ML12318A341
| ML12318A341 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 11/13/2012 |
| From: | Hay M Division Reactor Projects III |
| To: | Cortopassi L Omaha Public Power District |
| Hay M | |
| References | |
| EA-12-174 IR-12-005 | |
| Download: ML12318A341 (56) | |
See also: IR 05000285/2012005
Text
November 13, 2012
Louis P. Cortopassi, Site Vice President
Omaha Public Power District
Fort Calhoun Station FC-2-4
P.O. Box 550
Fort Calhoun, NE 68023-0550
Subject: FORT CALHOUN - NRC INTEGRATED INSPECTION REPORT NUMBER
05000285/2012005, AND NOTICE OF VIOLATION
Dear Mr. Cortopassi:
On September 30, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Fort Calhoun Station. The enclosed inspection report documents the
inspection results which were discussed on October 18, 2012, with Mike Prospero, Plant
Manager, and other members of your staff, and on November 7, 2012, with you, and other
members of your staff.
The inspection(s) examined activities conducted under your license as they relate to safety and
compliance with the Commission=s rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection a Severity Level IV violation of NRC requirements was
identified involving the failure to update the Updated Safety Analyis Report. This violation was
evaluated in accordance with the NRC Enforcement Policy. The violation is being cited in the
enclosed Notice of Violation (Notice) and the circumstances surrounding it are described in
detail in the subject inspection report. The violation is being treated as a cited violation,
consistent with Section 2.3.2(a)(3) of the NRC Enforcement Policy. Specifically, this violation
was repetitive as a result of ineffective corrective actions and was identified by the NRC.
You are required to respond to this letter and should follow the instructions specified in the
enclosed Notice when preparing your response. If you have additional information that you
believe the NRC should consider, you may provide it in your response to the Notice. The NRC
review of your response to the Notice will also determine whether further enforcement action is
necessary to ensure compliance with regulatory requirements.
One NRC identified finding of very low safety significance (Green) was identified during this
inspection. This finding was determined to involve a violation of NRC requirements. The NRC is
treating this violation as a noncited violation consistent with Section 2.3.2 of the Enforcement
Policy.
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION IV
1600 EAST LAMAR BLVD
ARLINGTON, TEXAS 76011-4511
L. Cortopassi
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If you contest these 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 Fort Calhoun
Station.
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 Fort
Calhoun Station.
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
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/
Mr. Michael Hay
Chief, Project Branch F
Division of Reactor Projects
Docket: 50-285
License: DPR-40
Enclosures:
2. NRC Inspection Report 05000285/2012005
w/Attachment: Supplemental Information
cc w/ encl: Electronic Distribution
L. Cortopassi
- 3 -
DISTRIBUTION:
Electronic distribution by RIV:
Regional Administrator (Elmo.Collins@nrc.gov)
Deputy Regional Administrator (Art.Howell@nrc.gov)
DRP Director (Kriss.Kennedy@nrc.gov)
ACTING DRP Deputy Director (Barry.Westreich@nrc.gov)
ACTING DRS Director (Tom.Blount@nrc.gov)
ACTING DRS Deputy Director (Jeff.Clark@nrc.gov)
MC0350 Panel Chair (Anton.Vegel@nrc.gov)
MC0350 Panel Co-Chair (Louise.Lund@nrc.gov)
MC0350 Panel Member (Michael.Balazik@nrc.gov)
MC0350 Panel Member (Michael.Markley@nrc.gov)
Senior Resident Inspector (John.Kirkland@nrc.gov)
Resident Inspector (Jacob.Wingebach@nrc.gov)
Branch Chief, DRP/F (Michael.Hay@nrc.gov)
Senior Project Engineer, DRP/F (Rick.Deese@nrc.gov)
Project Engineer, DRP/F (Chris.Smith@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Acting Branch Chief, DRS/TSB (Ryan.Alexander@nrc.gov)
Project Manager (Lynnea.Wilkins@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Technical Support Assistant (Loretta.Williams@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
OEMail Resource
ROPreports
RIV/ETA: OEDO (Cayetano.Santos@nrc.gov)
DRS/TSB STA (Dale.Powers@nrc.gov)
R:_REACTORS\\_FCS\\2012\\FCS 2012-005 RP JCK.DOCX
SUNSI Rev Compl.
Yes No
Yes No
Reviewer Initials
MCH
Publicly Avail.
Yes No
Sensitive
Yes No
Sens. Type Initials
MCH
SRI:DRP/F
SPE:DRP/F
SPE:DRP/F
C:DRS/PSB2
C:ORA/ACES BC:DRP/.F
JCKirkland
JFWingebach
RWDeese
JDrake
HGepford
MCHay
/RA via E/
/RA via E/
/RA/
/RA/
/CYoung for/
/RA/
11/13/12
11/13/12
11/8/12
11/13/12
11/13/12
11/13/12
- 1 -
Enclosure 1
Omaha Public Power District
Docket No.:
05000285
Fort Calhoun Station
License No.: DPR-40
During an NRC inspection conducted from June 18 to August 3, 2012, a violation of NRC
requirements was identified. In accordance with the NRC Enforcement Policy, the violation is
listed below:
Title 10 CFR 50.71(e) requires, in part, that each person licensed to operate a nuclear
power reactor under the provisions of 50.21 or 50.22, shall update periodically the final
safety analysis report (FSAR) originally submitted as part of the application for the
license, to assure that the information included in the report contains the latest
information developed. The submittal shall include the effects of all changes made in the
facility or procedures as described in the FSAR; and all safety analyses and evaluations
performed by the applicant or licensee either in support of approved license
amendments or in support of conclusions that changes did not require a license
amendment in accordance with § 50.59(c)(2). The updated information shall be
appropriately located within the update to the FSAR.
Contrary to the above, from December 2006 to June 2012, the licensee failed to assure
that the information included in the Updated Safety Analysis Report contains the latest
information developed, including the effects of all changes made in the facility or
procedures as described in the Report. Specifically, since December 2006, the licensee
stored a significant source of radioactivity in the Original Steam Generator Storage
Facility but failed to describe the volume of waste, the principal sources of radioactivity,
the total quantity of radioactivity, and the estimated dose rate at the site boundary per
curie of radioactivity in the Updated Safety Analysis Report.
This is a Severity Level IV violation (Section 6.1.d).
Pursuant to the provisions of 10 CFR 2.201, Omaha Public Power District is hereby required to
submit a written statement or explanation to the U.S. Nuclear Regulatory Commission,
ATTN: Document Control Desk, Washington, DC 20555-0001 with a copy to the Regional
Administrator, Region IV, and a copy to the NRC Resident Inspector - Fort Calhoun Station,
within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply
should be clearly marked as a "Reply to a Notice of Violation; EA-12-0174" and should include
for each violation: (1) the reason for the violation or, if contested, the basis for disputing the
violation or severity level, (2) the corrective steps that have been taken and the results
achieved, (3) the corrective steps that will be taken, and (4) the date when full compliance will
be achieved. Your response may reference or include previous docketed correspondence if the
correspondence adequately addresses the required response. If an adequate reply is not
received within the time specified in this Notice, an order or a Demand for Information may be
issued as to why the license should not be modified, suspended, or revoked, or why such other
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action as may be proper should not be taken. Where good cause is shown, consideration will
be given to extending the response time.
If you contest this enforcement action, you should also provide a copy of your response with the
basis for your denial, to the Director, Office of Enforcement, United States Nuclear Regulatory
Commission, Washington, DC 20555-0001.
Because your response will be made available electronically for public inspection in the NRC
Public Document Room or from the NRCs document system (ADAMS), accessible from the
NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should not
include any personal privacy, proprietary, or safeguards information so that it can be made
available to the public without redaction. If personal privacy or proprietary information is
necessary to provide an acceptable response, then please provide a bracketed copy of your
response that identifies the information that should be protected and a redacted copy of your
response that deletes such information. If you request withholding of such material, you must
specifically identify the portions of your response that you seek to have withheld and provide in
detail the bases for your claim of withholding (e.g., explain why the disclosure of information will
create an unwarranted invasion of personal privacy or provide the information required by
10 CFR 2.390(b) to support a request for withholding confidential commercial or financial
information). If safeguards information is necessary to provide an acceptable response, please
provide the level of protection described in 10 CFR 73.21.
In accordance with 10 CFR 19.11, you may be required to post this Notice within two working
days of receipt.
Dated this 13th day of November 2012
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Enclosure 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
05000285
License:
Report:
Licensee:
Omaha Public Power District
Facility:
Fort Calhoun Station
Location:
9610 Power Lane
Blair, NE 68008
Dates:
August 19 through September 30, 2012
Inspectors:
J. Kirkland, Senior Resident Inspector
J. Wingebach, Resident Inspector
A. Klett, Reactor Operations Engineer
A. Rosebrook, Senior Project Engineer
R. Deese, Senior Project Engineer
F. Ramirez, Resident Inspector
K. Clayton, Senior Operations Engineer
W. Smith, Project Engineer
A. Fairbanks, Reactor Inspector
Approved By:
Michael Hay, Chief, Project Branch F
Division of Reactor Projects
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SUMMARY OF FINDINGS
IR 05000285/2012005; 08/19/2012 - 09/30/2012; Fort Calhoun Station, Integrated Resident,
Inservice Inspection, and Confirmatory Action Letter Report
The report covered a 6-week period of inspection by resident inspectors and announced baseline
inspections by region-based inspectors. One Green noncited violation and one Severity Level IV
cited violation 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: Initiating Events
Green. The NRC identified a noncited violation (NCV) of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Actions, for the failure to take timely corrective actions with
respect to nonconforming conditions in several circuit breakers. These conditions were
determined to have been the cause of the 1B4A bus bar failure that initiated a fire on
June 7, 2011. These conditions were not corrected in a timely manner and the licensee
continued to operate with a degraded breaker for nine months after the breaker tripped
unexpectedly during the June 7, 2011, fire event. The licensee entered this issue into
their corrective action program as CRs 2012-01884 and 2011-5414.
The violation was determined to be more than minor because it affected the Initiating
Events Cornerstone attribute of protection against external events (i.e., fire). The issue
adversely affected the associated cornerstone objective of limiting the likelihood of those
events that upset plant stability and challenge critical safety functions during shutdown as
well as power operations because the condition that contributed to the fire event was left
uncorrected. The finding screened to Green in accordance with IMC 0609, Appendix G
because RCS makeup capability was not degraded. The inspectors determined that the
issue had a cross-cutting aspect in the area of Problem Identification and Resolution,
Corrective Action Program (P.1(d)). (4OA4.1.c.(3).2).
Cornerstone: Miscellaneous
SLIV. The inspectors identified a cited violation of 10 CFR 50.71(e), Maintenance of
Records, Making of Reports, for the failure to update the Updated Safety Analysis
Report with a detailed description of the Original Steam Generator Storage Facility.
Specifically, since December 2006, the licensee stored a significant source of
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radioactivity in the Original Steam Generator Storage Facility, but failed to describe the
volume of waste, the principal sources of radioactivity, the total quantity of radioactivity,
and the estimated dose rate at the site boundary per curie of radioactivity in the
Updated Safety Analysis Report. The licensee has entered this violation into their
corrective action program as Condition Report 2012-05725.
This issue was evaluated using traditional enforcement because it has the potential to
impact the NRCs ability to perform its regulatory function. This issue is being
characterized as a Severity Level IV violation in accordance with Section 6.1.d.3 of the
NRC Enforcement Policy. Cross-cutting aspects are not assigned to traditional
enforcement violations (Section 2RS08).
B.
Licensee-Identified Violations
None
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REPORT DETAILS
Summary of Plant Status
The station remained in Mode 5 with the fuel in the reactor vessel for the entire inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R08 Inservice Inspection Activities (71111.08)
a. Inspection Scope
During August through November, 2012, the inspectors completed a focused inspection
of the steam generators in response to the San Onofre Nuclear Generating Station
(SONGS) primary to secondary steam generator leakage. The inspection focused on
similarities of steam generator design, and verified that the types of degradation affecting
SONGS steam generators does not impact the steam generators at the Fort Calhoun
Station. The inspection focused on:
Retainer and freespan indications.
Adequacy of Mitsubishis thermal-hydraulic model.
Refueling outage eddy current testing results.
