ML14094A052
ML14094A052 | |
Person / Time | |
---|---|
Site: | Fort Calhoun |
Issue date: | 04/03/2014 |
From: | Hay M NRC/RGN-IV/DRP |
To: | Cortopassi L Omaha Public Power District |
References | |
EA-13-201 IR-13-013 | |
Download: ML14094A052 (122) | |
See also: IR 05000285/2013013
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION IV
1600 E LAMAR BLVD
ARLINGTON, TX 76011-4511
April 3, 2014
Louis P. Cortopassi, Vice President
and Chief Nuclear Officer
Omaha Public Power District
Fort Calhoun Station FC-2-4
P.O. Box 550
Fort Calhoun, NE 68023-0550
SUBJECT: FORT CALHOUN - MANUAL CHAPTER 0350 TEAM INSPECTION REPORT
NO. 05000285/2013013 AND NOTICE OF VIOLATION
Dear Mr. Cortopassi:
On February 18, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed a team
inspection at the Fort Calhoun Station (FCS). The purpose of this inspection was to evaluate
the readiness of plant hardware, plant staff, plant processes, and management programs that
supported safe restart and continued operation of the FCS. The team focused on those issues
described in the Restart Checklist, enclosed in the Confirmatory Action Letter issued to the FCS
on June 11, 2012 (ML12163A287), and updated on February 26, 2013 (ML13057A287), which
were ready for NRC inspection. The enclosed report documents the inspection results which
were discussed on February 18, 2014, with you and other members of your staff.
During this inspection, the NRC staff examined activities conducted under your license as they
relate to safety and compliance with the Commissions rules and regulations and with the
conditions of your license. The team reviewed selected procedures and records, observed
activities, and interviewed personnel.
Twenty one findings of very low safety significance (Green) are documented in this report. All of
these findings involved violations of NRC requirements. Three of these violations were
determined to be Severity Level IV under the traditional enforcement process. One of the SLIV
violations is being cited in the enclosed Notice of Violation (Notice) as discussed below.
The NRC determined that a Severity Level IV violation of NRC requirements occurred. The
circumstances of the violation involved incomplete and inaccurate information submitted by FCS
in a response to a Request for Additional Information (RAI) concerning the exemption request
from the requirements of 10 CFR Part 50, Appendix R, Section III.G.1.b for Fire Area 31 at the
Fort Calhoun Station. The details of the violation are described in the enclosed report. The
violation was evaluated in accordance with the NRC Enforcement Policy. The current
Enforcement Policy is included on the NRC's web site at
http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. In accordance with
Section 6.9.c.1 of the Enforcement Policy, this violation would normally be assessed as Severity
L. Cortopassi -2-
Level III. However, in accordance with the Enforcement Policy, and considering the very low
safety significance (Green) of the associated finding, the NRC concluded this violation is more
appropriately assessed as Severity Level IV with a response required.
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 NRCs
review of your response to the notice will also determine whether further enforcement action is
necessary to ensure your compliance with regulatory requirements.
If you contest these violations or significance of these NCVs, 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 the Fort Calhoun Station.
If you disagree with a cross-cutting aspects 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 the
FCS.
