition
reports since 2005 that identified degradation of the Denso protective wrap applied to
the P4-A and P-4C service water pumps. The latest Condition Report, CR-ANO-1-2011-
0493 written on April 14, 2011, described two sections of Denso wrap that had peeled off
and were hanging from the P-4C service water pump column. One piece was about
18 inches in length and the other section was split into two pieces of several inches
each. The condition report only considered this issue as a long term corrosion concern
and determined that it had no immediate impact on the pump operability. No evaluation
was performed regarding the impact of additional unraveling of the Denso wrap to the
service water pumps operability. The only corrective action performed was to
immediately trim the loose pieces of Denso wrap to prevent further unraveling.
Analysis. The failure to promptly identify and correct a condition adverse to quality
associated with degradation of the protective wrap (brand name - Denso) installed on
the Unit 1 service water pump columns is a performance deficiency. The performance
deficiency is determined to be more than minor because it was associated with the
equipment performance attribute of the Mitigating Systems cornerstone and adversely
affects the cornerstone objective to ensure availability, reliability, and the capability of
systems that respond to initiating events to prevent undesirable consequences and is
therefore a finding. The inspectors performed the significance determination for the
failure of service water pump 4C using NRC Inspection Manual Chapter 0609,
Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings.
The problem had occurred during an outage, but it could have occurred at power during
a system realignment. The at-power model was more conservative, so it was used to
evaluate the finding. Service water was a two train system with a swing pump (an
installed spare). The allowed outage time for one train was 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Operators could
easily align the swing pump to provide the train B service water loads within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Therefore, this finding screened to Green because: 1) it was not a design or qualification
deficiency; 2) it did not result in loss of safety function of one train of equipment for more
than its technical specification allowed outage time; 3) It did not result in a loss of one
train of non-technical specification equipment; and 4) it did not screen as potentially risk
significant due to an external event. The finding was determined to have a cross-cutting
aspect in the area of problem identification and resolution, associated with the corrective
action program component, in that, the licensee failed to thoroughly evaluate problems
such that the resolutions address causes and extent of conditions. Specifically, the
failure to thoroughly evaluate identified issues with the protective wrap prevented
corrective action to be taken to prevent the deficiencies with the service water pump
Enforcement. Title 10 of the Code or Federal Regulations, Part 50, Appendix B,
Criterion XVI states, in part, Measures shall be established to assure that conditions
adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective
material and equipment, and nonconformances are promptly identified and corrected.
Contrary to the above, from 2005 to November 15, 2011, the licensee failed to ensure
that a known condition adverse to quality associated with the degradation of the Denso
protective wrap, on the Unit 1 service water pumps, was thoroughly evaluated for
continued degradation and/or corrected in a timely manner. Because this finding is of
very low safety significance and has been entered into the corrective action program as
- 33 - Enclosure
Condition Report CR-ANO-1-2011-2843, this violation is being treated as a noncited
violation consistent with Section 2.3.3.a of the NRC Enforcement Policy: NCV 0500313/2011005-03, Failure to Identify and Correct Unit 1 Service Water Pump
Column Protective Wrap Installation Deficiencies.
(3) Failure to Identify and Correct a Condition Adverse to Quality Resulted in Dropping a
Fuel Bundle Approximately One Inch
Introduction. The inspectors identified a Green, noncited violation of 10 CFR 50,
Appendix B, Criterion XVI for failure to identify and correct a condition adverse to quality.
Specifically, on November 1, 2011, the licensee failed to identify and correct a condition
associated with seating an irradiated fuel bundle into a reactor building storage location
during core re-loading activities. The licensee failed to thoroughly evaluate a
discrepancy associated with an unexpected vertical measurement when inserting an
irradiated fuel bundle into a reactor building storage location. This resulted in the bundle
dropping 1 1/8 inches at the storage location.
Description. On November 1, 2011, the licensee was reloading the Unit 1 reactor core
and was experiencing some difficulty inserting an irradiated fuel bundle, NJ0C12, into
core location A-10. At this time the reactor building was open to the atmosphere. The
refueling team decided to move the fuel bundle to the reactor building storage rack C,
while attempting to adjust fuel bundles surrounding core location A-10. The ZZ-tape,
(the vertical measuring system used for fuel bundle placement) indicated that the
irradiated fuel bundle was at 32 feet and 1/4 inch. This measurement was 1 5/8 inch
higher than the nominal reading for this location. The refueling team raised and set the
fuel bundle down again and obtained the same ZZ-tape measurement. The nominal
reading was noted as 31 feet 10 and 5/8 inch in Attachment J, Main Fuel Bridge (H-1)
Fuel Hoist ZZ Tape Readings and Weight Setpoints, of procedure OP-1502.003,
Refueling Equipment and Operator Checkouts, Revision 35. The table also stated an
allowable tolerance of +1/2 inch difference between the current ZZ-tape reading and the
nominal readings obtained during fuel handling. System and reactor engineering were
notified for resolution.
In an attempt to verify that the fuel bundle was fully seated, the refueling team used an
underwater camera to inspect and evaluate the top portion of the bundle and the storage
rack. A visual comparison was performed with a smooth side dummy bundle two
storage locations away. The refueling team did not visually identify any height
difference. Reactor engineering, without going to the refueling bridge, approved the as
found ZZ-tape measurement as the current vertical measurement.
After fuel bundle adjustments were made in the reactor core, the refueling team went to
the storage rack to retrieve fuel bundle NJ0C12 to load it into core location A-10. When
the grapple was lowered onto the assembly, the bundle dropped approximately
1 1/8 inches in the storage rack. An immediate visual inspection did not identify any
obvious damage. The licensee decided not to use the bundle. An evaluation later
performed by AREVA determined that, although there was no visual damage to the
bundle, the fuel pellets may have been damaged due to the 11g of force experienced as
- 34 - Enclosure
a result of the drop. Another bundle was identified for use and a new core design was
developed and approved.
The licensee performed a lower tier apparent cause evaluation, which determined that
no human performance errors were involved in this event, and their apparent cause for
the dropped bundle was an inadequate procedure that failed to give specific guidance to
move fuel bundles to the reactor building storage racks and to verify that the fuel bundle
is fully seated in the storage rack. The licensee did not address any human
performance issues associated with this event.
The inspectors determined that the licensee failed to identify that the fuel bundle was not
fully seated in the storage location, and failed to correct that condition prior to
un-grappling. The inspectors also determined that the licensee failed to thoroughly
evaluate the discrepancy between the vertical fuel bundle measurement and the
expected nominal measurement. The refueling team did attempt to verify fuel bundle
position with an underwater camera, but incorrectly compared the heights of the smooth
sided dummy bundle, which is shorter in height, and the fuel bundle. The licensee failed
to look at the bottom of the storage location for confirmation that the bundle was fully
seated. The refueling team did not note any ZZ-tape vertical measurement
discrepancies with any other locations, nor did they review any measurement data to
rule out any issue with the ZZ-tape. The licensee also incorrectly assumed that the
reactor building storage racks on Unit 1 (Babcox & Wilcox) were designed the same as
the Unit 2 (Combustion Engineering) storage racks. The Unit 1 storage racks have a
cruciform on the bottom of the rack to help align and seat the fuel bundle. The licensee
did not thoroughly evaluate the fuel bundle measurement, convinced themselves that the
ZZ-tape discrepancy was acceptable and decided to accept the discrepancy. The
inspectors determined that the discrepancy associated with the ZZ-tape should have
placed the issue into the corrective action program, but was not placed into the program
until the bundle was dropped.