10 CFR 50.59 review
The inspectors reviewed the updated safety analysis report (USAR), steam generator
design documents, eddy current testing (ECT) procedures and data results, corrective
actions, and performed a walkdown of the steam generators. The inspectors also
attended a presentation provided to the licensee by Mitsubishi Heavy Industries (MHI).
Specifically, the inspectors reviewed:
10 CFR 50.59 evaluation of the replacement steam generators.
Eddy current examination reports for the 2008 refueling outage.
Secondary inspection results for the 2008 refueling outage.
MHI presentation that included discussions on retainer bar random vibrations, and
in-plane flow elastic instabilities of tube-to-tube wear.
Fort Calhoun steam generator long term inspection strategy plan.
Westinghouse second review of eddy current testing data.
Independent review of raw ECT data on EddyNet format
Industry experience has shown that most deficiencies in steam generator design are
typically identified during eddy current inspections following the first operating cycle. The
steam generators at Fort Calhoun Station were replaced in 2006, and inspected during
the refueling outage in 2008. NRC experts performed an independent review of select
ECT raw data, with an emphasis on low frequencies absolute data channels indicative of
tube-to-tube wear, with no issues identified. As a result of the information presented to
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the NRC, including a Westinghouse second review of ECT data, the NRCs independent
review of the same data, and positive industry experience of steam generator designs not
experiencing issues after a successful first cycle inspection, the inspectors determined
that reasonable assurance exists that the degradation mechanism experienced in
SONGS steam generators does not exist at this time for the Fort Calhoun Station.
The inspectors will review the following documentation as it becomes available:
Revised degradation and operational assessment.
Certain aspects documented as open items in the SONGS Augmented Inspection Team
report (ML12188A748) have the potential to require further inspections at Fort Calhoun
Station.
b. Findings
No findings were identified.
1R15 Operability Evaluations and Functionality Assessments (71111.15)
a. Inspection Scope
The inspectors reviewed the following assessments:
August 31, 2012, Operability of the reactor cavity walls prior to moving fuel from
the reactor vessel to the spent fuel pool
The inspectors selected these operability and functionality assessments based on the risk
significance of the associated components and systems. The inspectors evaluated the
technical adequacy of the evaluations to ensure technical specification operability was
properly justified and to verify 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 USAR to
the licensees 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. Additionally, the inspectors 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 one operability evaluations inspection sample as
defined in Inspection Procedure 71111.15-05.
b. Findings
No findings were identified.
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1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed the USAR, 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
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.
August 28, 2012, OP-ST-FH-0005, Refueling System Spent Fuel Handling
Machine Refueling Interlocks Test
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September 1, 2012, OP-ST-FH-0002, Refueling System Fuel Transfer System
Interlocks Test
September 4, 2012, OP-ST-FH-0001, Refueling System Fuel Handling Machine
(FH-1) Interlocks Test
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of three surveillance testing inspection samples as
defined in Inspection Procedure 71111.22-05.
b. Findings
No findings were identified.
2RS08 Radioactive Solid Waste Processing, and Radioactive Material Handling, Storage,
and Transportation (71124.08)
a.
Inspection Scope
This area was inspected to verify the effectiveness of the licensees programs for
updates to the Updated Safety Analyiss Report related to the processing, handling, and
storage of radioactive material.
b.
Findings
(1) Failure to Update the Updated Safety Analysis Report-Solid Wastes
Introduction. The inspectors identified a Severity Level IV violation of 10 CFR 50.71(e),
Maintenance of Records, Making of Reports, for failure to update the Updated Safety
Analysis Report with information about the Original Steam Generator Storage Facility that
was constructed in 2006 for long-term storage of large decommissioned components .
Description. In 2006, the licensee built the Original Steam Generator Storage Facility for
long-term solid radioactive waste storage of the two original steam generators, the
pressurizer, the reactor vessel head, and four concrete reactor vessel head missile shield
blocks. From the licensees estimation, the Original Steam Generator Storage Facility
contained 404 curies. However, this significant source of radioactivity was not described
in the licensees Updated Safety Analysis Report. On November 10, 2010, the NRC
identified a Severity Level IV noncited violation for the failure to update the Updated
Safety Analysis Report per 10 CFR 50.71(e) because the licensee had not described the
Original Steam Generator Storage Facility in the Updated Safety Analysis Report (NCV 05000285/2010004-03).
During the June 2012 radiation protection inspection, the inspectors toured the
Original Steam Generator Storage Facility and reviewed the licensees implementation of
corrective actions associated with the previous violation. The licensees corrective actions
for the 2010 noncited violation were initially addressed in Condition Report 2010-03636
and included an apparent cause analysis. The licensees apparent cause for the violation
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stated that the Engineering Change Package was developed to an unknowable or
changing [NRC] requirement. The condition report further stated that this violation
showed a common misapplication of the regulations related to storage which may have
been in place for several years. The condition report also stated that engineering will be
contacted to perform a 10 CFR 50.59 screening and update the USAR by January 2011.
However, the inspectors determined that the licensee did not implement corrective
actions based on the noncited violation as addressed in Condition Report 2010-03636.
In 2011, the licensee did not update the Updated Safety Analysis Report to describe the
Original Steam Generator Storage Facility.
Prior to the June 2012 inspection, the licensee performed a self-assessment as part of
Condition Report 2012-03704 to verify that Chapter 11 of the Updated Safety Analysis
Report had been updated, including a description of the Original Steam Generator
Storage Facility. Based on the self-assessment results, the licensee submitted a
revision to the Updated Safety Analysis Report Chapter 11.2.4.1, Radioactive Waste
Storage to the NRC in June 2012. The inspectors review determined that the
information added in the June 2012 revision of the Updated Safety Analysis Report was
inadequate. The licensees update in Chapter 11.2.4.1, of the Updated Safety Analysis
Report merely stated that radwaste waiting disposal is stored in the Original Steam
Generator Storage Facility located on the west side of the plant site, north of the main
access road. The inspectors concluded that the Original Steam Generator Storage
Facility was being used to store a significant source of radioactivity that was not
adequately described in Chapter 11 of the licensees Updated Safety Analysis Report.
Some of the information missing about the Original Steam Generator Storage Facility
included the volume of waste, the principal sources of radioactivity, the total quantity of
stored radioactivity, and the estimated dose rate at the site boundary per curie of stored
waste.
As of June 22, 2012, the inspectors concluded that the corrective actions implemented
in Condition Report 2010-03636 for the 2010 violation and the self-assessment under
Condition Report 2012-03704 were inadequate to comply with 10 CFR 50.71(e), in that,
Chapter 11 of the Updated Final Safety Analysis Report did not adequately describe the
Original Steam Generator Storage Facility. This issue was entered into the licensees
corrective action program as Condition Report 2012-05725.
Analysis. Failure to update the Updated Safety Analysis Report as required by
10 CFR 50.71(e) with a detailed description of the Original Steam Generator Storage
Facility was a performance deficiency. This issue was evaluated using traditional
enforcement because it had the potential to impact the NRCs ability to perform its
regulatory function. The issue was characterized as a Severity Level IV violation in
accordance with Section 6.1.d.3 of the NRC Enforcement Policy, in that, the erroneous
[incomplete] information in the Final Safety Analysis Report Update was not used to
make an unacceptable change to the facility or procedures. Cross-cutting aspects are
not assigned to traditional enforcement violations.
- 9 -
Enforcement. 10 CFR 50.71(e), Maintenance of Records, Making of Reports, states, in
part, that each person licensed to operate a nuclear power reactor shall update
periodically the Updated Safety Analysis Report originally submitted as part of the
application for the license, to assure that the information included in the report contains
the latest information developed. Contrary to the above, from December 2006 to June
2012, the licensee failed to assure that the information included in the Updated Safety
Analysis Report contains the latest information developed to include the effects of all
changes made in the facility. Specifically, since December 2006, the licensee stored a
significant source of radioactivity in the Original Steam Generator Storage Facility, but
failed to describe the volume of waste, the principal sources of radioactivity, the total
quantity of radioactivity, and the estimated dose rate at the site boundary per curie of
radioactivity in the Updated Safety Analysis Report. This violation is being treated as a
cited violation, consistent with Section 2.3.2(a)(3) of the NRC Enforcement Policy:
NOV 05000285/2012005-01, Failure to Update the Updated Safety Analysis Report-
Solid Waste.
4.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
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 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.
- 10 -
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.
4OA3 Followup of Events and Notices of Enforcement Discretion (71153)
.1 (Open) Licensee Event Report 05000285/2011-010-00: Fire Causes a Circuit Breaker to
Open Outside Design Assumptions
On June 7, 2011, a bus fault in load center 1B4A initiated a switch gear fire that resulted
in the opening of a circuit breaker which supplies power to load center 1B3A, associated
with the opposite train. A fire in one fire area that resulted in a loss of power to a load
center associated with the opposite train is not in compliance with 10 CFR 50, Appendix
R. The analysis assumes that a fire in a fire area affecting one train of power will be
isolated such that power associated with the redundant train will be maintained.
A root cause analysis is being performed to determine the cause of the failure.
The affected bus was de-energized and the Halon system extinguished the fire. The
Halon system was recharged and restored to service. Inspections and testing of the
unaffected 480 V buses, the supply circuit breakers to the 480 V buses, and the 480 V
bus tie circuit breakers were performed. Appropriate 480 V supply circuit breakers and
bus tie circuit breakers passed their inspections and testing. The fire damaged switchgear
(1B4A), which contains two 480V supply circuit breakers, 1B4A and BT-1B4A (supply
circuit breaker to the associated island bus), is being replaced. Additional corrective
actions will be specified following the completion of the root cause analysis.
.2 (Open) Licensee Event Report 05000285/2012-014-00: Containment Beam 22 Loading
Conditions Outside of the Allowable Limits
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On July 11, 2012, while performing the Extent of Condition for an existing Condition
Report (CR) it was determined that Beam B-22, a structural member of the containment
internal structure at the 1013 foot elevation, loading conditions were outside the allowable
limits for both Working Stress and No Loss of Function load combinations as noted in the
USAR Section 5.11. This condition was identified on July 11, 2011, while the unit was
shutdown and reported to the U.S. Nuclear Regulatory Commission (NRC) Headquarters
Operations Center the same day at approximately 1603 CDT under Event Notification 48094.
A cause analysis is being evaluated and will be published in a supplement to this LER.
.3 (Open) Licensee Event Report 05000285/2012-015-00: Electrical Equipment Impacted by
High Energy Line Break Outside of Containment
While reviewing a draft of the Master List Reconstitution for Electrical Equipment
Qualification (EA-FC-08-011), Fort Calhoun Station (FCS) Engineering Department
identified that some of the listed components may not be qualified for the environments
where they are located. This was discovered during a comprehensive re-evaluation of
potential high energy line breaks and radiological impacts outside containment initiated in
response to issues identified by the station staff. This condition was identified on
September 16, 2011, while the unit was shutdown.
A cause analysis is in progress. The results of the analysis will be published in a
supplement to this LER.
.4 (Open) Licensee Event Report 05000285/2012-016-00: Unanalyzed Charging System
Socket Welds to the Reactor Coolant System
On July 17, 2012, Fort Calhoun Station (FCS) identified a deficiency as part of the
analyses being performed in support of resolution to the question as to whether some
Class I pipe was potentially not qualified as Class 1. Condition Report (CR) 2012-07724
documented that preliminary results from an Thermal Fatigue Analysis on the chemical
and volume control system (CVCS) concluded that; 1) The 2 inch socket welded fittings
on Reactor Coolant System (RCS) branch line piping cannot be qualified, and 2) The 2
inch charging lines are considered to be in an unanalyzed condition exceeding thermal
cycle fatigue and seriously degraded.
A cause analysis was completed and determined that the CVCS Class 1 piping was
constructed using socket welded fittings.
CVCS was declared inoperable. The normal charging headers to the RCS are classified
as inoperable until further evaluations or required repairs are performed. CVCS has been
isolated to prevent any further thermal transients to the suspect welds. In addition, the
affected waste disposal piping line which was scoped under the extent of condition is
being addressed under CR 2012-12184. Contingency actions have already been taken to
secure the letdown line so no thermal stress may be introduced to those socket welds.
The affected welds will be replaced prior to plant heatup.