In accordance with 10 CFR 2.390 of the NRC's Rules of Practice and Procedure, 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/
Michael Hay, Chief
Project Branch F
Division of Reactor Projects
Docket No.: 50-285
License No.: DPR-40
Enclosure:
1. Notice of Violation
2. NRC Inspection Report 05000285/2013017
w/Attachments:
Attachment 1: Supplemental Information
L. Cortopassi -3-
Electronic Distribution by RIV:
Regional Administrator (Marc.Dapas@nrc.gov)
Deputy Regional Administrator (Steven.Reynolds@nrc.gov)
MC0350 Chairman (Anton.Vegal@nrc.gov)
MC0350 Vice Chairman (Louise.Lund@nrc.gov)
DRP Director (Kriss.Kennedy@nrc.gov)
DRP Deputy Director (Troy.Pruett@nrc.gov)
Acting DRS Director (Jeff.Clark@nrc.gov)
Acting DRS Deputy Director (Geoffrey.Miller@nrc.gov)
Senior Resident Inspector (John.Kirkland@nrc.gov)
Resident Inspector (Jacob.Wingebach@nrc.gov)
Branch Chief, DRP/F (Michael.Hay@nrc.gov)
Project Engineer, DRP/F (Chris.Smith@nrc.gov)
FCS Administrative Assistant (Janise.Schwee@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Branch Chief, DRS/TSB (Ray.Kellar@nrc.gov)
Project Manager (Lynnea.Wilkins@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
ACES (R4Enforcement.Resource@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Regional State Liaison Office (William.Maier@nrc.gov)
Technical Support Assistant (Loretta.Williams@nrc.gov)
RidsOeMailCenter Resource
OE, Director (Roy.Zimmerman@nrc.gov)
OE/EB, Branch Chief (Nick.Hilton@nrc.gov)
OE/CRB, Enforcement Specialist (Nicole.Coleman@nrc.gov)
OE/EGB Sr. Enforcement Specialist (John.Wray@nrc.gov)
NRR/DIRS/IPAB/IAET Allegations Specialist (Carleen.Sanders@nrc.gov)
NRREnforcement Resource
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
RIV/ETA: OEDO (Joseph.Nick@nrc.gov)
MC 0350 Panel Member (Michael.Markley@nrc.gov)
MC 0350 Panel Member (Joseph.Sebrosky@nrc.gov)
MC 0350 Panel Member (Michael.Balazik@nrc.gov)
ROP reports
File located: R:\_REACTORS\_FCS\2014 ADAMS: ML14094A052
SUNSI Rev Yes No ADAMS Yes No Reviewer MCH
Compl. Initials
Publicly Avail Yes No Sensitive Yes No
SRI:DRP/C SRI:DRS/EB2 RI:DRS/EB2 BC:DRS/EB2 ORA/ACES
JJosey SGraves JWatkins JDixon RBrowder
/RA/ /RA/ /RA/ /RA/ /RA/
4/3/14 3/26/14 4/2/14 4/2/14 4/1/14
BC:DRP/F
MHay
4/3/14
/RA/
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
NOTICE OF VIOLATION
Omaha Public Power District (OPPD) Docket No. 50-285
Fort Calhoun Station License No. DPR-40
EA-2013-201
During a U.S. Nuclear Regulatory Commission (NRC) inspection conducted from July 8 through
December 16, 2013, a violation of NRC requirements was identified. In accordance with the
NRC Enforcement Policy, the violation is listed below:
10 CFR 50.9(a), Completeness and Accuracy of Information, requires in part that,
information provided to the Commission by a licensee shall be complete and accurate in
all material respects.
Contrary to the above, on October 13, 2008, the licensee provided to the Commission
documentation which contained information that was not complete and accurate in all
material respects. Specifically, the licensee submitted a letter dated October 13, 2008,
which stated that the pyrocrete enclosure remained in place to protect the cables
associated with AC-10A and AC-10B from a fire in the intake structure. When in fact,
the motor lead cables associated with raw water pump AC-10A were not protected by
the pyrocrete enclosure. In a letter, dated February 6, 2009, the NRC granted an
exemption from the specific requirements of Section III.G.1.b of 10 CFR Part 50,
Appendix R, for the Fort Calhoun Station based in part, upon the NRCs review and
evaluation of information provided by the licensee in its letter dated October 13, 2008.
Therefore, this information was considered material to the NRC.
This is a Severity Level IV Violation (Section 6.9).
Pursuant to the provisions of 10 CFR 2.201, Omaha Public Power District (OPPD) 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 at the Fort
Calhoun facility, 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-13-201
and should include for the 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 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.
-1- Enclosure 1
Because your response will be made available electronically for public inspection in the NRC
Public Document Room or from the NRCs Agencywide Documents Access and Management
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 or proprietary
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).
Dated this 3rd day of April 2014.