Analysis. The inspectors determined that the failure to identify and correct the condition
associated with the incorrect placement of an irradiated fuel bundle into a reactor
building storage location, is a performance deficiency because the licensee failed to
place the nuclear fuel in a safe position. The performance deficiency is determined to be
more than minor because it is associated with the human performance attribute of the
Barrier Integrity cornerstone and adversely affects the cornerstone objective to provide
reasonable assurance that physical design barriers protect the public from radionuclide
releases caused by accidents or events. Specifically, the performance deficiency
resulted in a dropped bundle that caused the bundle to be removed from service due to
possible fuel pellet damage. The event also took place during core reloading activities,
in which the reactor building was open to the atmosphere. Using Manual Chapter 0609,
Appendix G, Attachment 1, Checklist 4, PWR Refueling Operation: RCS Level >23,
the finding was determined to have very low safety significance (Green) because the
finding did not adversely affect: 1) core heat removal, 2) inventory control, 3) electrical
power, 4) containment control, or 5) reactivity control. The finding was determined to
have a cross-cutting aspect in the area of human performance, associated with the
decision making component in that the licensee failed to use conservative assumptions
and adopt a requirement to demonstrate that the proposed action is safe in order to
- 35 - Enclosure
proceed when deciding to accept the discrepancy in the vertical measurement when
storing a fuel bundle in the reactor building storage rack H.1(b).
Enforcement. Title 10 of the Code of Federal Regulation Part 50, Appendix B,
Criterion XVI, Corrective Action, requires, in part, that Measures shall be established
to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and non-conformances are promptly
identified and corrected. Contrary to the above, on November 1, 2011, the licensee
failed to identify and correct a condition adverse to quality regarding the placement of a
fuel bundle in a storage location when confronted with evidence that the fuel bundle may
not have been fully seated in that location. The fuel bundle subsequently dropped
1 1/8 inches. The drop was of sufficient force to render the bundle unusable due to
possible fuel pellet damage concerns. Because this finding is of very low safety
significance and has been entered into the corrective action program as Condition
Report CR-ANO-1-2012-0110, this violation is being treated as a noncited violation
consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000313/2011005-04, Failure to Identify and Correct a Condition Adverse to Quality
Resulted in Dropping a Fuel Bundle Approximately One Inch.
(4) Failure to Take Adequate Corrective Actions for Known Fuel Transfer System
Deficiencies
Introduction. The inspectors documented a Green, self-revealing finding for the failure to
take adequate corrective actions for known deficiencies associated with the Unit 1 fuel
transfer system. Specifically, the licensee failed to investigate and correct issues that
have been identified by site and vendor personnel from 1996 through 2010. This led to
repeated fuel transfer system failures and significant core offload and reload delays
during the 1R23 refueling outage, which placed the plant in an unplanned configuration
for an extended period of time.
Description. During the most recent Unit 1 refueling outage 1R23, fall 2011, numerous
problems associated with the fuel transfer system caused an interruption of fuel transfer
activities while offloading and reloading the reactor. Beginning on October 23, 2011,
while unloading the core, the refueling team began to experience fuel transfer carriage
overloads while moving fuel from the reactor building to the spent fuel pool, on every
other fuel transfer. Eventually the overloads became more frequent, occurring on every
fuel transfer until the overload condition could not be cleared and caused fuel transfer
activities to be stopped. The licensee subsequently identified worn carriage wheels and
cable tension issues as contributing to the overload conditions. The issues were
temporarily remedied, but cable tension issues remained. On October 27 reactor core
offload was completed, but the fuel transfer system continued to experience overload
conditions. No corrective actions were taken during the core defueled window to address
the overload issue.
On November 1, 2011, reactor core reload began. Cable tension was being monitored
and was increasing and continued with every fuel bundle transfer. At the time, the
licensee did not know why the cable tension was increasing, but later determined that
some increase in tension should have been expected and that actions could have been
- 36 - Enclosure
taken to mitigate the issue. On November 2, the fuel transfer carriage unexpectedly
stopped approximately three feet inside the reactor building. The licensee had 69 of
177 fuel bundles loaded into the core at this time. The licensee formed a failure modes
analysis team to further investigate the issue. It was determined that the fuel transfer
carriage wheels on the North side of the carriage were riding up on top of the railing
system in the reactor building. The licensee first attempted to realign the rails on the
spent fuel pool side to better align the carriage as it transitioned into the reactor building.
This action was not effective and the misalignment persisted. A temporary modification
was developed and installed that added a wheel extension to the reactor building side of
the fuel transfer carriage to prevent the carriage from riding up on top of the rails. On
November 13 core reload was completed.
The current fuel transfer system was not original equipment and was installed in 1986.
Beginning in 1996, issues associated with the fuel transfer system have been noted. In
2004, 2005, 2007, 2008, and again in 2010 issues with overloads, worn wheels,
sheaves, mechanical binding and even a broken retraction cable had been documented
in vendor (AREVA) outage reports and in the licensees corrective action program.
Inspections and pre-outage fuel system checkouts were performed prior to 1R23 outage
and did identify some overload conditions, but they were attributed to not having
calibrated the load cell. An inspection of the fuel transfer system was performed under
water and without moving the fuel transfer carriage. The refueling team further directed
unloaded and dry check runs of the fuel transfer system. Nothing was identified from
this inspection.
The inspectors reviewed the licensees root cause evaluation. The root cause evaluated
why the fuel transfer system experienced overloads and equipment deficiencies that
resulted in the loss of 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> of critical path time. Three root causes were identified:
1) original design and configuration issues, 2) organizational issues such as
communication, direction of field activities, application of field resources, and decision
making that was inadequate during the 1R23 refueling outage, and 3) that previous
vendor reports and operating experience items were not acted upon in a timely manner
to correct historical problems. The inspectors believe that the main cause for the fuel
transfer issues experienced in 1R23 was the failure to correct known deficiencies that
have been plaguing the licensee for years. The root cause further evaluated safety
culture aspects associated with this issue and concluded that several safety culture
aspects were applicable. Among these were decision making, corrective action program
for failing to correct the deficiencies, and the failure to act upon operating experience.
The inspectors determined that the safety culture aspect of non-conservative decision
making was the most dominate contributor to not correcting known deficiencies.
Specifically, the decision making efforts affecting the fuel transfer system did not reflect
a safety minded culture as past experience and vendor recommendations were
disregarded.
Analysis. The failure of the licensee to take effective corrective action for known
deficiencies related to the Unit 1 fuel transfer system is determined to be a performance
deficiency because it was not in accordance with their corrective action program, was
within their ability to foresee and correct, and should have been corrected. The
performance deficiency is determined to be more than minor because if left uncorrected
- 37 - Enclosure
the performance deficiency could become a more safety significant issue. Specifically,
the licensees failure to correct known deficiencies of the fuel transfer system
demonstrated a lack of knowledge of the system design and function which could fail in
unexpected and in unpredictable ways which could lead to more safety significant
issues. Using Manual Chapter 0609, Appendix G, Attachment 1, Checklist 4, PWR
Refueling Operation: RCS Level >23, the finding was determined to have very low
safety significance (Green) because the finding did not adversely affect: 1) core heat
removal, 2) inventory control, 3) electrical power, 4) containment control, or 5) reactivity
control. The finding was determined to have a cross-cutting aspect in the area of human
performance, associated with the decision making component in that the licensee failed
to use conservative assumptions and adopt a requirement to demonstrate that the
proposed action is safe in order to proceed rather than a requirement to demonstrate
that it is unsafe in order to disapprove the action. Specifically, the decision making
efforts affecting the fuel transfer system did not reflect a safety minded culture as past
experience and vendor recommendations were disregarded H.1(b).
Enforcement. Although a performance deficiency was identified, there were no
violations of NRC requirements identified during the review of this issue because the
Unit 1 fuel transfer system is not safety-related. The licensee entered this issue into the
corrective action program as Condition Report CR-ANO-1-2011-2558. This finding is
being documented as: FIN 05000313/2011005-05, Failure to Take Adequate Corrective
Actions for Known Fuel Transfer System Deficiencies.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed the SAR, procedure requirements, and technical specifications
to ensure that the surveillance activities listed below demonstrated that the systems,
structures, and/or components tested were capable of performing their intended safety
functions. The inspectors either witnessed or reviewed test data to verify that the
significant surveillance test attributes were adequate to address the following:
- Preconditioning
- Evaluation of testing impact on the plant
- Acceptance criteria
- Test equipment
- Procedures
- Jumper/lifted lead controls
- Test data
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- Testing frequency and method demonstrated technical specification operability
- Test equipment removal
- Restoration of plant systems
- Fulfillment of ASME Code requirements
- Updating of performance indicator data
- Engineering evaluations, root causes, and bases for returning tested systems,
structures, and components not meeting the test acceptance criteria were correct
- Reference setting data
- Annunciators and alarms setpoints
The inspectors also verified that licensee personnel identified and implemented any
needed corrective actions associated with the surveillance testing.