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4OA4 IMC 0350 Inspection Activities (92702)
Inspectors began the IMC 0350 inspection activities, which include follow-up on the restart
checklist contained in Confirmatory Action Letter (CAL) 4-12-002 issued June 11, 2012. The
purpose of the beginning phase of this inspection is to assess the licensees performance and
progress in addressing its implementation and effectiveness of FCSs Integrated Performance
Improvement Plan (IPIP), significant performance issues, weaknesses in programs and
processes, and flood restoration activities. This phase of inspection determines whether the
depth and breadth of performance concerns are understood.
Inspectors used the criteria described in baseline and supplemental inspection procedures,
various programmatic NRC inspection procedures, and IMC 0350 to assess the licensees
performance and progress in implementing its performance improvement initiatives. Inspectors
performed on-site and in-office activities, which are described in more detail in the following
sections of this report. This report covers inspection activities from July 16 through
August 18, 2012. Specific documents reviewed during this inspection are listed in the
attachment.
The following inspection scope, assessments, observations, and findings are documented by
CAL restart checklist item number.
.1 Causes of Significant Performance Deficiencies and Assessment of Organizational
Effectiveness
Section 1 of the restart checklist contains those items necessary to develop a comprehensive
understanding of the root causes of safety-significant performance deficiencies identified at
Fort Calhoun Station. In addition, Section 1 includes the independent safety culture
assessment with the associated root causes and findings. The integration of the
assessments under Item 1.f identifies the fundamental aspects of organizational performance
in the areas of organizational structure and engagement, values, standards, culture, and
human behaviors that have resulted in the protracted performance decline and are critical for
sustained performance improvement. Section 1 reviews also include an assessment against
appropriate NRC Inspection Procedure 95003 key attributes. These assessments are
documented in section 4OA4.5.
.a Flooding Issue - Yellow Finding
Item 1.a is included in the restart checklist for the failure of Fort Calhoun Station to
maintain procedures and equipment that protects the plant from the effects of a design
basis flood. These deficiencies resulted in a Yellow (substantial safety significance)
finding.
(1) Inspection Scope
Item 1.a is included in the restart checklist because the licensee failed to maintain
procedures and equipment that protects the plant from the effects of a design basis
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flood. These deficiencies resulted in a finding having Yellow (i.e., substantial) safety
significance. During the inspection period covered by this report, the NRC inspectors
assessed, and will continue to assess during upcoming inspection periods, the
licensees root cause, extent of cause, and extent of condition evaluations related to
the Yellow finding. In addition, the inspectors continued to verify that corrective
actions are adequate to address the root and contributing causes.
The onsite activities included specific walk-downs of licensee procedure to mitigate
flooding such as PE-RR-AE-1001, Flood Barrier and Sandbag Staging and
Installation, PE-RR-AE-1002, Installation of Portable Steam Generator Pumps,
Abnormal Operating Procedure (AOP)-1, Acts of Nature Section I, Flood, and
OI-CW-1, Circulating Water System Normal Operation, Attachment 18, Sand
IntrusionMitigation. In addition, the inspectors completed a more detailed walk-down
of the intake structure and pre-staged flooding equipment; interviews with personnel
involved in the flooding emergency preparedness and recovery efforts; and
observation of recovery effort meetings. The in-office activities consisted of reviews
of documents associated with the recovery efforts, procedures associated with
flooding mitigation strategies, system lesson plans, and condition reports.
(2) Assessment
The inspectors review focused mainly on the adequacy of procedures that are
associated with mitigation strategies for a design basis flood. As a result of the
various procedure walk-downs, the inspectors had observations associated with
procedure sustainability and quality. For example, PE-RR-AE-1001, Attachment 23,
Fuel Transfer Hose to Emergency Diesel Generator (EDG) Day Tanks, does not
prescribe a specific plan to route the EDG fuel transfer hose. This procedure
attachment is used to provide the EDG day tanks with fuel in the event elevated river
levels were expected to last longer than 7 days. The inspectors identified that the
procedure did not contain detailed information regarding how the hose would be
routed from the tanker at the entrance of the plant to the EDG day tanks to ensure it
will not be damaged by other plant traffic. This observation was provided to the
licensee and was placed in the Corrective Action Program.
During the walk-down of the flooding procedures listed in the scope of this report
section, the inspectors also noted that, even though the main pieces of equipment
and tools listed in the procedures were pre-staged, some of the smaller tools were
not. The inspectors noted that if the licensee had a more meticulous pre-staging of
equipment including small tools and consumables, the number of trips to the tool
room would be minimized and flood preparations would be more efficient. The
licensee entered this observation into the corrective action process.
During this inspection period, the inspectors assessed the flood preparations
associated with the emergency response facilities such as the Technical Support
Center (TSC), the Operations Support Center (OSC), and the Emergency Operations
Facility (EOF). The inspectors reviewed the licensees plan to provide for an alternate
emergency response facility in case the original locations were expected to flood.
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The licensee was able to demonstrate that an adequate plan existed for alternate
TSC, OSC, and EOF facilities in case of a flood. In addition, the inspectors noted that
there are no thresholds to transfer the TCS and OSC to alternate locations. The
inspectors also noted a general lack of rigor and details in the procedures to respond
to prepare and respond to a flood. Specifically, the inspectors noted the licensee did
not have detailed plan on managing the distribution of resources and personnel, and
the strategy during the preparation time for an imminent flood. As a result of the
inspectors observations, the licensee is currently constructing a resource-loaded
schedule that delineates the different tasks and times requested for all the
preparations needed prior to a flood. The inspectors will review the plan and continue
to have further discussions with licensee operations and emergnency preparedness
personnel. Further in-depth Emergency Preparedness (EP) inspections will be
performed by EP inspectors and will be documented in the future as part of Restart
Checklist Item 5.f.
The inspectors reviewed the basis for the number of hours that the licensee bases
their entire flooding planning on. The inspectors wanted to ensure that the technical
foundation for that window of preparation time was adequate and that the licensee
would still be able to stage equipment, stack sand bags, and assemble flood barriers
in enough time before the plant grounds start to flood.
(3) Findings
No findings of significance were identified.
.b Reactor Protection System contact Failure - White Finding
Item 1.b is included in the restart checklist for the failure of Fort Calhoun Station to
correct a degraded contactor, which subsequently failed, in the reactor protection system.
These deficiencies resulted in a White (low to moderate safety significance) finding.
(1) Inspection Scope
The NRC inspected and will continue to inspect the root cause, extent of cause, and
extent of condition related to the contactor failure and the associated process failures.
The on-site activities included interviews and discussions with staff performing
evaluations of significant performance issues, programs, and processes; and
observation of conduct of recovery effort meetings.
(2) Assessment
The team completed the review of revision 2 of the Root Cause Analysis for the
contactor failure, RCA 2011-0451, during previous inspection weeks. However, no
progress was made in this area during the six weeks of this reporting period because
the licensee started a new root cause analysis (revision 3) the week of
September 24, 2012. Revision 3 of this root cause analysis will supersede the
previous two versions because of errors, omissions, and poor clarity. The licensee
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continues to try to pull this date up for completion of the root cause itself to
November 9, 2012, and does not currently have a schedule for completion of all
corrective actions. The NRC will close out this issue for restart after the inspections
verify that the station has 1) completed revision 3 of this root cause analysis,
2) completed the corrective actions from the root cause analysis, and 3) completed all
actions necessary to prevent re-occurrence.
(3) Findings
No Findings of significance were identified.
.c Electrical Bus Modification and Maintenance - Red Finding
Item 1.c is included in the restart checklist because the licensee failed to adequately
design, modify, and maintain the electrical power distribution system, which caused a fire
in the safety-related 480 volt (V) electrical switchgear. These deficiencies resulted in a
finding having Red (i.e., high) safety significance.
(1) Inspection Scope
During the inspection period, the NRC assessed (and will continue to assess during
upcoming inspection periods) the licensees root cause, extent of cause, and extent of
condition evaluations related to the fire and associated equipment and process
failures.
The on-site activities included a walk-down of the remains of the breaker that was on
fire and a tour of the switchgear rooms, interviews and discussions with licensee staff,
and observation of recovery effort meetings. The in-office activities, which were
conducted at the inspectors normal duty stations, consisted of reviews of documents
associated with the recovery efforts, conditions reports, root cause analyses, scoping
procedures, calculations, and drawings.
The team also reviewed modification EC 33464, Replace AK-50 480 V Main and
Bus-Tie Breakers With Molded Case Type or Equivalent, Revision 0, which replaced
12 General Electric AK-50 low voltage power circuit breakers with Nuclear Logistics
Incorporated/Square-D Masterpact circuit breakers / cradle assemblies, and digital
trip devices in November 2009. The modification replaced six feeder circuit breakers
and six bus-tie breakers.
The team interviewed the system engineers responsible for the 480 VAC distribution
system and electrical maintenance technicians that maintained the system. The team
interviewed operations personnel and discussed procedures and training for the
modification. The team reviewed the modification to determine if the requirements of
10 CFR 50.59, Changes, Tests and Experiments, were met, including understanding
the possible failure modes, and to assess the post-modification testing completeness
for cradle and breaker positioning, electrical resistance, and other critical parameters.
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(2) Assessment
As previously discussed in NRC IR 050-00285/2012004, when evaluating whether a
risk significant finding may be closed, NRC IP 95002 directs inspectors to :
1) To provide assurance that the root and contributing causes of individual and
collective (multiple greater than green inputs) risk-significant performance
issues are understood.
2) To independently assess and provide assurance that the extent of condition
and the extent of cause of individual and collective (multiple greater than
green inputs) risk-significant performance issues are identified.
3) To independently determine if safety culture components caused or
significantly contributed to the individual and collective (multiple greater than
green inputs) risk-significant performance issues.
4) To provide assurance that a licensees corrective actions for risk-significant
performance issues are sufficient to address the root and contributing causes
and prevent recurrence.
In order to achieve these objectives the inspectors independently reviewed the
licensees evaluations of the event and determined that the following conditions
contributed to 1) the initiation of the fire event or 2) the unexpected system response
to the initiating event. In the inspectors assessment are SCAQs based upon the
OPPD QA manuals definition since each of these conditions would have precluded
plant response to the event from ending up outside plant design basis and resulting in
a high safety significance (RED) finding.
OPPD committed to meeting the criteria in IEEE 384-1981, IEEE Standard Criteria
for Independence of Class 1E Equipment and Circuits. This standard describes
independence requirements for Class 1E equipment, including those required for safe
shutdown. Section 5.10.1 of IEEE 384-1981 states that an electrically generated fire
in one Class 1E division shall not cause a loss of function in its redundant Class 1E
division. OPPD also committed to the design criteria in IEEE 308-1974, IEEE
Standard Criteria for Class 1E Power Systems for Nuclear Power Generating
Stations. Criterion 5.2.2(3), Independence, states that distribution circuits to
redundant equipment shall be physically and electrically independent of each other.
Criterion 4.6, Equipment Protection, states that Class 1E power equipment shall be
physically separated from its redundant counterpart or mechanically protected as
required to prevent the occurrence of common failure modes due to design basis
events. The IEEE standard defines design basis events to include postulated
phenomena such as fires. Fort Calhoun USAR also specifies that any subsequent
fault induced by a single failure shall be considered to be part of that single failure and
not treated as a separate failure.
1) The postulated cause of the fire was a high impedance connection between
the breaker cradle assembly and the 480 VAC bus stabs which caused
localized overheating and the bus bar failure, which initiated the event. This
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condition was the focus of CR 2011-5414. The licensees corrective actions
developed included replacing the damaged switchgear components,
correcting and/or verifying the alignment of the remaining breaker and cradle
assemblies, correcting the silver plating on all the breaker stabs, and revising
design procedures. The inspectors reviewed the corrective actions completed
and planned and concluded they were adequate to preclude repetition of this
SCAQ. However, NLI and Square D (the vendors for the breaker) completed
an independent RCA for the event on 8/22/12. As of the end of the inspection
period the NRC had not completed its review of this independent RCA.
2) During the fire, a phase-to-phase arc fault occurred for 42 seconds, which
generated a fault current value of 16,000 amperes (A), until operators
manually de-energized Transformer T1B-4A by opening Breaker 1A4-10. In
accordance with 480 VAC, 4160 VAC and Fire protection system design
criteria and IEEE Standards, a fault should be isolated by the breaker closest
to the fault. This would have isolated and arrested the fault and prevented it
from impacting other electrical buses. However, Breaker 1A4-10s breaker trip
setpoint was such that a phase-to-phase fault on the line side of Breaker 1B4A
would not be cleared. This allowed the fire to continue, produce combustion
products, and develop the subsequent ground fault between the BT-1B4A
breaker and the island bus. Although the licensee generated CR 2012-01630
on March 1, 2012, which acknowledged this condition, the licensee had yet to
complete an analyze the adequacy of the breaker trip set points as of the
conclusion of this inspection period. Therefore, the 4160 VAC bus is still not
protected against an arc fault event on the 480 VAC bus upstream of the 480
VAC feeder breaker and this vulnerability is still present.