-2-
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 05000285
License: DPR-40
Report: 05000285/2013013
Licensee: Omaha Public Power District
Facility: Fort Calhoun Station
Location: 9610 Power Lane
Blair, NE 68008
Dates: July 8, 2013 through February 18, 2014
Inspectors: H. Barrett, Senior Fire Protection Engineer, Headquarters
R. Deese, Senior Project Engineer, Region IV
G. George, Senior Reactor Inspector, Region IV
J. Hanna, Senior Reactor Analyst, Region II
R. Haskell, Reactor System Engineer, Headquarters
C. Henderson, Resident Inspector, Region IV
J. Jacobson, Senior Reactor Operations Engineer, Headquarters
J. Josey, Senior Resident Inspector, Region IV
S. Laur, Senior Reliability and Risk Analyst, Headquarters
T. Lightly, Project Engineer, Region II
D. Loveless, Senior Reactor Analyst, Region IV
S. Makor, Reactor Inspector, Region IV
J. Polickoski, Project Manager, Headquarters
F. Ramirez, Resident Inspector, Region III
J. Robles, Reactor System Engineer, Headquarters
C. Sanders, Allegations Specialist, Headquarters
A. Scarbeary, Resident Inspector, Region III
C. Smith, Project Engineer, Region IV
R. Telson, Reactor Operations Engineer, Headquarters
J. Watkins, Reactor Inspector, Region IV
J. Wingebach, Resident Inspector, Region IV
Accompanying C. Baron, Mechanical Contractor, Beckman and Associates
Personnel N. Patel, Electrical Contractor, Beckman and Associates
Approved By: Michael Hay, Chief
Project Branch F
Division of Reactor Projects
-1- Enclosure 2
SUMMARY OF FINDINGS
IR 05000285/2013013; 07/08/2013 - 2/18/2014; Fort Calhoun Station,
Supplemental Inspection for Repetitive Degraded Cornerstones, Multiple Degraded
Cornerstones, Multiple Yellow Inputs or One Red Input.
The report covered a seven month period of inspection by an Inspection Manual Chapter 0350
inspection team. Eighteen Green non-cited violations were identified. Additionally, one cited
and two non-cited, Severity Level IV violations were identified. The significance of most findings
is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609,
Significance Determination Process. The cross-cutting aspect is determined using Inspection
Manual Chapter 0310, Components Within the Cross Cutting Areas. Findings for which the
significance determination process does not apply may be Green or be assigned a severity level
after NRC management review. The NRC's program for overseeing the safe operation of
commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 4, dated December 2006.
A. NRC-Identified Findings and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green. The team identified a non-cited violation of 10 CFR Part 50 Appendix B,
Criterion XVI, Corrective Actions, for the licensees failure to promptly identify
and correct a condition adverse to quality. Specifically, the licensee failed to fully
implement a corrective action from a previous breaker issue, which was to
perform current injection testing for the 480 Vac 1B4A bus breakers without the
full function test kit. Testing with the full function test kit would not identify if zone
select interface jumpers were incorrectly installed. The licensee performed
current injection testing without the full functional test kit on the 480 Vac load
center main breaker 1B4A and the bus tie breaker BT-1B4A. The licensee
addressed this deficiency by performing the appropriate testing on the two
breakers. The licensee entered this deficiency into their corrective action
program for resolution as Condition Report (CR) 2013-13262.
The licensees failure to promptly identify and correct a condition adverse to
quality is a performance deficiency. This performance deficiency was more than
minor, and therefore a finding, because it was associated with the equipment
performance attribute of the Mitigating Systems Cornerstone and affected the
associated objective to ensure availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. The team
evaluated the finding using Inspection Manual Chapter 0609, Appendix G,
Shutdown Operations Significance Determination Process, 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, dated May 25, 2004, and
determined that the finding is of very low safety significance (Green) because the
finding did not require a quantitative risk assessment since adequate mitigating
equipment remained available. The finding has a cross-cutting aspect in the
area of human performance associated with the decision-making component
-2-
because the licensee did not ensure that the proposed action was safe in order
to proceed, rather than unsafe in order to disapprove the action
H.1(b)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion XVII, Quality Assurance Records, associated with the licensees
failure to furnish evidence of an activity affecting quality associated with the
480 Vac breakers. Specifically, the licensee failed to maintain design documents
that detailed the correct Digital Low Resistance Ohm (DLRO) values required for
ensuring proper connections between the Square D Masterpact NW
breaker/cradle assembly to the GE AKD-5, 480 Vac cubicle stabs. The licensee
re-generated acceptance criteria to address this issue. This issue was entered
into the licensees corrective action program as CR 2013-04032.