- October 5, 2011, Unit 1 VCH-4A, loop 2 emergency switchgear room chiller
temperature switch surveillance test
- November 9, 2011, Unit 1, make up and purification system check valve and
control valve full flow inservice surveillance test
- November 10, 2011, Unit 1, fill and vent of makeup and purification, and the high
pressure injection system (TI 2515/177 effort)
- November 11, 2011, Unit 1, train A engineered safeguards actuation system
integrated test
- November 18, 2011, Unit 1, pressurizer sampling system containment isolation
valve SV-1818 local leak rate test
- December 19, 2011, Unit 2 containment isolation valve 2CV-4823-2 local leak
rate test
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of six (6) surveillance testing inspection samples
as defined in Inspection Procedure 71111.22-05.
b. Findings
No findings were identified.
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Cornerstone: Emergency Preparedness
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
a. Inspection Scope
The inspector performed an in-office review of Emergency Plan Implementing Procedure
OP-1903.010, Emergency Action Level Classification, Change 44 submitted by letter
dated July 26, 2011. This revision changed a reference in Attachment 9, EAL
Equipment Compensating Measures, of this procedure from referencing a table in the
Technical Requirements Manual listing seismic instrumentation to referencing
Procedures 1203.025 and 2203.008, Natural Emergencies, for Units 1 and 2
respectively, were the compensating measures are specified for seismic instrumentation.
This revision was compared to its previous revision, to the criteria of NUREG-0654,
Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and
Preparedness in Support of Nuclear Power Plants, Revision 1, and to the standards in
10 CFR 50.47(b) to determine if the revision adequately implemented the requirements
of 10 CFR 50.54(q). This review was not documented in a safety evaluation report and
did not constitute approval of licensee-generated changes; therefore, this revision is
subject to future inspection.
These activities constitute completion of one (1) sample as defined in Inspection
Procedure 71114.04-05.
b. Findings
No findings were identified.
1EP6 Drill Evaluation (71114.06)
a. Inspection Scope
The inspectors observed a Unit 1 simulator training evolution for licensed operators on
November 22, 2011, which required emergency plan implementation by a licensee
operations crew. This evolution was planned to be evaluated and included in
performance indicator data regarding drill and exercise performance. The inspectors
observed event classification and notification activities performed by the crew. The
inspectors also attended the postevolution critique for the scenario. The focus of the
inspectors activities was to note any weaknesses and deficiencies in the crews
performance and ensure that the licensee evaluators noted the same issues and entered
them into the corrective action program. As part of the inspection, the inspectors
reviewed the scenario package and other documents listed in the attachment.
These activities constitute completion of one (1) sample as defined in Inspection
Procedure 71114.06-05.
- 40 - Enclosure
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
4OA1 Performance Indicator Verification (71151)
.1 Data Submission Issue
a. Inspection Scope
The inspectors performed a review of the performance indicator data submitted by the
licensee for the third Quarter 2011 performance indicators for any obvious
inconsistencies prior to its public release in accordance with Inspection Manual
Chapter 0608, Performance Indicator Program.
This review was performed as part of the inspectors normal plant status activities and,
as such, did not constitute a separate inspection sample.
b. Findings
No findings were identified.
.2 Mitigating Systems Performance Index - Emergency ac Power System (MS06)
a. Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index - emergency ac power system performance indicator for Units 1 and 2 for the
period from the fourth quarter 2010 through the third quarter 2011. To determine the
accuracy of the performance indicator data reported during those periods, the inspectors
used definitions and guidance contained in NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the
licensees operator narrative logs, mitigating systems performance index derivation
reports, issue reports, event reports, and NRC integrated inspection reports for the
period of October 2010 through September 2011 to validate the accuracy of the
submittals. The inspectors reviewed the mitigating systems performance index
component risk coefficient to determine if it had changed by more than 25 percent in
value since the previous inspection, and if so, that the change was in accordance with
applicable NEI guidance. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the performance
indicator data collected or transmitted for this indicator and none were identified.
Specific documents reviewed are described in the attachment to this report.
- 41 - Enclosure
These activities constitute completion of two (2) mitigating systems performance index -
emergency ac power system samples as defined in Inspection Procedure 71151-05.
b. Findings
No findings were identified.
.3 Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)
a. Inspection Scope
The inspectors sampled licensee submittals for the mitigating systems performance
index - high pressure injection systems performance indicator for Units 1 and 2 for the
period from the fourth quarter 2010 through the third quarter 2011. To determine the
accuracy of the performance indicator data reported during those periods, the inspectors
used definitions and guidance contained in NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the
licensees operator narrative logs, issue reports, mitigating systems performance index
derivation reports, event reports, and NRC integrated inspection reports for the period of
October 2010 through September 2011 to validate the accuracy of the submittals. The
inspectors reviewed the mitigating systems performance index component risk
coefficient to determine if it had changed by more than 25 percent in value since the
previous inspection, and if so, that the change was in accordance with applicable NEI
guidance. The inspectors also reviewed the licensees issue report database to
determine if any problems had been identified with the performance indicator data
collected or transmitted for this indicator and none were identified. Specific documents
reviewed are described in the attachment to this report.
These activities constitute completion of two (2) mitigating systems performance index -
high pressure injection system samples as defined in Inspection Procedure 71151-05.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution (71152)
.1 Routine Review of Identification and Resolution of Problems
a. Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify that they were being entered into the licensees
corrective action program at an appropriate threshold, that adequate attention was being
given to timely corrective actions, and that adverse trends were identified and
addressed. The inspectors reviewed attributes that included the complete and accurate
- 42 - Enclosure
identification of the problem; the timely correction, commensurate with the safety
significance; the evaluation and disposition of performance issues, generic implications,
common causes, contributing factors, root causes, extent of condition reviews, and
previous occurrences reviews; and the classification, prioritization, focus, and timeliness
of corrective actions. Minor issues entered into the licensees corrective action program
because of the inspectors observations are included in the attached list of documents
reviewed.
These routine reviews for the identification and resolution of problems did not constitute
any additional inspection samples. Instead, by procedure, they were considered an
integral part of the inspections performed during the quarter and documented in
Section 1 of this report.
b. Findings
No findings were identified.
.2 Daily Corrective Action Program Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees corrective action program. The inspectors
accomplished this through review of the stations daily corrective action documents.
The inspectors performed these daily reviews as part of their daily plant status
monitoring activities and, as such, did not constitute any separate inspection samples.
b. Findings
No findings were identified.
.3 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a review of the licensees corrective action program and
associated documents to identify trends that could indicate the existence of a more
significant safety issue. The inspectors focused their review on repetitive equipment
issues, but also considered the results of daily corrective action item screening
discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human
performance results. The inspectors nominally considered the 6-month period of June
2011 through December 2011 although some examples expanded beyond those dates
where the scope of the trend warranted.
The inspectors also included issues documented outside the normal corrective action
program in major equipment problem lists, repetitive and/or rework maintenance lists,
- 43 - Enclosure
departmental problem/challenges lists, system health reports, quality assurance
audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.
The inspectors compared and contrasted their results with the results contained in the
licensees corrective action program trending reports. Corrective actions associated with
a sample of the issues identified in the licensees trending reports were reviewed for
adequacy.
These activities constitute completion of one (1) single semi-annual trend inspection
sample as defined in Inspection Procedure 71152-05.
b. Findings and Observations
No findings were identified. The inspectors did identify the following items during the
review: 1) configuration control issues, 2) water intrusion issues into the auxiliary
building, turbine building, and manholes; and 3) outage performance with regards to the
refueling team performance and refueling equipment. These items have been entered
into the corrective action program.