3) The bus separation scheme design was inadequate to meet the systems
design criteria , IEEE standards, and the 1971 NRC Standard Review Plan
(SRP). (Note: however, the inspectors recognize that OPPD was licensed to
operate FCS prior to the SRP). OPPDs bus separation scheme design
allowed combustion products from the Bus 1B4A fire to be communicated to
and affect the island bus because of the physical configuration of the bus duct
work and because there is only one bus tie breaker on each end of the island
buses. This configuration and the fire event resulted in the development of an
electrical short to ground between Breaker BT-1B4A and Island Bus 1B3A-4A,
which was powered from the opposite safety bus (Bus 1B3A). Thus both
independent trains of vital AC power were adversely affected by a fault on a
single bus. FCSs corrective actions restored the original configuration of the
480V switchgear. The inspectors were not aware of any formal evaluation
which reviewed this design vulnerability and/or operability evaluation as of the
end of the inspection period. This design vulnerability is still present.
4) The DC bus separation scheme design for the DC buses was questioned by
the inspectors. During the fire event on June 7, 2011, grounds developed on
both DC buses. OPPD evaluated the inspectors concern and were able to
demonstrate that there was no adverse impact on the DC buses. While the
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condition did result in degradation of the DC busses,t he DC buses are an
ungrounded system by design; therefore, a single ground would not impact
system operation. This condition was determined not to be a SCAQ, because
it is consistent with plant and system design basis and did not contribute to the
unexpected plant response during the event. This concern was adequately
evaluated by OPPD and can be considered closed.
5) The breaker coordination scheme design did not respond as expected during
the fire event. Breaker 1B3A tripped when a fault developed on Island Bus
1B3A-4A, which resulted in both Bus 1B3A and Island Bus 1B3A-4A being lost
during the event. In accordance with system design requirements, Breaker
BT-1B3A should have isolated the fault. Because of the fire and breaker
coordination failure, six of nine vital 480 V buses were either manually or
automatically de-energized during the event, and minimum ECCS system
capacity was not maintained. This condition was the focus of CR 2011-6621.
Corrective actions developed were reviewed by the inspectors and determined
to be adequate to preclude repetition of this SCAQ. This SCAQ and the
associated finding 2012-004-04 can be closed
The inspectors determined the above conditions were SCAQ based upon the
following. Condition #1 is a SCAQ because it resulted in the initiation of an electrical
fault on a single 480 VAC bus and the resulting fire which caused significant
equipment damage and resulted in an EAL declaration. Condition #2 is a SCAQ
because it 1) allows a fault on a single 480 VAC bus to adversely impact the
associated 4160 VAC bus and the remaining 480 VAC on this train, 2) prevents the
fault from being deenergized thus allowing the fire to burn for an additional 42
seconds causing significant equipment damage, and 3) develops charged particles
and soot which allow the design vulnerability discussed in condition 3 to be exploited.
Condition #3 is a SCAQ because this design vulnerability is the mechanism which
allows a single fault to impact both trains of safety related equipment (ECCS,
480VAC, and SSE) and thus is not with the design basis and is an unanalyzed
condition. As a result, during the event, the fault impacted the 1B3A-1B4A island bus
which is powered from the opposite train from the fault. Condition #5 is a SCAQ
because it resulted in a loss of breaker coordination which is relied upon per the Fire
Protection Safe Shutdown Design to protect both trains of SSE during a postulated
fire event, thus this was beyond the system design basis and was an unanalyzed
condition. As a result during the event, a second bus on the opposite train from the
fault was lost and all high pressure make up water sources (HPSI and Charging) were
lost and could not be restored via remote manual operator action.
During this inspection period the inspectors focused on SCAQs 2, and 3. In 1991,
FCS completed a breaker coordination study of the 4160 VAC and 480 VAC
distribution systems. The inspectors identified that the breaker coordination survey
correctly identified that the breaker trip setpoints does not provide full protection
against a 4160VAC/480VAC transformer fault or a 480V Load Center Bus Fault. The
study evaluated that this was acceptable due to the possibility of a fault is extremely
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small and the fact that the USAR Section 8.3.1 does not state that all breakers are
coordinated.
The inspectors challenged this conclusion on the basis that the major concern is fault
protection and clearance. The June 7, 2011 fire demonstrated that not showing
protection against a 480 VAC load center fault would prevent the fault from being
cleared, allow a 480 VAC fault to adversely impact the associated 4160 VAC bus.
This lack of protection turned a fire on a single 480VAC bus into an unisolable fault on
the 4160 VAC bus, which is the worst case design basis single failure for ECCS since
the entire 4160 VAC bus and thus each of the associated 480VAC on the train are
also lost. In addition, since the fire is allowed to continue to burn, the known bus
separation design vulnerability is allowed to be exploited as soot and charged particle
are allowed to collect on the associated bus tie breaker (physically located in the
same switchgear cabinet) and develop a fault on the opposite train. This takes plant
response outside of the design basis. Thus, the inspectors questioned the validity of
the studys conclusion. This concern was still under review by the inspectors at the
end of the inspection period.
(3) Findings
.1 Untimely Corrective Actions for 480 VAC Breaker Issues
Introduction: The inspectors identified a Green noncited violation (NCV) of
10 CFR 50, Appendix B, Criterion XVI, Corrective Actions. Specifically, FCS failed
to take timely corrective actions to address non conforming conditions identified in
several breakers during their review of the June 7, 2011, 1B4A Bus fire and abnormal
system response event. Specifically, several breakers were observed to have
significant breaker cradle assembly to bus stab misalignment and high impedance
connections were identified. These conditions were determined to have been the
cause of the 1B4A bus bar failure that initiated the fire; however, this condition was
not corrected for several months. Additionally, FCS continued to operate with a
degraded 1B3A breaker for nine additional months after the breaker tripped
unexpectedly during the event. The breaker remained in service until February 2012.
Description: Following the June 7, 2011, 1B4A breaker fire and abnormal 480 VAC
system response event, FCS wrote several CRs and conducted Root Cause Analysis
(RCA) CR 2011-05414 related to the why the fire occurred. A separate CR
(2011-6621) was written to document and review the unexpected tripping of the 1B3A
breaker during the fire event. FCS initially failed to properly evaluate the significance
of the event as an event significant to nuclear safety, in accordance with FCS
corrective action program procedure . FCS only evaluated the event with respect to
the plant conditions at the time of the fire (i.e., the plant was shutdown for a refueling
outage). In September 2011, during the NRCs Special Inspection of the fire event,
FCS revised its risk assessment and determined that if the fire had occurred at power,
it would have been an event significant to nuclear safety because of the loss of all
high pressure injection sources (HPSI and charging pumps), that adversely impacted
both trains of safe shutdown equipment (SSE).
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In July 2011, boroscope inspections of the undamaged 480 VAC breakers were
conducted as an Extent of Condition (EOC) review. These inspections revealed that
four other breakers had significant breaker cradle finger to bus stab misalignment and
appeared to be contacting the stabs beyond the silver plating on the stabs and
created a high impedance connection. This was the same failure mechanism that
CR 2011-5414 concluded was the most likely cause of the 1B4A bus failure and fire.
However, once this condition adverse to quality was identified to exist, the condition
was not corrected until November 2011. During this work, one of the breakers,
Breaker 1B3C was found to have discolorations on the fingers of the cradle assembly,
and this was believed to be heat related. This indicated that at least one other
breaker was potentially progressing down the same failure mechanism as 1B4A.
As discussed in IR 05000285/2011014, the initiating event likelihood of a fire was
calculated to increase to 7.0 x 10-2/year from a baseline likelihood of 2.5 x 10-5 / year
due to this misalignment condition. This significant increase in the likelihood of
another fire occurring due to the same cause as the June 7th, 2011, fire, would make
the misalignment identified in July 2011 a Significant Condition Adverse to Quality
(SCAQ). SCAQs and CAQs must be identified and corrected commensurate with the
safety significance of the issue. Because this issue was determined to have Red (i.e.,
high) safety significantce by the NRC and to be significant to nuclear safety in
accordance with FCSs own risk re-assessment in September 2011, the NRC
determined that waiting to address the issue until November 2011 was not determined
to be a timely corrective action.
In addition, during the 1B4A breaker fire, the 1B3A breaker tripped unexpectedly to
clear a fault induced at the BT-1B4A Bus Tie breaker. This fault should have been
cleared by the BT-1B3A breaker, but the 1B3A breaker tripped first, contrary to the
FCS Breaker Coordination design Scheme. CR 2011-6621 was written to document
the abnormal 480 VAC system response, but it was classified originally as a C level
CR, and no formal evaluation was assigned. It was determined via CR 2011-5514
that 1B3A tripped before BT-1B3A because the breaker coordination curves were set
close to each other in a manner that allowed 1B3A to trip first (i.e., it won the relay
race). The 1B3A breaker was returned to service on June 22, 2011. In September
2011, this CR was brought back to the stations corrective action review board
(CARB) meeting and reassigned as a level A CR, and a root cause evaluation was
assigned. This was due to the fire event risk being re-evaluated. This root cause
rejected the relay race explanation and identified several potential failure
mechanisms that could have caused the breaker to trip outside the coordination
scheme. Troubleshooting was commenced by testing the breakers locally and by
testing the BT-1B3A and 1B3A breakers at the NLI facility in October 2011. These
tests did not identify any problems, and the breakers were returned to FCS and
returned to service.
In February 2012, both breakers BT-1B3A and 1B3A were removed and sent to NLIs
factory test facility. During this round of testing, the symptoms observed on
June 7, 2011, were repeated. With 1B3A and BT-1B3A in series with a fault source,
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the 1B3A breaker tripped instantaneously before the BT-1B3A breaker could trip.
Further inspection revealed that the WAGO jumpers disabling the Zone Selective
Interlock (ZSI) function were not installed in the correct location; therefore, the ZSI
feature was not disabled as originally intended. The jumpers were restored to their
proper positions, and proper breaker coordination was observed. Licensee
inspections were conducted on the remaining breakers at FCS in a timely manner,
and no further issues were identified.
However, the fact that the 1B3A breaker was in service in a known degraded
condition from June 22, 2011, until February 27, 2012, is another example of
corrective actions not being timely, and exposing the plant to unnecessary risk.
Analysis: The failure to take timely corrective actions for known SCAQs or CAQs was
within FCSs ability to foresee and prevent and is therefore a performance deficiency.
The performance deficiency was evaluated using NRC Inspection Manual Chapter 0612, Appendix B, Issue Screening, and the issue was determined to be more than
minor because it affected the Initiating Events Cornerstone attribute of protection
against external events (i.e., fire) because the condition that contributed to the fire
event was left uncorrected. The issue adversely affected the associated cornerstone
objective of limiting the likelihood of those events that upset plant stability and
challenge critical safety functions during shutdown as well as power operations. This
issue also affected the Mitigating System Cornerstone.
The inspectors evaluated the finding using NRC Inspection Manual Chapter 0609,
Attachment 4, Initial Characterization of Findings. IMC 0609, Attachment 4 directs
the user to use of IMC 0609, Appendix G, Shutdown Operations SDP, since FCS
was in cold shutdown during the entire exposure period. Using IMC 0609 Appendix
G, Attachment 1, Phase 1 Operational Checklists for Both PWRs and BWRs,
Checklist 4, PWR Refueling Operation: RCS level > 23' or PWR Shutdown Operation
with Time to Boil > 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> And Inventory in the Pressurizer, the issue screens to
having Green (i.e., very low) safety significance because RCS makeup capability was
not degraded since one or more low pressure makeup water sources would remain
available. The inspectors determined that the issue had a cross-cutting aspect in the
area of Human Performance, Decision Making, 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 (H.1.b).
Enforcement: 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, states 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. In the case of significant
conditions adverse to quality, the measures shall assure that the cause of the
condition is determined and corrective action taken to preclude repetition.