The licensees failure to furnish evidence that showed the required DLRO values
ensured proper connections between the Square D Masterpact NW
breaker/cradle assemble to the GE AKD-5, 480 V cubicle stabs is a performance
deficiency. The performance deficiency was determined to be more than minor,
and therefore a finding, because it affected the design control attribute of the
Mitigating Systems Cornerstone, and it directly affected the cornerstone objective
to ensure availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Using Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings At-Power, dated July 1, 2012, the finding was determined to have very
low safety significance (Green) because it: (1) was not a deficiency affecting the
design and qualification of a mitigating structure, system, or component, and did
not result in a loss of operability or functionality; (2) did not represent a loss of
system and/or function; (3) did not represent an actual loss of function of at least
a single train for longer than its allowed outage time or two separate safety
systems out-of-service for longer than their Technical Specification allowed
outage time; and (4) did not represent an actual loss of function of one or more
non-Technical Specification trains of equipment designated as high safety-
significance in accordance with the licensees maintenance rule program. This
finding had a cross-cutting aspect in the area of human performance, associated
with the resources component, because the licensee failed to maintain complete,
accurate, and up-to-date design documentation. Specifically, the licensee did not
maintain the engineering process for determining acceptable DLRO values
H.2(c)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, for the licensees approval of Root Cause Analysis 2013-03424,
Revision 0 and Revision 1, MSPI Safety System Functional Failures Degrading
Trend, which did not assure corrective actions to prevent repetition of a
significant condition adverse to quality. The licensees addressed this issue by
revising the root cause analysis. The licensee entered this deficiency into their
corrective action program for resolution as CRs 2013-00584 and 2013-14614.
-3-
The licensees failure to establish measures to assure that the cause of the
degrading trend in MSPI safety system functional failures would be promptly
identified and action taken to preclude repetition in accordance with
10 CFR Part 50, Appendix B, Criterion XVI, was a performance deficiency. The
performance deficiency was more than minor, and therefore a finding, because
the failure to correct the cause and preclude the repetition of the cause would
have the potential to lead to a more significant safety concern. Specifically,
failure to identify the correct cause and preclude repetition could lead to a high
frequency of safety system functional failures. This finding was associated with
the mitigating systems cornerstone. Using Inspection Manual Chapter 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-
Power, dated July 1, 2012, the finding was determined to be of very low safety
significance (Green) because it: (1) was not a deficiency affecting the design
and qualification of a mitigating structure, system, or component, and did not
result in a loss of operability or functionality; (2) did not represent a loss of
system and/or function; (3) did not represent an actual loss of function of at least
a single train for longer than its allowed outage time, or two separate safety
systems out-of-service for longer than their Technical Specification allowed
outage time; and (4) did not represent an actual loss of function of one or more
non-Technical Specification trains of equipment designated as high safety-
significance in accordance with the licensees maintenance rule program. This
finding has a cross-cutting aspect in the area of in the area of problem
identification and resolution, associated with the corrective action program
component, because the licensee did not thoroughly evaluate the problem and,
consequently, the resolution did not identify the extent of cause as necessary
P.1(c)(Section 4OA4).
- Green. The team identified multiple examples of a non-cited violation of
10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees
failure to control deviations from design standards. Specifically, the licensee
failed to control deviations from the design basis requirements for structural
calculations related to the reactor coolant system. The licensee took action to
perform additional analysis to confirm the operability of the affected components
and to determine the scope of the problem. The licensee entered this deficiency
into their corrective action program for resolution as CRs 2013-19878,
2013-18361, 2013-20281, and 2013-14726.
The failure to control deviations from quality standards as required by
10 CFR Part 50, Appendix B, Criterion III, was a performance deficiency. This
performance deficiency is more than minor, and therefore a finding, because it is
associated with the design control attribute of the Mitigating Systems
Cornerstone, and affected the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Using Inspection Manual Chapter 0609, Appendix A,
The Significance Determination Process (SDP) for Findings At-Power, dated
July 1, 2012, the finding was determined to have very low safety significance
(Green) because it: (1) was not a deficiency affecting the design and
-4-
qualification of a mitigating structure, system, or component, and did not result in
a loss of operability or functionality; (2) did not represent a loss of system and/or
function; (3) did not represent an actual loss of function of at least a single train
for longer than its allowed outage time, or two separate safety systems out-of-
service for longer than their Technical Specification allowed outage time; and
(4) did not represent an actual loss of function of one or more non-Technical
Specification trains of equipment designated as high safety-significance in
accordance with the licensees maintenance rule program. There was no
cross-cutting aspect assigned to this finding because this issue does not reflect
present licensee performance (Section 4OA4).