.4 Selected Issue Follow-up Inspection
a. Inspection Scope
During a review of items entered in the licensees corrective action program, the
inspectors recognized a corrective action report documenting an incident where an
operator found a diesel oil storage tank outlet valve closed that was required to be open
to support the functionality of the alternate AC diesel generator. The licensee entered the
issue into the corrective action program as Condition Report CR-ANO-C-2011-2241.
The inspectors reviewed the condition report for impact upon the diesels functionality
and the high risk significance associated with potential loss of functionality of the
alternate AC diesel generator.
These activities constitute completion of one (1) in-depth problem identification and
resolution sample as defined in Inspection Procedure 71152-05.
b. Findings
Introduction: The inspectors documented a Green, self revealing, noncited violation of
Unit 1 Technical Specification 5.4.1.a for the failure to implement station procedure
OP-1015.049 Configuration Control Program, Revision 1. Specifically, on multiple
occasions, station personnel failed to maintain configuration control through the use of
valve line-ups and station procedures to ensure that plant components were in required
positions.
Description: On September 3, 2011, Unit 1 outside auxiliary operator discovered FO-37,
diesel oil storage tank outlet valve, closed when it was required to be open to supply fuel
oil to the alternate AC diesel generator 600 gallon day tank. This condition would have
prevented automatic makeup to the day tank but the alternate AC diesel would have
started and run when demanded for approximately 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The licensee determined
- 44 - Enclosure
that FO-37 was not correctly positioned open on August 24, 2011, while performing
Attachment B of station operating procedure OP-1104.023, Diesel Oil Transfer
Procedure during the performance of maintenance on the Unit 1, train A emergency
diesel generator. The licensee entered the issue into their corrective action program as
Condition Report CR-ANO-C-2011-2241.
On October 18, 2011, while collapsing the pressurizer bubble per station procedure
OP-1103.011, reactor vessel level indication became erratic and indicated a low level
condition. Draining was secured to evaluate the condition. After securing the drain it
was noted that pressurizer level continued to lower and the quench tank volume
continued to rise. After investigation it was determined that RBV-71B, T hot loop B root
vent was open when it should have been closed. This caused an unintended reactor
coolant system loss of approximately 525 gallons to the quench tank during the
pressurizer bubble collapse effort. The licensee determined that RBV-71B was not
closed as required per station procedure OP-1103.002, Attachment B, Valve Lineup
after completion of Fill and Vent at the completion of the previous outage. The licensee
entered the issue into their corrective action program as condition report CR-ANO-1-
2011-1740 and 1744.
On October 19, 2011, while performing station procedure OP-1104.004, Attachment G,
Decay Heat Coolant Purification Using Alternate Purification, station chemistry
personnel determined that the reactor coolant system was not getting cleaner based on
the results of the demineralizer effluent sample and this indicated that there was no flow
through the demineralizer. Following an investigation, it was determined that valves
CZ-33 and CZ-34B were closed and should have been open and valve CZ-35B was
open and should have been closed as required by station procedure OP-1104.004. The
mispositioned valves allowed the reactor coolant system flow to bypass the
demineralizer. The licensee entered the issue into their corrective action program as
Condition Report CR-ANO-1-2011-1812.
On October 23, 2011, the licensee used station procedure OP-1104.002, Makeup and
Purification System Operation, Supplement 8 to perform a full flow check valve test of
the makeup system using the A high pressure injection pump. It was determined that
the pump curve data obtained was out of the IST limiting range for the pump. An
investigation determined that the equalizing valve for PDT-1210 D, high pressure flow
indication, was open one-half turn and caused flow indication to read lower. The valve
did not have the hand wheel installed and was operated with channel locks. During the
subsequent retest the valve was again found three turns open following its operation to
flush the lines. The valve was finally replaced with a new one with a hand wheel. The
licensee entered the issue into their corrective action program as Condition Report
CR-ANO-1-2011-2312.
The inspectors reviewed Condition Report CR-ANO-C-2011-2942, and its associated
apparent cause evaluation relating to 12 potential mispositioned components since
June 2011. The evaluation concluded that the causes included: (1) a lack of
commitment to program implementation; (2) documents not followed correctly involving
- 45 - Enclosure
both programmatic and component control document usage; and (3) guidance was not
well defined or understood.
Based upon the multiple examples of failures to satisfy station configuration control
procedures the inspectors have determined the failures to be indicative of a
programmatic failure to position plant components as required per the configuration
control program.
Analysis: The inspectors determined that the failure of station personnel to maintain
configuration control through the use of valve line-ups and governing station procedures
to ensure reactor plant components were in their required positions, is a performance
deficiency. The performance deficiency is more than minor because it is associated with
the configuration control attribute of the Mitigating Systems cornerstone and adversely
affects the cornerstone objective to ensure the availability, reliability and capability of
systems that respond to initiating events to prevent undesirable consequences and is
therefore a finding. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and
Characterization of Findings, the finding included an example that was determined to be
an actual loss of safety function of a non-technical specification train of equipment
designated as risk-significant per 10CFR50.65, for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A phase 3
significance determination analysis was performed by a Region IV senior reactor
analyst. The dominant core damage sequences for Unit 1 were station blackouts with
battery depletion and transients with loss of feedwater and feed and bleed capability.
The dominant core damage sequences for Unit 2 were station blackout with loss of
emergency feedwater and once-through-cooling, loss of 4160 volt vital bus 2A4 with loss
of feedwater and once-through-cooling, and station blackout with an 8-hour battery
depletion. Based on both units having the capability to operate a steam driven
emergency feedwater pump during the dominate core damage sequences the finding
was determined to have very low safety significance (Green). The finding was
determined to have a cross-cutting aspect in the area of human performance, associated
with the work practices component to support human performance in that the licensee
failed to define and effectively communicate expectations regarding procedural guidance
and personnel follow procedures when performing component positioning in accordance
with the licensees program for configuration control H.4(b).
Enforcement: Technical Specification 5.4.1.a states, in part, that written procedures shall
be established, implemented and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Section 1 of Appendix A to Regulatory Guide 1.33, states in part, that safety related
activities should be covered by written procedures such as equipment control. Station
procedure OP-1015.049, Configuration Control Program, Revision 1, step 6.1 stated
the control of plant equipment status is established by performing valve/breaker line-ups
and then governed by procedures, work orders, log readings, or protective tagging.
Contrary to the above, on multiple occasions, between September 3 and October 23,
2011, the licensee failed to control plant equipment status by inappropriately performing
valve/breaker line-ups and for failing to follow governing procedures. Because this
finding is of very low safety significance and has been entered into the corrective action
program as Condition Report CR-ANO-1-2011-2942, this violation is being treated as a
- 46 - Enclosure
noncited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:
NCV 05000313/2011005-06, Failure to Adequately Implement the Configuration Control
Program.
.5 In-depth Review of Operator Workarounds
a. Inspection Scope
The inspectors selected this issue for review to verify that licensee personnel were
identifying operator workaround problems at an appropriate threshold and entering them
in the corrective action program, and has proposed or implemented appropriate
corrective actions. The inspectors reviewed and evaluated the licensee's operator
workaround log, for both Units 1 and 2, operator logs and associated condition reports.
The inspectors considered the following, as applicable, during the review of the
licensee's actions: (1) complete and accurate identification of the problem in a timely
manner; (2) evaluation and disposition of operability/reportability issues;
(3) consideration of extent of condition, generic implications, common cause, and
previous occurrences; (4) classification and prioritization of the resolution of the problem;
(5) identification of root and contributing causes of the problem; (6) identification of
corrective actions; and (7) completion of corrective actions in a timely manner.
b. Findings
No findings were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
.1 (Closed) LER 05000368/2009003 Steam Generator Tube Exceeding Technical
Specification Plugging Criteria Remained in Service During Previous Cycles as a Result
of the Failure to Use Proper Independent Verification
On September 8, 2009, Unit 2 was shutdown in Mode 6 for 2R20 outage activities.