Contrary to the above, from July 2011 until November 2011, a SCAQ related to the
misalignment of the 480 VAC breakers, which was identified as the cause of the 1B3A
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fire, was identified to exist in other equipment, but corrective actions to preclude
repetition were not taken in a timely manner. Additionally from June 22, 2011, until
February 27, 2012, a known degraded breaker was allowed to remain in service for
approximately 8 additional months until the cause was identified. This was also not
timely. FCS corrected the nonconforming conditions in the breakers and has revised
its corrective action program. However, because this violation was of very low safety
significance, and FCS has entered this issue into their its corrective action program as
CRs 2012-01884 and 2011-5414, the NRC is treating this as an NCV in accordance
with Section 2.3.2 of the NRC Enforcement Policy;05000285/2012005-02, Untimely
Corrective Actions for 480 VAC Breaker Issues.
.e Third-Party Safety Culture Assessment
Item 1.e is included in the restart checklist because the NRC recognizes the importance
of nuclear plant licensees establishing and maintaining a strong safety culture, a work
environment where management and employees are dedicated to putting safety first. In
addition, nuclear power plants should have a work environment where employees are
encouraged to raise safety concerns, and where concerns are promptly reviewed, given
the proper priority based on their potential safety significance, and appropriately resolved
with timely feedback to the originator of the concerns and to other employees.
(1) Inspection Scope
The NRC attended safety conscious work environment (SCWE) training that FCS
provided to its supervisors on September 13, 2012. The site vice president
introduced the training class with a discussion of why the training was being
conducted. The training material included the topics of employee protection,
regulations, the definition of SCWE and its relationship to safety culture, the attributes
of SCWE, discrimination, and the safety culture survey results performed at FCS in
May 2012. The instructor emphasized the importance of encouraging people to enter
issues into the FCS corrective action program (CAP).
(2) Assessment
Inspectors thought that the training content was adequate and that the opportunity at
the end of the training for supervisors to discuss the safety culture survey results was
beneficial. During the training, the instructor discussed the differences between the
concepts of perception of retaliation versus proof of retaliation. A question of
perception versus proof of retaliation also came up during the meeting on
July 19, 2012, in which fundamental performance deficiencies were discussed. NRC
inspectors commented to FCS staff during a weekly debrief that insights from the
sites employee concerns program manager, union, and human resources department
could have been incorporated into the training to help clarify what types of behavior
FCS employees are perceiving as retaliation.
- 23 -
(3) Findings
No findings or violations of NRC requirements were identified; however, the NRC will
continue its assessment of this CAL item. This restart checklist item remains open.
.2 Flood Restoration and Adequacy of Structures, Systems, and Components
Section 2 of the Restart Checklist contains those items necessary to ensure that important
structures, systems and components affected by the flood are in adequate condition to
support safe restart and continued safe plant operation. Section 2 reviews will also include
an assessment of how the licensee addresses the NRC Inspection Procedure 95003 key
attributes as described in Section 6.
.a Flood Recovery Plan Actions Associated With Facility and System Restoration
Item 2.a is the NRCs independent evaluation of Fort Calhoun Stations Flood Recovery
Plan. An overall flood recovery plan is important to ensure the station takes a
comprehensive approach to restoring the facility structures, systems, and components to
pre-flood conditions.
On August 30, 2011, Fort Calhoun Station issued Revision 1 to the Fort Calhoun Station
Post-Flooding Recovery Action Plan, (FRAP) that provided for extensive reviews of plant
systems, structures, and components to assess the impact of the floodwaters. On
September 2, 2011, the NRC issued Confirmatory Action Letter (CAL) 4-11-003, listing
235 items described in the Fort Calhoun Station Post-Flooding Recovery Action Plan that
the licensee committed to complete. These 235 items were broken down into three
sections: items to complete prior to exceeding 210 degrees Fahrenheit in the reactor
coolant system, items to complete prior to reactor criticality; and items to complete
following restart of the plant. On June 11, 2012, the NRC issued CAL 4-12-002. This
CAL incorporates all the actions required by CAL 4-11-003.
The areas to be inspected are identified in the CAL. Inspection items are considered
complete when the licensee has submitted a closure package that has been satisfactorily
reviewed by the inspectors
(1) CAL Action Item 1.2.1.4
i.
Inspection Scope
The purpose of Action Item 1.2.1.4 was to return B.5.b materials to their proper
location. This item was required to be completed prior to exceeding 210 degrees
Fahrenheit in the Reactor Coolant System.
During the 2011 flood some B.5.b materials were displaced from their normal
location in the FCS warehouse to other locations on site.
- 24 -
After flood waters receded, the B.5.b materials were relocated from their
temporary location in the training center truck bay to their permanent location.
The licensee inventoried the equipment per Attachment 11 of OCAG-1,
Operational Contingency Action Guideline.
The inspectors performed an independent inventory of all B.5.b materials listed in
attachments 8, 9, 10, and 11 to ensure all equipment was accounted for.
This activity constitutes completion of Action Item 1.2.1.4 as described in
Confirmatory Action Letter 4-12-002.
ii. Findings
No findings were identified.
(2) CAL Action Item 2.1.1.3
i.
Inspection Scope
The purpose of Action Item 2.1.1.3 was to flush fire protection piping connected to
the fire protection header ring which flowed river water during flood mitigation
actions. This item was required to be completed prior to exceeding 210 degrees
Fahrenheit in the Reactor Coolant System.
In preparation for the Missouri River flooding in 2011, the licensee installed a
water filled protection device around the plant. This required large quantities of
water to be provided for extended periods of time. The licensee utilized the
electric driven fire pump, PF-1A to fill the individual sections of the protection
device with some of the exterior fire hose cabinets. This activity deposited river
water into the underground fire main piping around the plant.
The licensee performed OP-ST-FP-0011, Fire Protection System Hose Station
Operability Test to flush the underground fire main and to operate all exterior fire
hydrants. Each fire hydrant was flushed for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> with clean,
fresh water.
The inspectors reviewed the USAR, procedure requirements, and technical
specifications to ensure that the surveillance activities demonstrated that the
systems, structures, and/or components tested were capable of performing their
intended safety functions. During performance of the surveillance test, Fire
Hydrant FP-3C was identified as degraded during flushing activities.
The licensee created a new action item in the flood recovery action plan, 2.1.3.8,
which was to replace FP-3C. The licensee replaced the fire hydrant, as well as its
associated isolation valve, FP-114.
The inspectors observed the installation of the fire hydrant and isolation valve, as
well as the postmaintenance testing to ensure the effect of testing on the plant
- 25 -
had been adequately addressed; testing was adequate for the maintenance
performed, and acceptance criteria were clear and demonstrated operational
readiness; and test instrumentation was appropriate.
This activity constitutes completion of Action Item 2.1.1.3 as described in
Confirmatory Action Letter 4-12-002, as well as flood recovery plan action item
2.1.3.8.
Findings
ii. No findings were identified.
(3) CAL Action Item 2.1.1.9
i.
Inspection Scope
The purpose of Action Item 2.1.1.9 was to complete full flow testing of fire pumps.
This item was required to be completed prior to exceeding 210 degrees
Fahrenheit in the Reactor Coolant System.
Due to the flooding conditions and the location of the water filled protection
device, access to the fire protection test header valves and general area required
for testing equipment was restricted. To complete full flow testing of the fire
pumps, a test rig was installed on a truck with fire hoses attached to the test
header. This test configuration required the areas west of the intake structure to
be clear. Due to the conditions from the flooding event the tests had to be
delayed until the flood waters had receded and the water filled protection device
was removed.
Surveillance Tests SE-ST-FP-0002 'Fire Protection System Motor Driven Fire
Pump Full Flow Test' and ST SE-STFP-0003 'Fire Protection System Diesel
Driven Fire Pump Full Flow Test' were completed as soon as the testing area and
equipment was accessible. Both the electric motor driven fire pump FP-1A and
the diesel driven fire pump FP-1 B passed their respective surveillance tests and
were returned to service and declared operable.
The inspectors reviewed the USAR, procedure requirements, and technical
specifications to ensure that the surveillance activities demonstrated that the
systems, structures, and/or components tested were capable of performing their
intended safety functions.
The inspectors witnessed and 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
- 26 -
Acceptance criteria
Test equipment
Procedures
Jumper/lifted lead controls
Test data
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
This activity constitutes completion of Action Item 1.2.1.4 as described in
Confirmatory Action Letter 4-12-002.
ii.
Findings
No findings were identified.
(4) CAL Action Item 2.2.1.32
i.
Inspection Scope
The purpose of Action Item 2.2.1.32 was to assess the effects of the flood on the
Communications System and identify actions to restore the system. This item
was required to be completed prior to exceeding 210 degrees Fahrenheit in the
The inspectors independently reviewed the system to identify if there were any
temporary modifications in place, any outstanding preventive or corrective
maintenance required, and reviewed all open condition reports, as well as all
- 27 -
condition reports created since January 1, 2011. The inspectors also conducted a
complete system walkdown to identify any adverse conditions and to verify all
system components were functioning properly. The inspectors compared the
results of their independent assessment to those contained in the licensees
Flooding Recovery Startup System Health Assessment report.
The Plant Communications System uses a combination of dial telephones,
dedicated telephone lines, intra-plant intercom/paging facilities, Paging System
and a 800 MHz Radio Communication System for on-site information relaying and
alarm notification. It also provides off-site communications with other facilities and
support personnel. The Plant Communications System does not perform any
safety related functions.
The inspectors identified no adverse conditions associated with the Plant
Communications System.
This activity constitutes completion of Action Item 2.2.1.32 as described in
Confirmatory Action Letter 4-12-002.
ii. Findings
No findings were identified.
(5) CAL Action Item 2.3.1.1
i.
Inspection Scope
The purpose of Action Item 2.3.1.1 was to assess whether motors were to be
tested for possible use, refurbished or replaced. This item was required to be
completed prior to exceeding 210 degrees Fahrenheit in the Reactor Coolant
System.
The licensee determined that five normally dry pump motors were wetted for some
period of time: the three circulating water pump motors, CW-1A, CW-1B, and
CW-1C; and the Demineralized Water Storage Tank inlet and outlet pump motors,
DW-69 and DW-70.
The inspectors performed an independent assessment of which motors may have
been wetted. The assessment included individual inspector walkdowns during
and after the flood, and conversations with inspectors who had been present
during the site flooding in 2011. The inspectors also searched all opened
condition reports since the onset of flooding and concurred with the licensee that
the circulating water and demineralized water pumps were the only normally dry
pump motors that had been wetted by floodwaters.
The licensee also created action items 2.3.1.2 through 2.3.1.8 to track completion
of items associated with the circulating water pump motors, and action items
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2.3.1.9 through 2.3.1.16 to track completion of items associated with the
demineralized water pump motors.
In addition to these five pumps, the switchgear room ventilation condensing units,
VA-89 and VA-90 were flooded when the water filled protection device around the
plant collapsed. These condensing units were repaired prior to the issuance of
the flood recovery plan.
This activity constitutes completion of Action Item 2.3.1.1 as described in
Confirmatory Action Letter 4-12-002.
ii. Findings
No findings were identified.
(6) CAL Action Items 2.3.1.2 and 2.3.1.1
i.
Inspection Scope
The purpose of Action Items 2.3.1.2 and 2.3.1.3 were to take oil sample from
bearing housings and evaluate if water had gotten in contact with the bearings in
the circulating water pump motors, CW-1A, CW-1B, and CQ-1C. These items
were required to be completed prior to exceeding 210 degrees Fahrenheit in the
The licensee took cold oil samples from each of the circulating water pump
motors upper and lower bearing reservoirs on September 6 and 7, 2011. The
samples were then sent to a third party laboratory for analysis.
The inspectors observed the sampling of the oil and reviewed the analyses
results. Each of the 6 samples were first tested for water contamination via the
Crackel Test. The Crackle Test is a standard laboratory test to detect the
presence of water in lubricating oil. A drop of oil is placed on a hotplate that has
been heated to approximately 400 degrees Fahrenheit. The sample then bubbles,
spits, crackles or pops when moisture is present. The Crackel test showed
undetectable for water content for all samples except for the inboard bearing
reservoir for CW-1C motor.
The samples were then tested utilizing the Karl Fisher Titration method. This
method uses anode and titrant solutions to determine concentrations of water in
the oil. The Karl Fisher Titration results showed the inboard bearing reservoir for
CW-1C motor to contain approximately 110 parts per million (ppm) water, where
the other five bearing reservoirs contained between 20.0 and 21.5 ppm water.