During the B steam generator inspection it was discovered that a steam generator tube
was incorrectly plugged during the previous outage. During the 2R17 spring outage a
steam generator tube with an identified flaw was correctly plugged on the cold leg side of
the steam generator but not on the hot leg side. An adjacent steam generator tube on
the hot leg side was incorrectly plugged instead. The condition resulted in Unit 2
operating at power, from April 2005 until discovery, with a steam generator tube
characterized with an approximate 43 percent through wall defect which was in violation
of the Unit 2 Technical Specification of less than 40 percent through wall required to be
in service. Licensee investigation determined that the error in plugging was caused by a
failure to use proper independent verification that the correct tube was plugged. Both
steam generator tubes were plugged to remove them from service. The issue was
placed into the corrective action program as Condition Report CR-ANO-2-2009-2357. A
licensee identified noncited violation was documented in Inspection Report 05000368/2009004 for this issue. This licensee event report is closed.
- 47 - Enclosure
.2 (Closed) LER 05000368/2009002 Containment Building Penetration Isolation Valves
Open During Core Alterations without Application of Administrative Controls Required by
Technical Specifications Due to Inadequate Procedural Instructions
On September 7, 2009, with Unit 2 in Mode 6 for refueling, licensed operators
discovered that containment penetration isolation valves located on the return line of the
containment atmospheric monitoring system were configured such that a direct path
existed between the containment atmosphere and the auxiliary building atmosphere and
the resulting containment breech was not being administratively controlled as required
by Unit 2 technical specifications. The licensee determined that the system was initially
placed in the correct configuration during reactor shutdown, but a local leak rate testing
evolution required these vales to be repositioned. The valves were not restored to the
required configuration following completion of the local leak rate testing. Core alteration
commenced shortly after completion of the testing. The licensee determined that the
local leak rate procedure failed to give adequate guidance to restore the system for
shutdown plant conditions. The licensee took corrective action to modify the procedure
to specify position of the valves depending on the plant mode. The issue was placed
into the corrective action program as Condition Report CR-ANO-2-2009-2329. A
licensee identified noncited violation was documented in Inspection Report 05000368/2009004. This licensee event report is closed.
.3 (Closed) LER 05000368/2009004 Emergency Diesel Automatic Actuation While
Performing Offsite Power Transfer Testing Due to a High Resistance Contact Supplying
Voltage to a Synchronizing Check Relay
On September 20, 2009, Unit 2 was shutdown in Mode 5 for 2R20 outage activities.
During the performance of planned surveillance testing of the Offsite Power Transfer
Test, the 2K-4A emergency diesel generator automatically started. An Offsite Power
Transfer Test was being performed to test automatic transfer from the Startup 3 Offsite
Transformer to the Startup 2 Offsite Transformer. During the Offsite Power Transfer
Test, a permissive contact in the Startup 2 feeder breaker failed resulting in a slow
transfer to the 2A1 bus instead of the expected fast transfer. The slow transfer resulted
in a momentary loss of power to the 4160 Volt Safety Electrical Bus 2A3 which is
powered from 2A1. The momentary undervoltage condition on 2A3 caused the 2K-4A
emergency diesel generator to auto start as designed. The 2K-4A emergency diesel
generator did not power 2A3, since 2A3 was successfully powered from 2A1 after the
slow transfer completed. During the momentary loss of power, 2A3 automatically shed
all loads as designed. This load shed caused the running shutdown cooling pump,
2P-60A , to secure which resulted in a loss of shutdown cooling flow to the reactor
coolant system for approximately three and one half minutes. The licensee determined
that the cause of the event was a loss of one of the voltage inputs that feed the 2A1 bus
synchronizing check relay (125-111), located in the 2A-111 breaker cubicle, due to a high
resistance contact. This high resistance condition blocked one of the voltage inputs to
the synchronizing check relay, causing the relay to falsely indicate that the startup 2
transformer and the 2A1 bus were not synchronized. The licensee took immediate
corrective action to modify the circuit with alternate contacts with the appropriate
resistance. The licensee also took corrective action to modify the maintenance
procedures for these type breakers to inspect and maintain these contacts. The issue
- 48 - Enclosure
was placed into the corrective action program as Condition Reports
CR-ANO-2-2009-2997. A self-revealing noncited violation was documented in
Inspection Report 05000368/2009005 for this issue. The review of this licensee event
report is complete and no findings were identified and no violations of NRC requirements
occurred. This licensee event report is closed.
4OA5 Other Activities
(Open) NRC TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling,
Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008-01)
As documented in Section 1R22, the inspectors confirmed the acceptability of the
licensees procedures and processes for filling and venting ECCS systems. This
inspection effort counts towards the completion of TI 2515/177 which will be closed in a
later NRC Inspection Report following further inspection activities to follow-up on
previously identified issues documented in inspection report ANO 2011-04.
4OA6 Meetings
Exit Meeting Summary
On October 28, 2011, the inspectors presented the inspection results of the review of inservice
inspection activities to Mr. C. Schwarz, Site Vice President, and other members of the licensee
staff. The licensee acknowledged the issues presented. The inspector asked the licensee
whether any materials examined during the inspection should be considered proprietary. No
proprietary information was identified.
On December 1, 2011, the inspector, during a telephonic meeting, discussed the results of the
in-office inspection of changes to the licensees emergency plan and emergency action levels to
Mr. R. Holeyfield, Manager, Emergency Preparedness, and other members of the licensees
staff. The licensee acknowledged the issues presented. The inspector asked the licensee
whether any materials examined during the inspection should be considered proprietary. No
proprietary information was identified.
On January 20, 2012, the inspectors presented the inspection results to Mr. M. Chisum, General
Manager, Plant Operations, and other members of the licensee staff. The licensee
acknowledged the issues presented. The inspector asked the licensee whether any materials
examined during the inspection should be considered proprietary. No proprietary information
was identified.
4OA7 Licensee-Identified Violations
The following violations of very low safety significance (Green) were identified by the licensee
and are violations of NRC requirements which meet the criteria of Section 2.3.2 of the NRC
Enforcement Policy for being dispositioned as noncited violations.
- Unit 1 Technical Specification 5.4.1.a, requires, in part, that Written procedures shall be
established, implemented, and maintained covering the following activitiesthe
- 49 - Enclosure
applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A,
February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, Section 2 specifies
written procedures for the safety-related activity of refueling and core alterations.
Contrary to the above, the licensee failed to implement procedures for core alterations
during 1R23 Unit 1 refueling outage. Specifically, on two occasions, the refueling team
failed to follow refueling procedures for verifying neutron counts prior to un-grappling a
fuel bundle in the core and for moving a fuel bundle in fast speed prior to obtaining
adequate clearance from other fuel bundles in the core. Using Manual Chapter 0609,
Appendix G, Attachment 1, Checklist 4, PWR Refueling Operation: RCS Level >23,
the finding was determined to have very low safety significance (Green) because the
finding did not adversely affect: 1) core heat removal; 2) inventory control; 3) electrical
power; 4) containment control; or 5) reactivity control. These issues were entered into
the corrective action program as Condition Reports CR-ANO-1-2011-2085, and 2552.
- Unit 1 Technical Specification 5.4.1.a, requires, in part, that Written procedures shall be
established, implemented, and maintained covering the following activitiesthe
applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A,
February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, Section 2 specifies
written procedures for the safety-related activity of refueling and core alterations.
Contrary to the above, the licensee failed to provide adequate procedures for refueling
and core alterations during 1R23 Unit 1 refueling outage. Specifically, the licensee over
rotated a control rod drive lead screw during reactor disassembly and resulted in having
to replace the control rod drive mechanism. Using Manual Chapter 0609, Appendix G,
Attachment 1, Checklist 4, PWR Refueling Operation: RCS Level >23, the finding was
determined to have very low safety significance (Green) because the finding did not
adversely affect: 1) core heat removal, 2) inventory control, 3) electrical power,
4) containment control, or 5) reactivity control. This issue was entered into the corrective
action program as Condition Report CR-ANO-1-2011-1921.
- 50 - Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
C. Schwarz, Site Vice President
D. Bice, Licensing Specialist
B. Byford, Manager, Training
T. Chernivec, Manager, Outages
M. Chisum, General Manager, Plant Operations
B. Daiber, Manager, Design Engineering
A. Dodds, Manager, Maintenance
M. Farmer, Maintenance, Refueling Program Manager
R. Fowler, Senior Emergency Preparedness Planner
R. Fuller, Manager, Quality Assurance
W. Greeson, Manager, Engineering Programs and Component
R. Holeyfield, Manager, Emergency Preparedness
R. Holman, Welding Engineer, Entergy Code Programs
D. Hughes, Manager (Acting), Engineering Programs and Component
K. Jones, Manager, Operations
B. Lovin, Manager, Security
D. Marvel, Manager, Radiation Protection
J. McCoy, Director, Engineering
R. McGaha, NDE Technician, Entergy Code Programs
D. Metheany, Steam Generator Programs Owner
N. Mosher, Licensing Specialist
B. Pace, Manager, Planning, Scheduling, and Outage
K. Panther, Manager, ISI Program
D. Perkins, Manager, Maintenance
S. Pyle, Manager, Licensing
T. Sherrill, Manager, Chemistry
P. Williams, Manager, System Engineering
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
Exceeded Technical Specification Allowed Completion Time for
Electrical Power Systems (Section 1R15)
Failure to Implement Procedure Results in Lowering Spent Fuel
Pool Level by 0.6 Feet (Section 1R20(1))
Failure to Identify and Correct Unit 1 Service Water Pump Column
Protective Wrap Installation Deficiencies (Section 1R20(2))05000313/2011005-04 NCV Failure to Identify and Correct a Condition Adverse to Quality
A-1 Attachment
Opened and Closed
Resulted in Dropping a Fuel Bundle Approximately One Inch
(Section 1R20(3))
Failure to Take Adequate Corrective Actions for Known Fuel
Transfer System Deficiencies (Section 1R20(4))
Failure to Adequately Implement the Configuration Control
Program (Section 4OA2.4)
Closed
Steam Generator Tube Exceeding Technical Specification
Plugging Criteria Remained in Service During Previous Cycles as
a Result of the Failure to Use Proper Independent Verification
Containment Building Penetration Isolation Valves Open During
Core Alterations without Application of Administrative Controls
05000368/2009002 LER Required by Technical Specifications Due to Inadequate
Procedural Instructions
Emergency Diesel Automatic Actuation While Performing Offsite
05000368/2009004 LER Power Transfer Testing Due to a High Resistance Contact
Supplying Voltage to a Synchronizing Check Relay
A-2 Attachment
LIST OF DOCUMENTS REVIEWED
Section 1R01: Adverse Weather Protection
PROCEDURES
NUMBER TITLE REVISION
OP-1104.039 Plant Heating and Cold Weather Operations 22
OP-2106.032 Unit 2 Two Freeze Protection Guide 22
Section 1R04: Equipment Alignment
PROCEDURES
NUMBER TITLE REVISION
OP-1104.029 Unit 1 Service and Auxiliary Cooling Water System 55
OP-1104.036 Unit 1 Emergency Diesel Generator Operation 59
OP-2104.037 Alternate AC Diesel Generator 22
OP-1104.032 Unit 1 Fire Protection Systems 68
OP-2104.032 Unit 2 Fire Protection Systems Operations 32
DRAWINGS
NUMBER TITLE REVISION
M-210 Service Water 150
M-217 Emergency Diesel Generator and Fuel Oil System 89
M-2241 Alternate AC Generator System 3
M-2219 Fire Water System Pipe and Instrument Diagram 61
Sheet 1
M-2219 Fire Water System Pipe and Instrument Diagram 69
Sheet 2
M-2219 Deluge Valve Detail 35
Sheet 4
M-2219 Outside Fire Loop 50
Sheet 5
M-2219 Deluge Valve Detail 15
Sheet 7
A-3 Attachment
MISCELLANEOUS DOCUMENTS
NUMBER TITLE REVISION
STM-1-42 Unit 1 Service and Auxiliary Cooling Water 20
STM-1-31 Unit 1 Emergency Diesel Generators 12
STM-2-33 Unit 2 Alternate AC Diesel Generator 21
Section 1R05: Fire Protection
PROCEDURES
NUMBER TITLE REVISION
FHA ANO Fire Hazard Analysis 13
PFP-U1 ANO Pre-Fire Plan Unit 1 13
PFP-U2 ANO Pre-Fire Plan Unit 2 10
DRAWINGS
NUMBER TITLE REVISION
FZ-1063 Unit 1 Fire Zone Detail - Reactor Building 3
FZ-1064 Unit 1 Fire Zone Detail - Reactor Building 3
FZ-1065 Unit 1 Fire Zone Detail - Reactor Building 3
FZ-1066 Unit 1 Fire Zone Detail - Reactor Building 3
FZ-1067 Unit 1 Fire Zone Detail - Reactor Building 3
FZ-2044 Unit 2 Fire Zone Detail - Electrical Switchgear, Feedwater 1
Heaters, and Turbine areas
FZ-2025 Unit 2 Fire Zone Detail - Electrical Equipment (motor 2
generator sets) room
FZ-1030 Unit 1 Service Water Intake Structure 2
Section 1R06: Flood Protection Measures
PROCEDURES
NUMBER TITLE REVISION
ULD-0-TOP-17 ANO Topical Flooding 0
A-4 Attachment
MISCELLANEOUS DOCUMENTS
NUMBER TITLE REVISION
CALC-92-R-0024-01 Flooding Evaluation INPO SOER-85-5 0
CALC-92-R-0034-01 Flooding Evaluation INPO SOER-85-5 2nd Iteration
ULD-1-SYS-01 ANO Unit 1 Emergency Diesel Generator 5
ULD-0-TOP-02 Fire Protection Topical 4
CONDITION REPORTS
CR-ANO-1-2011-1343 CR-ANO-C-2011-0802 CR-ANO-1-2011-0744 CR-ANO-1-2011-0662
CR-ANO-1-2001-0661 CR-ANO-1-2011-0641
Section 1R07: Heat Sink Performance
PROCEDURES
NUMBER TITLE REVISION
OP-1309.016 Decay Heat Thermal Test 004-01-0
MISCELLANEOUS DOCUMENTS
NUMBER TITLE REVISION
ER-91-R-2013-01 Service Water Performance Testing Methodology 21
CONDITION REPORTS
CR-ANO-1-2011-2134 CR-ANO-1-2011-2014 CR-ANO-1-2011-1750 CR-ANO-1-2011-1712
Section 1R08: Inservice Inspection Activities
DOCUMENTS
NUMBER TITLE REVISION /
DATE
Entergy Steam Generator Degradation Assessment: Plant and 0
Unit - Arkansas Nuclear One Unit One, Refueling Outage:
1R23
Snapshot Assessment / Benchmark On: August 31,
Pre-NRC Inspection - In-service Inspection (ISI) 2011
1R23
Quarterly Health Reports 4Q2010, 1Q2011, 2Q2011, 3Q2011
A-5 Attachment
Section 1R08: Inservice Inspection Activities
DOCUMENTS
NUMBER TITLE REVISION /
DATE
1R20 Cycle Report Spring 2007
1032.037 Inspection And Identification Of Boric Acid Leaks For ANO-1 5
and ANO-2
1103.013 RCS Leak Detection 35
1CAN060902 Request for Alternative - Implementation of a Risk-Informed June 11, 2009
Inservice Inspection Program Based on ASME Code Case N-
716, Arkansas Nuclear One, Unit 1, Docket No. 50-313
License No. DPR-51
1CNA030901 Arkansas Nuclear One, Unit 1, Grand Gulf Nuclear Station, March 6, 2009
River Bend Station, and Waterford Steam Electric Station,
Unit 3 - Request for Alternative CEP-ISI-012, Use Alternative
Requirements In ASME Code Case N-753 (TAC NOS.