This is indicative of flood water ingress into the inboard bearing reservoir for CW-
1C motor.
The refurbishment of CW-1C pump motor will be completed and evaluated under
Confirmatory Action Letter item 2.3.1.4,
- 29 -
This activity constitutes completion of Action Items 2.3.1.2 and 2.3.1.3 as
described in Confirmatory Action Letter 4-12-002.
ii. Findings
No findings were identified.
(7) CAL Action Items 2.3.1.5 and 2.3.1.6
i.
Inspection Scope
The purpose of Action Items 2.3.1.5 and 2.3.1.6 were to perform visual and
boroscope inspections of the circulating water pump motors and evaluate the
results. These items were required to be completed prior to exceeding 210
degrees Fahrenheit in the Reactor Coolant System.
The licensee performed a visual inspection of the circulating water pump motor
internals and termination boxes on September 8, 2011.
The inspectors performed an independent visual inspection of the pump motors,
and observed the licensee using the boroscope. The inspectors evaluated the
boroscope photographs and compared them to their visual inspection.
The inspection showed no signs of debris, silt, moisture or corrosion. The motors
did contain a fine film of dust throughout the stator winding as a normal result of
operation. The inspection showed similar results for all three motors. A cleaner
area was observed near the termination box opening into the motor of the CW-1C
motor. This was indicative of where water entered the motor.
No abnormal degradation was noted in any of the three pump motors. The
refurbishment of CW-1C pump motor will be completed as a result of water
intrusion into the motor oil as described in action items 2.3.1.2 and 2.3.1.3 and
evaluated under Confirmatory Action Letter item 2.3.1.4,
This activity constitutes completion of Action Items 2.3.1.5 and 2.3.1.6 as
described in Confirmatory Action Letter 4-12-002.
ii. Findings
No findings were identified.
(8) CAL Action Item 3.2.1.2
i.
Inspection Scope
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The purpose of Action Item 3.2.1.2 was to test maintenance rule low voltage
power cable on cables which had been subjected to wetting/submergence. This
item was required to be completed prior to exceeding 210 degrees Fahrenheit in
The licensee performed megger testing on low voltage (480 volt) cable in
November 2011. The population of cables was those which were exposed to
water, traversing through manholes 5 and 31: the feeder cables for motor control
centers MCC-3B3 and MCC-4C4.
The inspectors observed the licensees megger testing and analyzed the result. A
megger test is performed to ensure the adequacy of the insulation in a cable. In
480 volt cables, 500 volts are applied to the cable for one minute, and the
resistance is measured. The acceptance criteria for 480 volt cables is 1.48
megohms. The inspectors verified that the resistance on the cables for MCC-3B3
were greater than 50,000 megohms, and for MCC-4C4 were greater than 2,000
megohms.
This activity constitutes completion of Action Item 3.2.1.2 as described in
Confirmatory Action Letter 4-12-002.
ii.
Findings
No findings were identified.
(9) CAL Action Item 3.2.1.3
i.
Inspection Scope
The purpose of Action Item 3.2.1.3 was to test maintenance rule low voltage
control and instrumentation on cables which had been subjected to
wetting/submergence. This item was required to be completed prior to exceeding
210 degrees Fahrenheit in the Reactor Coolant System.
The licensee performed megger testing on low voltage instrumentation and
control cables in October, 2011. The population of cables was those which were
exposed to water, traversing through manholes 5 and 31: motor driven fire pump,
FP-1A, control cable; the four raw water pump discharge valve control cables,
HCV-2850, HCV-2851, HCV-2852, and HCV-2853; and the six raw water
discharge header isolation valve control cables, HCV-2874A & B, HCV-2875A & B,
and HCV-2876A & B.
The inspectors observed the licensees megger testing and analyzed the result. A
megger test is performed to ensure the adequacy of the insulation in a cable. In
low voltage control and instrumentation cables, 250 volts are applied to the cable
for one minute, and the resistance is measured. The acceptance criteria for these
cables is 1.13 megohms. The inspectors verified that the resistance on all of the
cables was greater than 2,000 megohms.
- 31 -
This activity constitutes completion of Action Item 3.2.1.3 as described in
Confirmatory Action Letter 4-12-002.
ii.
Findings
No findings were identified.
.3 Adequacy of Significant Programs and Processes
Section 3 of the Restart Checklist addresses major programs and processes in place at Fort
Calhoun Station. Section 3 reviews will also include an assessment of how the licensee
addressed the NRC Inspection Procedure 95003 key attributes as described in Section 6.
.a Corrective Action Program
(1) Inspection Scope
The Corrective Action Program and the use of industry Operating Experience at a
nuclear power plant is a key element in ensuring the licensees ability to effectively
detect, correct, and prevent problems. A properly functioning Corrective Action
Program is also a basis for licensee operation within the Reactor Oversight Process.
Based upon observed problems with Corrective Action Program effectiveness the
licensee is performing a comprehensive review of this program.
The NRC will assess the licensees review and potential changes to the Corrective
Action Program. The NRC will also conduct independent inspections to validate
whether the Corrective Action Program is appropriately functioning.
For the assessment period covered by this inspection report, the onsite activities
included the observation of CAP meetings such as the Department Station Corrective
Action Review Board (DCARB), which was observed for the Operations Department,
and a presentation of the licensees corrective actions taken to date. The presentation
also included an explanation of the root causes identified as a result of the licensees
review of the CAP and what the next steps are for their improvement plan. In
addition, the inspectors interviewed site personnel associated with the Performance
Improvement department to continue to get a better understanding of the site CAP
processes. The in-office activities, which were conducted at the inspectors regular
duty stations, consisted of reviews of root cause analyses and procedures associated
with the Corrective Action Program.
(2) Assessment
During this assessment period, the inspectors attended one DCARB meeting for the
Operations Department. To be able to reasonably assess these processes, the
inspectors will continue to attend more of these meetings and observe more of the
CAP processes during future on-site inspection weeks. In general, the inspectors
noted a general attitude to follow the CAP procedures and healthy willingness to
- 32 -
express dissenting views during CAP meetings. However, during the course of
interviews, plant tours and interactions with plant personnel, the inspectors have also
noted a general behavioral issue with the threshold to initiating Condition Reports
(CRs). The inspectors have noted that, especially with lower level issues, the workers
opt for an attempt to repair the condition in-place and not writing a condition report to
document the deficiency, and place it in the CAP. The inspectors noted that this
approach could prevent issues from being placed in the CAP at an early stage.
(3) Findings
No findings of significance were identified.
.b Equipment Design Qualifications
This item of the Restart Checklist verifies that plant components are maintained within
their licensing and design basis. Additionally, this item provides monitoring of the
capability of the selected components and operator actions to perform their functions. As
plants age, modifications may alter or disable important design features making the
design bases difficult to determine or obsolete. The plant risk assessment model
assumes the capability of safety systems and components to perform their intended
safety function successfully.
.i
Safety-Related Parts Program
A number of instances have been identified where non-safety-related parts have been
installed into safety-related applications. Fort Calhoun Station is performing reviews
to identify conditions where a non-safety-related component or subcomponent was
improperly used in a safety-related application. The restart checklist includes an NRC
assessment of the licensees equipment design qualifications review for inconsistent
quality classifications and the licensees review of the use of non-safety-related parts
in safety-related applications.
(1) Inspection Scope
NRC inspectors reviewed the licensees procedure, scope of work, and training
material for assessing their safety-related parts program. Inspectors also
interviewed station personnel and contractors that performed the reviews.
Inspectors reviewed a sample of the condition reports generated from the review
and draft revisions of the individual system and collective evaluations, many of
which have not been finalized as of the end of the inspection period covered by
this report.
(2) Assessment
During the inspection period, OPPD completed the discovery phase of its
evaluations of this issue. The discovery phase was designed to identify all work
orders (WOs) where non safety related parts were issued for jobs involving safety-
- 33 -
related SSCs. This process identified 2100 WOs to be evaluated to determine if
non safety related parts were installed in safety-related systems and, if so,
whether these parts impacted the systems functionality and operability. At the
end of the inspection period, the licensee had reviewed approximately 40 percent
of the 2100 WOs, and approximately 15 of those WOs required an evaluation of
the impact on system functionality and operability. The NRC inspectors will
continue to review all instances of WO issues that resulted in system functionality
evaluations, and the team will assess a sampling of the WOs for which further
evaluations were performed to determine the effectiveness of the licensees
review. This restart checklist item will remain open until all WOs have been
screened and questions related to operability of SSCs required for Modes 1 and 2
have been appropriately evaluated and addressed.
During the inspection period, FCS changed its scope expansion criteria for this
project. Originally, FCSs scope expansion was based on criteria related to the
number of WOs discovered in the discovery phase and adding more WOs to the
population to be evaluated. FCS changed this scope expansion criteria to one
based upon components evaluated to have been installed in a safety related
application and requiring further review. When an item is found to meet this
criteria, the scope is expanded to search for additional WOs where this part was
issued beyond the original 5-year scope and in other systems. The change was
made to allow the scope expansion to be more risk based. The inspectors will
assess if the revised scope expansion criteria is as effective as identifying
vulnerabilities which occurred beyond the original 5-year scope.
In addition, FCS is in the process of replacing its CQE/non-CQE terminology
with safety-related/non-safety related terminology. FCS staff expects the
updates to station programs and procedures to be completed in 2012. The CQE-
to-safety related terminology conversion is expected to be completed in October
2013, and the non-CQE-to-non-safety related terminology conversion is
supposed to be completed by January 2014.
(3) Findings
No findings or violations of NRC requirements were identified; however, the NRC
will continue its assessment of this CAL item.
.ii High Energy Line Break (HELB) Program and Equipment Qualifications
Industry experience with extended power up-rates (a method some plants use to
produce more power from the same reactor) highlighted potential problems
associated with HELB effects. In preparations for a postponed extended power up-
rate, Fort Calhoun Station reviewed HELB calculations. FCS personnel found that it
was lacking adequate documentation and calculations for HELB effects in some
areas. The restart checklist includes an NRC assessment of FCSs HELB analyses
and documents to ensure the plant is within its licensing and design basis for HELB
- 34 -
effects. The NRC will also assess the licensees qualifications and documentation for
certifying equipment for harsh environments.
(1) Inspection Scope
NRC inspectors reviewed the licensees procedure, scope of work, and training
material for assessing the HELB and Equipment Qualification programs.
Inspectors also interviewed station personnel and contractors that performed the
reviews. Inspectors reviewed a sample of the condition reports generated from
the review and a draft revision of the collective evaluation, which has not been
completed as of the end of the inspection period covered by this report.
(2) Assessment
During this inspection period, OPPD continued to evaluate concerns related to
containment electrical penetrations discussed in LER 2852012002, and an overall
review of the Environmental Qualification program and HELB program including a
reassessment of the HARSH environment files and program scope and basis.
These reviews were still in progress at the end of the inspection period.
Therefore, the NRCs review of this restart checklist item is still in progress.
Closure of this restart checklist item will be dependent on, in part, the evaluation
and resolution of the issues discussed in the aforementioned LERs, including any
operability concerns.
(3) Findings
No findings or violations of NRC requirements were identified; however, the NRC
will continue its assessment of this CAL item.
.c Design Changes and Modifications
Modifications to risk-significant structures, systems, and components can adversely affect
their availability, reliability, or functional capability. Modifications to one system may also
affect the design bases and functioning of interfacing systems. Similar modifications to
several systems could introduce potential for common cause failures that affect plant risk.
A temporary modification may result in a departure from the design basis and system
success criteria. Modifications performed during increased risk configurations could
place the plant in an unsafe condition.
This item assesses the effectiveness of the licensees implementation of changes to
facility structures, systems, and components, risk significant normal and emergency
operating procedures, test programs, evaluations required by 10 CFR 50.59, and the
updated final safety analysis report. The NRC will inspect to provide assurance that
changes have been appropriately implemented.
.i
Vendor Modification Control
- 35 -
Past NRC inspections indicated that the licensee failed to ensure critical
characteristics were identified and properly addressed in several modification
packages. FCS is currently reviewing work performed by vendors. The restart
checklist includes an NRC assessment of the effectiveness of the licensees vendor
program, including its oversight of vendor work.