MD8813, MD8814, MD8815 AND MD8816)
1CNA061001 Arkansas Nuclear One, Unit No. 1 -Request For Alternative June 2, 2010
AN01-ISI-014 Re: Implementation Of a Risk-Informed
Inservice Inspection Program Based on ASME Code
Case N-716 (TAC No. ME1488)
20004-017 ENGINEERING INFORMATION RECORD, Document No.: 51 March 2010
- 9135783 - 000, Technical Summary of Steam Generator
Eddy Current Examinations at Arkansas Nuclear One, 1R22
51-9135783-000 Areva NP Inc, Engineering Information Record, Technical March 2010
Summary of Steam Generator Eddy Current Examinations at
Arkansas Nuclear One, 1R22.
CNRO-2008- Relief Requests for Third 120 Month Inservice Testing Interval May 20, 2008
00016
EN-DC-319 Inspection and evaluation of Boric Acid Leaks 7
EN-DC-319 Inspection and evaluation of Boric Acid Leaks 6
LO-ALO-2008- Boric Acid Corrosion Control Program (BACCP) Self August 13,
00090 Assessment 2009
LO-ALO-2010- Assessment Report: Welding Program Assessment August 2011
00056
A-6 Attachment
NDE PROCEDURES
NUMBER TITLE REVISION
CEP-NDE-0255 Radiographic Examination ASME, ANSI,AWS Welds and 6
Components
CEP-NDE-0400 Ultrasonic Examination 3
CEP-NDE-0404 Manual Ultrasonic Examination of Ferritic Piping Welds 5
(ASME XI)
CEP-NDE-0407 Straight Beam Ultrasonic Examinations of Bolts and Studs 3
(ASME XI)
CEP-NDE-0423 Manual Ultrasonic Examination of Austenitic Piping Welds 5
(ASME XI)
CEP-NDE-0497 Manual Ultrasonic Examination of Welds in Vessels (Non- 5
App. VIII)
CEP-NDE-0641 Liquid Penetrant Examination (PT) for ASME Section XI 7
CEP-NDE-0731 Magnetic Particle Examination (MT) for ASME Section XI 3
CEP-NDE-0901 VT-1 Examination 4
CEP-NDE-0902 VT-2 Examination 7
CEP-NDE-0903 VT-3 Examination 5
CONDITION REPORTS
CR-ANO-1-2011-02807 CR-ANO-1-2011-02789 CR-ANO-1-2011-00554 CR-ANO-1-2010-00956
CR-ANO-1-2010-00968 CR-ANO-1-2010-01986 CR-ANO-1-2011-00685 CR-ANO-1-2010-01983
CR-ANO-1-2010-00977 CR-ANO-1-2010-02009 CR-ANO-1-2011-00753 CR-ANO-1-2011-00512
CR-ANO-1-2010-01118 CR-ANO-1-2010-02021 CR-ANO-1-2011-00872 CR-ANO-1-2010-01966
CR-ANO-1-2010-01124 CR-ANO-1-2010-02055 CR-ANO-1-2011-00909 CR-ANO-1-2011-00318
CR-ANO-1-2010-01295 CR-ANO-1-2010-02071 CR-ANO-1-2011-01126 CR-ANO-1-2010-01948
CR-ANO-1-2010-01361 CR-ANO-1-2010-02073 CR-ANO-1-2011-01379 CR-ANO-1-2011-02736
CR-ANO-1-2010-01462 CR-ANO-1-2010-02089 CR-ANO-1-2011-01380 CR-ANO-1-2011-00250
CR-ANO-1-2010-01475 CR-ANO-1-2010-02087 CR-ANO-1-2011-01395 CR-ANO-1-2010-01933
CR-ANO-1-2010-01493 CR-ANO-1-2010-02173 CR-ANO-1-2011-01489 CR-ANO-1-2011-02258
CR-ANO-1-2010-01564 CR-ANO-1-2010-02197 CR-ANO-1-2011-01728 CR-ANO-1-2011-00157
CR-ANO-1-2010-01587 CR-ANO-1-2011-02213 CR-ANO-1-2011-01824 CR-ANO-1-2010-01930
CR-ANO-1-2010-01613 CR-ANO-1-2010-02218 CR-ANO-1-2011-01895 CR-ANO-1-2011-02224
CR-ANO-1-2010-01644 CR-ANO-1-2010-02516 CR-ANO-1-2011-01926 CR-ANO-1-2011-00034
CR-ANO-1-2010-01716 CR-ANO-1-2010-02605 CR-ANO-1-2011-01979 CR-ANO-1-2010-01922
CR-ANO-1-2010-01754 CR-ANO-1-2010-02734 CR-ANO-1-2011-01998 CR-ANO-1-2011-02213
CR-ANO-1-2010-01802 CR-ANO-1-2010-02736 CR-ANO-1-2011-02071 CR-ANO-1-2010-03760
CR-ANO-1-2010-01810 CR-ANO-1-2010-02900 CR-ANO-1-2011-02084 CR-ANO-1-2010-01907
CR-ANO-1-2010-01823 CR-ANO-1-2010-03617 CR-ANO-1-2011-02128 CR-ANO-1-2011-02173
A-7 Attachment
CONDITION REPORTS
CR-ANO-1-2010-01856 CR-ANO-1-2010-03754
Section 1R12: Maintenance Effectiveness
PROCEDURES
NUMBER TITLE REVISION
EN-DC-203 Maintenance Rule Program 1
EN-DC-204 Maintenance Rule Scope and Basis 2
EN-DC-205 Maintenance Rule Monitoring 3
EN-DC-206 Maintenance Rule (a)(1) Process 1
ULD-0-TOP-19 Upper Level Document Station Blackout 0
OP-2104.037 Alternate AC Diesel Generator Operations 21
MISCELLANEOUS DOCUMENTS
NUMBER TITLE DATE
Maintenance Rule Database Scoping and October 12, 2011
Performance Criteria - Unit 1 Alternate AC diesel
generator
Unit 1 Alternate AC diesel generator Functional October 12, 2011
Failure Determination Report
Maintenance Rule Database Scoping and November 15, 2011
Performance Criteria - Unit 1 Turbine Building
Unit 1 Turbine Building Functional Failure November 15, 2011
Determination Report
Unit 1 Reactor Building Spray - Maintenance Rule November 28, 2011
Database Scoping and Performance Criteria
Unit 1 Reactor Building Spray - Maintenance Rule November 28, 2011
Functional Failure Determination Report
CONDITION REPORTS
CR-ANO-C-2011-1639 CR-ANO-C-2011-1971 CR-ANO-C-2011-1862 CR-ANO-1-2011-0567
CR-ANO-C-2011-0061 CR-ANO-1-2011-1617 CR-ANO-1-2011-2075 CR-ANO-1-2011-0588
CR-ANO-1-2011-0999
A-8 Attachment
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
PROCEDURE
NUMBER TITLE REVISION
OP-1203.025 Natural Emergencies 35
CONDITION REPORTS
CR-ANO-C-2011-2952
Section 1R15: Operability Evaluations
PROCEDURES
NUMBER TITLE REVISION
EN-OP-104 Operability Evaluations 5
OP-1105.001 Unit 1 Nuclear Instrumentation and Reactor Protection 25
System Operating Procedure
CALCULATIONS
NUMBER TITLE REVISION
CALC-ANO1-NE- ANO Unit 1 Cycle 24 Core Operating Limits Report 3
11-00002
MISCELLANEOUS DOCUMENTS
NUMBER TITLE REVISION
STM-1-63 Unit 1 Reactor Protection System 9
CONDITION REPORTS
CR-ANO-1-2011-1655 CR-ANO-1-2011-1659 CR-ANO-1-2011-1667 CR-ANO-1-2010-3653
CR-ANO-1-2011-1672 CR-ANO-1-2011-3044 CR-ANO-1-2011-3183 CR-ANO-1-2011-0896
A-9 Attachment
Section 1R18: Plant Modifications
PROCEDURES
NUMBER TITLE REVISION
EN-DC-115 Engineering Change Process 12
EN-DC-136 Temporary Modifications 6