(1) Inspection Scope
NRC inspectors interviewed station personnel and contractors that performed the
reviews. Inspectors also reviewed the collective evaluation condition report.
(2) Assessment
The licensee completed its latest version of the collective evaluation condition
report, which summarized the results of its review of modification packages
prepared by vendors. The condition report mentions that significant issues were
identified; however, the licensee stated that it does not plan to perform a root
cause analysis on this topic. The inspector discussed some discrepancies in the
report in the characterization of identified issues. For example, the overall
conclusion in the report was that the identified issues were administrative;
however, another section of the report mentions significant issues were identified.
The licensee stated that it was aware of the discrepancies and is revising the
report. Inspectors also expressed a concern that the condition report stated what
the causal analysis should conclude instead of allowing the causal analysis
process to come to its own conclusions. The inspectors expressed the concern
that the effort was potentially being biased by the results of the organizational
effectiveness root cause analysis. The licensee stated that a final report for this
issue was still in progress.
(3) Findings
No findings or violations of NRC requirements were identified; however, the NRC
will continue its assessment of this CAL item.
.ii 10 CFR 50.59 Screening and Safety Evaluations
Past NRC inspections indicated that several changes to the facility were not properly
screened or evaluated in accordance with the requirements of 10 CFR 50.59. FCS is
evaluating past 10 CFR 50.59 documents. The restart checklist includes an NRC
assessment of plant and procedure modifications to determine if those modifications
were appropriately evaluated in accordance with 10 CFR 50.59. The NRC will also
evaluate the effectiveness of the licensees 10 CFR 50.59 process to ensure proper
treatment of changes to the facility.
(1) Inspection Scope
- 36 -
NRC inspectors interviewed station personnel and contractors that performed the
reviews. Inspectors reviewed a sample of the condition reports generated from
the review.
(2) Assessment
The licensee stated that they completed their review of 50.59 documents and the
collective evaluation condition report and are in the stage of developing a final
report before commencing a root cause analysis for the identified issues. The
collective evaluation condition report summarizes the results of the licensees
review of 50.59 documents. The report attachment contained the same statement
as the vendor modification report about what the cause analysis should state,
which further supported the inspectors concern that the organization
effectiveness root cause analysis results could bias other root cause analyses.
The licensee stated that they would remove these statements from the condition
reports.
The condition reports documenting the results of each 50.59 document review
contained due dates for when the identified issues would be corrected, if FCS staff
decided the issues had to be corrected. The inspectors noticed that some of the
corrective actions (e.g., updating the 50.59 documents with applicable design
basis information to support the conclusions) were deferred until after restart.
Inspectors also noticed a condition report that identified that design basis
information was not adequately incorporated or referenced in a 50.59 for an
engineering change (EC); however, FCS staff responded to the condition report
that there was no benefit to correcting the EC package because the summary of
the modification was already sent to the NRC, and the result of the 50.59 would
have been the same. The licensee stated that the contractors performing the
reviews were relying on experience and judgment to gauge whether NRC
approval would have been needed for determining the due dates for correcting
issues.
NRC inspectors attended a portion of 50.59 training that was provided by a
contractor to FCS staff. The training was thorough and of high quality.
The NRC will continue its review of the 50.59 documentation and associated
condition reports evaluated by the licensee. The NRC will also review the final
report, root cause analysis, corrective actions, and the effectiveness of those
corrective actions when completed by the licensee. This restart checklist item
remains open.
(3) Findings
No findings or violations of NRC requirements were identified; however, the NRC
will continue its assessment of this CAL item.
.d Maintenance Programs
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Inadequate maintenance activities that are not detected prior to returning the equipment
to service can result in a significant increase in unidentified risk for the subject system.
The Maintenance Rule (10 CFR 50.65) requires licensees to monitor the performance or
condition of structures, systems and components within the scope of the rule against
licensee-established goals to provide reasonable assurance that these structures,
systems, and components are capable of fulfilling their intended functions. These goals
are to be commensurate with safety and, where practical, should take into account
industry-wide operating experience.
The NRC will assess the licensees maintenance programs, including preventative
maintenance, compliance with vendor recommendations, post-maintenance testing
programs, and establishing and controlling equipment service life.
(1) Inspection Scope
.i
Vendor Manuals and Vendor Informational Control Programs
NRC inspections determined vendor manuals and information have not been
adequately maintained, which has resulted in adverse conditions at Fort Calhoun
Station. The licensee will perform a review to identify and incorporate updates to
vendor manual technical documentation. This review applies to all equipment and
components classified as a Critical Quality Element (safety-related). Changes in
vendor guidance will be evaluated to determine what impact, if any, the new
information has on scheduled work, work completed since the last vendor manual
update was made, and changes to plant documentation. The NRC will evaluate
the effectiveness of the licensees incorporation of vendor information into
applicable plant procedures and design documents to ensure proper maintenance
and operation of facility equipment.
.ii Equipment Service Life
NRC inspections determined that the licensee opted to keep some plant
equipment in service beyond the vendor recommended service life or standard
industry guidelines. Operating equipment past the recommended replacement
timeline has resulted in age-related failures at Fort Calhoun Station. In response,
the licensee will perform an assessment to evaluate the service life of
safety-related plant equipment and the effectiveness of programs used to
implement service life requirements. The NRC will inspect and assess the
adequacy of this evaluation and the associated corrective actions.
(2) Assessment
The team noted that a new apparent cause analysis is being performed for the vendor
manual area and the targeted completion date for this new analysis is October 30,
2012. The licensee does not currently have a schedule for completion of all
corrective actions. The NRC will close out this issue for restart after the inspections
- 38 -
verify that the station has 1) completed the new apparent cause analysis, 2)
completed the corrective actions from the apparent cause analysis, and 3) completed
all actions necessary to prevent re-occurrence. Additionally, because the vendor
manuals contain the service life requirements for most equipment and their
subcomponents, the inspectors will need to complete the service life corrective
actions as well to ensure proper reconciliation of these programs was accomplished.
The licensee wrote Condition Report CR 2012-09215 to address the reconciliation
issue.
The team noted that the root cause analysis being performed for the equipment
service life issue is scheduled to be completed on November 28, 2012. The licensee
does not currently have a schedule for completion of all corrective actions. The NRC
will close out this issue for restart after the inspections verify that the station has
1) completed the root cause analysis, 2) completed the corrective actions from the
root cause analysis, and 3) completed all actions necessary to prevent re-occurrence.
As mentioned above, proper reconciliation will need to be verified for this issue as
well (Condition Report CR 2012-09215).
(3) Findings
No Findings of significance were identified.
.e Operability Process
Improper evaluations of degraded and/or non-conforming conditions may result in
continued operation with a structure, system, or component that is not capable of
performing its design function.
(1) Inspection Scope
.i
Operability Determination Process
NRC inspections determined that Fort Calhoun Station did not consistently
conduct adequate Operability Evaluations to ensure that the impacts of degraded
conditions on plant operations are fully understood. In response, the licensee will
assess their operability evaluation program and develop corrective actions to
improve performance. The NRC will assess the licensees operability
determination process reviews. The NRC will inspect a sample of operability
determinations to ensure proper implementation of the licensees process and
ensure evaluations were correct.
.ii Degraded and Non-conforming Conditions
NRC inspection determined that some equipment identified as operable but
degraded remained degraded until subsequent failure occurred. Fort Calhoun
Station processes did not adequately identify degraded equipment or restore
equipment from a degraded condition to full qualifications in a timely manner. In
- 39 -
response, Fort Calhoun Station will assess their controls for the review of
operable but degraded equipment. The NRC will evaluate the effectiveness of
the changes made to the licensees tracking and treatment of operable but
degraded equipment.
(2) Assessment
The team noted that the root cause analysis being performed for the two issues of
operability and degraded and non-conforming conditions is scheduled to be
completed on November 16, 2012. The licensee does not currently have a schedule
for completion of all corrective actions. The NRC will close out these two issues for
restart after the inspections verify that the station has 1) completed the root cause
analysis, 2) completed the corrective actions from the root cause analysis, and 3)
completed all actions necessary to prevent re-occurrence.
The team reviewed several condition reports related to issues with containment spray
pumps, component cooling water pumps, and the emergency diesel generators. The
team also performed interviews and attended discussions with the licensee regarding
the operating experience program. A detailed write up on these systems,
components, and programs will be completed during the next six-week inspection
period.
(3) Findings
No Findings of significance were identified.
4OA5 Other Inspection Activities (TI 2515/188)
.1 (Opened and Closed) Temporary Instruction 2515/188 - Inspection of Near-Term Task Force
Recommendation 2.3 Seismic Walkdowns
NRC inspectors performed inspection activities to independently verify that Fort Calhoun Station
conducted seismic walkdown activities using an NRC-endorsed seismic walkdown methodology.
The seismic walkdowns are being performed at all sites in response to Enclosure 3 of a letter
from the NRC to licensees entitled, Request for Information Pursuant to Title 10 of the Code of
Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term
Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 12, 2012
(ADAMS Accession No. ML12053A340).
(1) Inspection Scope
The inspectors accompanied the licensee on their seismic walkdowns of :
The Motor Driven Auxiliary Feedwater Pump and associate equipment in Room
19 on August 8, 2012.
The B EDG and associated equipment on August14, 2012.
- 40 -
Walk down of the 1A2/1A4 switchgear area and inspection of the 1A4-9 breaker
cubicle.
The inspectors verified that the licensee confirmed that the following seismic features
associated with the above equipment and systems were free of potential adverse seismic
conditions by verifying:
Anchorages were free of bent, broken, missing or loose hardware.
Anchorages were free of corrosion that is more than mild surface oxidation.
Anchorages were free of visible cracks in the concrete near the anchors.
Anchorage configurations were consistent with plant documentation.
SSCs will not be damaged from impact by nearby equipment or structures.
Overhead equipment, distribution systems, ceiling tiles and lighting, and masonry
block walls are secure and not likely to collapse onto the equipment.
Attached lines have adequate flexibility to avoid damage.
The area appears to be free of potentially adverse seismic interactions that could
cause flooding or spray in the area.
The area appears to be free of potentially adverse seismic interactions that could
cause a fire in the area.
The area appears to be free of potentially adverse seismic interactions associated
with housekeeping practices, storage of portable equipment, and temporary
installations (e.g., scaffolding, lead shielding).
The inspectors independently performed their walkdown and verified that the following
areas were inspected and seismic features verified:
Walkdown of the Component Cooling Water Pump Area and associated
equipment on September 18, 2012.
Walk by of the Charging Pump Room and associated equipment on
September 19, 2012.
Additionally, inspectors verified that items that could allow the spent fuel pool to drain
down rapidly were added to the SWEL and these items were walked down by the
licensee.
(2) Findings and Observations:
No NRC-identified or self-revealing findings were identified.
The walkdowns were performed by contract personnel with support from OPPDs
operations and security departments. FCS appropriately conducted the walkdowns in
accordance with the industry guidance. Observations were documented in the corrective
action program as condition reports, as appropriate. The inspectors observed that FCS
completed walkdowns of all accessable equipment. For equipment which was
inaccessible (such as energized electrical busses) or equipment for which full walkdowns
- 41 -
could not be completed, the walkdowns were documented as not completed and followup
inspections were scheduled for system outage windows. The inspection of these items is
expected to be completed prior to plant restart.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On October 18, 2012, the inspectors presented the inspection results to Mr. Mike Prospero, Plant
Manager, and other members of the licensee staff. Additionally, on November 7, 2012 one
finding was recharacterized as an Severity Level IV, cited violation. 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.
- 1 -
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
C. Cameron, Supervisor Regulatory Compliance
L. Cortopassi, Site Vice President
K. Erdman, Supervisor, Engineering Programs
M. Ferm, Manager, Site Performance Improvement
M. Frans, Manager, Engineering Programs
W. Hansher, Supervisor, Nuclear Licensing
K. Ihnen, Manager, Manager, Site Nuclear Oversight
J. James, Manager, Outage
R. King, Director, Site Maintenance
K. Kingston, Manager, Chemistry
T. Maine, Manager, Radiation Protection
E. Matzke, Senior Licensing Engineer
S. Miller, Manager, Design Engineering
V. Naschansy, Director, Site Engineering
T. Orth, Director, Site Work Management
A. Pallas, Manager, Shift Operations
M. Prospero, Division Manager, Plant Operations
T. Simpkin, Manager, Site Regulatory Assurance
M. Smith, Manager, Operations
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000285-2011-010-00 LER Fire Causes a Circuit Breaker to Open Outside Design
Assumptions
05000285-2012-014-00 LER Containment Beam 22 Loading Conditions outside of the
Allowable Limits
05000285-2012-015-00 LER Electrical Equipment Impacted by High Energy Line Break
Outside of Containment
05000285-2012-016-00 LER
Unanalyzed Charging System Socket Welds to the Reactor
Coolant System 05000285/2012005-01
NOV Failure to Update the Safety Analysis Report - Solid Waste
- 2 -
Opened and Closed 05000285/2012005-02
NCV Untimely Corrective Actions for 480 VAC Breaker Issues
2515/188
TI
Inspection of Near-Term Task Force Recommendation 2.3
Seismic Walkdowns
- 3 -
LIST OF DOCUMENTS REVIEWED
Section 1R08: Inservice Inspection Activities
CONDITION REPORTS
2012-01123
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
CFTC-09-108
Field Service Report Steam Generator Secondary Side
Services 2009 Outage
December
18, 2009
MRS-SSP-2229-
CFTC1
Analysis of Eddy Current Data
0
DRAWINGS
NUMBER
TITLE
REVISION /
DATE
E-925-096
Primary Piping Layout (Plan View)
18
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
CFTC-09-108
Field Service Report Steam Generator Secondary Side
Services 2009 Outage
December
18, 2009
89361
Steam Generator Services April 2008 Refueling Outage
May 5, 2008
Steam Generator Eddy Current Test Report - 2008
Refueling Outage
December 9,
2008
Revised License Amendment Request, Application for
Technical Specification Improvement Regarding Steam
Generator Tube Integrity Using the Consolidated Line Item
Improvement Process and Deletion of Sleeving as a Steam
Generator Tube Repair Method
August 30,
2006
FC06968
FCS RSG - Evaluation for the Impact of the RSG on FCS
0
Replacement Steam Generators (Component)
0
- 4 -
CFTC1_SG-B_20080401_ADI-ADH-CALLS
9/5/2012
CFTC1_SG-A_20080401_ADI-ADH-CALLS
9/5/2012
MHI Presentation on FCS Steam Generators
9/5/2012
Page 11 from Final ECTReport08 R1 1364
4/2008
CFTC1_SGA_Pri_sec_res_abs_channels_minus-ndf
9/25/2012
CFTC1_SGB_Pri_sec_res_abs_channels_minus-ndf
9/25/2012
LTR-AMER-
MKG-12-1715
Westinghouse Steam Generator Operational Assessment
Scope
1
Tubes looked at:SG11HCALROD00005 65 tubes
4/27/2008
SG21HCALROD00002 181 tubes
4/30/2008
Section 1R15: Operability Evaluations
CONDITION REPORTS
2012-00550
2012-00551
2012-00552
2012-00657
2012-07085
2012-07143
2012-11933
PROCEDURES
NUMBER
TITLE
REVISION /
DATE
Fueling Operations
64
DRAWINGS
NUMBER
TITLE
REVISION /
DATE
11405-S-17
Reactor Plant Basement Floor Plan El 994-0 Outline
17
11405-S-18
Reactor Plant Ground Floor Plan El 1013-0 Outline
4
11405-S-19
Reactor Plant Operating Fl Plan El 1045-0 and 1060-0
Outline
15
11405-S-20
Reactor Plant Reactor Foundation and Fuel Pit - Sheet 1
2
11405-S-23
Reactor Plant Section & Details Outline - Sheet 2
5
11405-S-24
Reactor Plant Section & Details Outline - Sheet 3
4
11405-S-39
Reactor Plant Ground Fl Plan El 1013-0 Reinf - Sheet 1
5
- 5 -
11405-S-41
Reactor Plant Operating Fl Plan El 1045-0 and 1060-0
Reinforcement - Sheet 1
4
11405-S-43
Reactor Plant Reactor Foundation & Fuel Pit Reinforcement
- Sheet 1
2
11405-S-44
Reactor Plant Reactor Foundation & Fuel Pit Reinforcement
- Sheet 2
2
11405-S-49
Auxiliary Building Misc Details
1
E-57
Refueling Area Crane Rail, Angle, Frame, Containment Plan
1038 Fy 6 In
1
CALCULATIONS
NUMBER
TITLE
REVISION /
DATE
FC01420
Reactor Plant Operating Floor Design
0
FC03230
Containment Structural Design: Columns, Beams,
Reinforcement, Various Elevations - Construction
2
FC06916
Seismic Analysis Calculation for the ReFueling Machine
(FH-1)
0
FC06971
Past Operability Evaluation: RV Head Laydown Area
Seismic Analysis
1
FC07176
Assessment of Concrete Beams at Elev. 1045'-0" in
Containment for Rx Vessel Head Load
2
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION /
DATE
USAR 5.11
Structures Other Than Containment
10
USAR App F
Classification of Structures and Equipment and Seismic
Criteria
9
Section 1R22: Surveillance Testing
WORK ORDERS
436013
436014
436015
PROCEDURES
- 6 -
NUMBER
TITLE
REVISION /
DATE
OP-ST-FH-0001
Refueling System Fuel Handling Machine (FH-1) Interlocks
Test
33
OP-ST-FH-0002
Refueling System Fuel Transfer System Interlocks Test
25
OP-ST-FH-0005
Refueling System Spent Fuel Handling Machine Refueling
Interlocks Test
28
Section 4OA4: IMC 0350 Inspection Activities
CONDITION REPORTS (CR)
2011-8955
2011-8950
2011-8957
2011-7319
2011-8956
2011-5718
2011-5831
2011-5930
2011-5963
2011-5830
2011-5834
2012-12612
2012-13491
2011-2865
2011-6726
2011-7675
2011-5433
2011-8109
2012-03734
2001-02933
2011-09384
2012-09795
2005-01815
2008-05695
2010-06905
2011-00814
2012-02063
2012-03886
2012-04299
2012-04973
2012-09865
2012-09771
2012-09865
2012-10480
2012-06714
2012-13444
2012-08177
2012-05253
2012-05382
2012-05383
2012-05256
2012-06715
2012-05383
2012-06715
2012-06714
2012-07827
2012-07878
2012-05385
2012-07367
2012-06707
2012-07350
2012-04499
2012-05384
2012-13281
2012-11064
2012-10382
2012-07279
2011-5553
2012-12780
2011-2790
2010-2387
2012-11201
2012-10977
2012-11215
2012-04425
2012-09265
2012-00307
2012-04492
2012-02331
2012-10963
2012-00986
2012-4315
2012-03819
WORK ORDERS (WO)
418123
424263
400199
396921
421701
421702
421703
417681
417698
PROCEDURES
NUMBER
TITLE
REVISION
- 7 -
PROCEDURES
NUMBER
TITLE
REVISION
OP-ST-FP-0001A
Fire Protection System Inspection and Test
17
OP-ST-FP-0002
Fire Protection Water Suppression System Valve
Cycling Test
33
OP-ST-FP-0011
Fire Protection System Hose Station Operability Test
8
OCAG-1
Operational Contingency Action Guideline
17
SE-ST-FP-0002
Fire Protection System Motor Driven Fire Pump Full
Flow Test
21
SE-ST-FP-0003
Fire Protection System Diesel Driven Fire Pump Full
Flow Test
25
FCS-65-2
Recovery Checklist Issue Closure
0
FCS-65-3
Restart Classification and Management of recovery
Action Items under MC 0350 Restart Oversight
1
NP 95003 Admin C
Admin Controls for 95003 Work Scope for Station
Recovery
1
PLDBD-CS-56
External Flooding
1
EPIP-OSC-7
Emergency Response Organization (ERO) Activation
at the Emergency Operations Facility (EOF)
3
EPIP-EOF-1
Activation of the Emergency Operations Facility
18
EPIP-TSC-2
Catastrophic Flooding Preparations
15
PE-RR-AE-1000
Flood Barrier Inspection and Repair
9
PE-RR-AE-1001
Flood Barrier and Sandbag Staging and Installation
16
PE-RR-AE-1002
Installation of Portable Steam Generator Make-up
Pumps
5
FCSG-64
External Flooding of Site
2
SO-G-124
Flood Barrier Impairment
2
Acts of Nature
31
AOP 38
Blair Water Main Trouble
4
Loss of Spent Fuel Cooling
8
Loss of Shutdown Cooling
17
- 8 -
PROCEDURES
NUMBER
TITLE
REVISION
OI-CW-1
Circulating Water System Normal Operation
67
EOP/AOP Floating Steps
3
CALCULATIONS
NUMBER
TITLE
REVISION
FC 08030
Intake Structure Cell Level Control Using the Intake
Structure Sluice Gates
11
MISCELLANEOUS DOCUMENTS
NUMBER
TITLE
REVISION
ACA 2011-3019
Equipment Service Life Apparent Cause Analysis
1
ACA 2011-09276 Apparent Cause Analysis for Missed Vendor Manual
1
RCA 2012-03986 Organizational Effectiveness Root Cause Analysis
0
ACA 2008-05695 Apparent Cause Analysis for SI-3A-M Pump Side Motor
Bearing Oil Level Found Low on Sight Glass
0
USAR 9.8
Auxiliary Systems: Raw Water System
31
RCA 2011-10135 Root Cause Analysis: Cultural Weaknesses in Problem
Identification and Resolution
0
RCA 2010-2387
Root Cause Analysis: External Flooding Protection
1
LIC-11-0011
OPPD Reply to Notice of Violation EA-10-084 (Revision 1)
June 7, 2011
Business Continuity Plan
June 11,
2011
Section 4OA5: Other Activities
DRAWINGS
NUMBER
TITLE
REVISION /
DATE
11405-E-61
Reactor Auxiliary Building Tray and Conduit Layout Plan
Basement FL EL 9890 West,
Rev 51
- 9 -
Section 4OA5: Other Activities
DRAWINGS
NUMBER
TITLE
REVISION /
DATE
11405-M-112
Containment & Auxiliary Building Miscellanious Piping Sh1,
Rev 17.
11405-M-66
Auxiliary Building RWD Vents, Drains, & Valve leak Offs EL
971-0 and 989-0,
Rev 19
303.130-M-001
CH-1A Oil Drain
Rev 1
70665-1 Sh1
Component Cooling Water Pump Specification,
Rev 7
A-6039 Sh 11
Safe Shutdown Target Drawing-Auxiliary Building basement
Level, Room 19
Rev 0.
A-6039 Sh 20
Safe Shutdown Target Drawing -Auxiliary Building Ground
Floor Level, Room 56
Rev 1
A-6039 Sh 25
Safe Shutdown Target Drawing-Auxiliary Building Ground
Floor Level, Room 63
Rev 0
A-6039 SH3
Safe Shutdown Target Drawing-Auxiliary building Basement
Level Room 6,
Rev 0
C 1845-833391
Installation & Assy 5 gallion 75 PSIG Suction Stabilizer.
Rev A
C-4055
Charging Pump A Flushing Line Vibration Restraints
Rev 1
D-12627
Cylinder Assembly PIB-STPS,
Rev 7
D-12629
Base Outline- P18
Rev 6
D-12742
Packing Cooling System
Rev 19
D-4112,
Addition of Suction Stabilizer & Discharge Pulsation
Dampener to Charging Pumps,
Rev 1
D-4228 Sh 2
CQE Piping Isometrics Seismic subsystem #CH-283-A
FC 259
Auxiliary Building Equipment Supports,
Rev 2
FIG 8.1.1
P&ID Plant Electrical System,
Rev 142
S-53, Auxiliary
Building
Intermediate Fl
EL 1025-0
Outline Sheet 1,
Rev 4
- 10 -
MISCELLANEOUS DOCUMENTS
TITLE
REVISION /
DATE
Electric Power Research Institute document 1025286, Seismic Walkdown
Guidance,
IPEEE USI A46 ,Seismic Inspections.
9/17/12
NRC Request for Information Pursuant to Title 10 of the Code of Federal
Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the
Near-Term Task Force Review of Insights from the Fukushima Dai-ichi
Accident, dated March 12, 2012
(ML12053A340).
Pre- Job Brief for Fukushima NTTF 2.3 Seismic Walkdowns.
Seismic Walkdown Checklist for AC-3B, CCW Pump.
Seismic Walkdown Checklist for AC-3C, CCW Pump.
Seismic Walkdown checklist for CH-1A, Charging Pump