ENGINEERING CHANGE DOCUMENTS
WORK ORDERS
00277055 00279037
Section 1R19: Postmaintenance Testing
PROCEDURES
NUMBER TITLE REVISION
OP-2304.039 Unit 2 Plant Protection System Channel C Test 47
OP-1305.007 RB Isolation and Miscellaneous Valve Stroke Test 39
EN-MA-101 Fundamentals of Maintenance 9
EN-WM-102 Work Implementation and Closeout 6
EN-WM-105 Planning 9
EN-WM-107 Post Maintenance Testing 3
WORK ORDERS
50271508 52326209
Section 1R20: Refueling and Other Outage Activities
PROCEDURES
NUMBER TITLE REVISION /
DATE
1-OPG-002 Unit 1 Tank Volume Book April 5, 2011
OP-1104.006 Unit 1 Spent Fuel Cooling System 51
OP-1506.001 Fuel and Control Component Handling 41
OP-1502.004 Control of Unit 1 Refueling 49
A-10 Attachment
Section 1R20: Refueling and Other Outage Activities
PROCEDURES
NUMBER TITLE REVISION /
DATE
OP-1502.003 Refueling Equipment and Operator Checkouts 35
OP-1103.011 Draining and N2 Blanketing the RCS 39
EN-OM-123 Fatigue Management Program 3
CONDITION REPORTS
CR-ANO-1-2011-2495 CR-ANO-1-2011-2498 CR-ANO-1-2011-2843 CR-ANO-C-2011-3017
CR-ANO-1-2011-0493 CR-ANO-1-2005-1405 CR-ANO-1-2010-0370 CR-ANO-1-2011-2558
CR-ANO-1-2011-2211 CR-ANO-1-2011-2814 CR-ANO-1-2011-2815 CR-ANO-1-2010-1028
CR-ANO-1-2011-2412 CR-ANO-1-2011-0769 CR-ANO-1-2011-1846
MISCELLANEOUS DOCUMENTS
NUMBER TITLE REVISION
STM-1-51-1 Refueling Machine & Reactor Bldg Fuel Handling Equipment 4
STM-1-51-2 Spent Fuel Handling & SFP Area Equipment 10
STM-1-51-3 Fuel Transfer System 2
Section 1R22: Surveillance Testing
PROCEDURES
NUMBER TITLE REVISION
OP-1305.018 Unit 1 Local Leak Rate Testing - Type C 23
OP-1305.006 Unit 1 Integrated Engineered Safeguards System Test 35
OP-1104.002 Unit 1 Makeup and Purification System Operation 72
OP-1104.027 Unit 1 Battery and Switchgear Emergency Cooling System 40
OP-2305.017 Local Leak Rate Testing 28
CONDITION REPORTS
CR-ANO-1-2011-1882 CR-ANO-1-2011-2660 CR-ANO-1-2011-2783 CR-ANO-2-2011-0820
CR-ANO-1-2011-2757 CR-ANO-1-2011-2021 CR-ANO-1-2011-2526 CR-ANO-2-2011-0800
CR-ANO-1-2011-2312 CR-ANO-1-2011-2316 CR-ANO-1-2011-2524 CR-ANO-1-2011-2700
CR-ANO-1-2011-2516 CR-ANO-1-2011-2130
A-11 Attachment
WORK ORDERS
52274060
Section 1EP4: Emergency Action Level and Emergency Plan Changes
PROCEDURES
NUMBER TITLE REVISION
OP-1903.011P SAE Emergency Direction and Control Checklist Shift Manager 42
OP-1903.011Y Emergency Class Initial Notification Message 40
Section 4OA1: Performance Indicator Verification
PROCEDURES
NUMBER TITLE REVISION
EN-LI-114 Performance Indicator Process 4
MISCELLANEOUS DOCUMENTS
NUMBER TITLE DATE
Unit 1 MSPI Derivation Report - Emergency AC Power October 28, 2011
System - Unavailability Index
Unit 1 MSPI Derivation Report - Emergency AC Power October 28, 2011
System - Unreliability Index
Unit 1 Emergency Diesel Generator 1 Conditional October 28, 2011
Probability Data
Unit 1 Emergency Diesel Generator 2 Conditional October 28, 2011
Probability Data
Unit 1 MSPI Derivation Report - High Pressure Injection October 28, 2011
System - Unavailability Index
Unit 1 MSPI Derivation Report - High Pressure Injection October 28, 2011
System - Unreliability Index
Unit 1 Makeup and Purification 1P36A Pump Conditional November 30, 2011
Probability Data
Unit 1 Makeup and Purification 1P36B Pump Conditional November 30, 2011
Probability Data
Unit 1 Makeup and Purification 1P36C Pump Conditional November 30, 2011
Probability Data
A-12 Attachment
Section 4OA2: Identification and Resolution of Problems
PROCEDURES
NUMBER TITLE REVISION
COPD-001 Operations Expectations and Standards 55
COPD-020 ANO Operations Concerns Program 10
EN-FAP-OP-006 Operator Aggregate Impact Index Performance Indicator 6
OP-2304.258 Unit 2 Escape Airlock Leak Rate Test 17
OP-2305.017 Local Leak Rate Testing 26
OP-2411.029 Emergency Air Lock Inspection, Lubrication and Chalk Test 5
OP-1015.001 Conduct of Operations 89
OP-1015.049 Configuration Control Program 1
OP-1103.002 Draining and Nitrogen Blanketing the Reactor Coolant 41
System
OP-1103.011 Filling and Venting the Reactor Coolant System 37
OP-1104.004 Decay Heat Removal Operating Procedure 94
OP-1104.002 Unit 1 Makeup and Purification System Operation 72
DRAWINGS
NUMBER TITLE REVISION
DWG 30970 Emergency Access Airlock - General Arrangement 0
DWG 30970 Emergency Access Airlock - General Assembly 0
MISCELLANEOUS DOCUMENTS
NUMBER TITLE DATE
Nuclear Oversight Fleet Trimester Report October 2011
Unit 1 Top Ten Reliability Issues
Unit 2 Top Ten Reliability Issues
CONDITION REPORTS
CR-ANO-2-2011-0888 CR-ANO-2-2011-1197 CR-ANO-2-2011-1687 CR-ANO-2-2011-3264
CR-ANO-2-2011-0768 CR-ANO-C-2011-2241 CR-ANO-C-2011-2942 CR-ANO-2-2011-3170
CR-ANO-1-2011-1740 CR-ANO-1-2011-1744 CR-ANO-1-2011-1851 CR-ANO-2-2011-3294
A-13 Attachment
CONDITION REPORTS
CR-ANO-1-2011-1812 CR-ANO-1-2011-2312 CR-ANO-1-2011-2498 CR-ANO-2-2011-2696
CR-ANO-1-2007-1667 CR-ANO-1-2011-0328 CR-ANO-1-2010-2370 CR-ANO-2-2011-3533
CR-ANO-1-2009-0014 CR-ANO-1-2011-0967 CR-ANO-1-2011-1666 CR-ANO-2-2011-2263
CR-ANO-1-2011-1797 CR-ANO-1-2011-2145 CR-ANO-1-2011-2319 CR-ANO-2-2011-2166
CR-ANO-1-2011-3049 CR-ANO-1-2011-3077 CR-ANO-1-2011-0858 CR-ANO-2-2011-2179
CR-ANO-1-2011-3070 CR-ANO-2-2008-2360 CR-ANO-2-2009-0176 CR-ANO-2-2011-1663
CR-ANO-2-2011-3250 CR-ANO-2-2009-3566 CR-ANO-2-2010-0923 CR-ANO-2-2011-1687
CR-ANO-2-2010-0056 CR-ANO-2-2011-0103 CR-ANO-2-2011-0644 CR-ANO-2-2011-1343
CR-ANO-2-2011-0924 CR-ANO-2-2011-1318 CR-ANO-2-2011-1411
A-14 Attachment