- Green. The team identified multiple examples of a non-cited violation of
10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings. Specifically, the licensees failed to follow station procedures for
corrective actions, operability evaluations, and performance of calculations for
instances where the licensees interim operability procedure was invoked for
degraded conditions associated with piping and pipe supports. As a result, non-
conservative design inputs were used without entering the non-conformances
into the corrective action process or performing procedurally required operability
evaluations. The licensees corrective action was to capture the identified
instances in the corrective action program and discontinue the use of the interim
operability procedure. This issue was entered into the licensees corrective
action program as CR 2013-03598.
The failure to follow the interim operability procedure was a performance
deficiency. This performance deficiency is more than minor, and therefore a
finding, because it is associated with the human performance attribute of the
Mitigating Systems Cornerstone, and affected the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Using Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings At-Power, dated July 1, 2012, and guidance from the Office of Nuclear
Reactor Regulation, Division of Engineering technical staff for issues where the
inputs to calculations deviated from approved standards, the finding was
determined to have very low safety significance (Green) because: (1) the Office
of Nuclear Reactor Regulation technical staff determined the non-conformances
would not render the evaluated component as inoperable or unable to perform its
safety function; (2) it was not a deficiency affecting the design and qualification
of a mitigating structure, system, or component; and (3) it did not represent an
actual loss of function of one or more non-Technical Specification trains of
equipment designated as high safety-significance in accordance with the
licensees maintenance rule program. This finding has a cross-cutting aspect in
the area of human performance associated with work practices component
because the licensee failed to define and effectively communicate expectations
regarding compliance with station procedures H.4(b)(Section 4OA4).
-5-
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action, for the licensees failure to correct conditions
adverse to quality in safety-related equipment. The team identified multiple
examples where an interim operability criteria procedure was applied instead of
correcting the conditions adverse to quality in a timely manner. The licensees
corrective actions included performing an extent of condition review to identify
similar issues and ensure they are entered into the corrective action program for
appropriate resolution. This issue was entered into the licensees corrective
action program as CR 2013-22426.
The failure to correct conditions adverse to quality is a performance deficiency.
This performance deficiency was more than minor, and therefore a finding,
because it was associated with the equipment performance attribute of the
Mitigating Systems Cornerstone, and affected the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Using Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings At-Power, dated July 1, 2012, the finding was determined to have very
low safety significance (Green) because it: (1) was not a deficiency affecting the
design and qualification of a mitigating structure, system, or component, and did
not result in a loss of operability or functionality; (2) did not represent a loss of
system and/or function; (3) did not represent an actual loss of function of at least
a single train for longer than its allowed outage time, or two separate safety
systems out-of-service for longer than their Technical Specification allowed
outage time; and (4) did not represent an actual loss of function of one or more
non-Technical Specification trains of equipment designated as high safety-
significance in accordance with the licensees maintenance rule program. This
finding has a cross-cutting aspect in the area of problem identification and
resolution associated with the corrective action program component because the
licensee had failed to implement a corrective action program with a low threshold
for identifying issues to ensure that an issue potentially affecting nuclear safety
was promptly identified and fully evaluated P.1(a)(Section 4OA4).
- Green. The team identified a non-cited violation of Title 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the
licensees failure to develop an adequate procedure for assessing operability of
degraded piping and pipe supports. Specifically, Station Procedure PED-MEI-17,
"Interim Operability Criteria," a procedure the licensee used to evaluate CQE and
L-CQE piping and piping supports that are found to exceed design basis
requirements, was inadequate for this application because it did not contain all
applicable constraints. The licensees corrective actions were to capture the
identified instances in the corrective action program and discontinue the use of
the interim operability procedure. This issue was entered into the licensees
corrective action program as CR 2013-22342.
The failure to use an adequate procedure for evaluating degraded or
nonconforming pipe and pipe supports is a performance deficiency. This
-6-
performance deficiency was more than minor, and therefore a finding, because it
is associated with the equipment performance attribute of the Mitigating Systems
Cornerstone, and affected the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Using Inspection Manual Chapter 0609, Appendix A,
The Significance Determination Process (SDP) for Findings At-Power, dated
July 1, 2012, and guidance from the Office of Nuclear Reactor Regulation,
Division of Engineering technical staff for issues where the inputs to calculations
deviated from approved standards, the finding was determined to have very low
safety significance (Green) because: (1) the Office of Nuclear Reactor
Regulation technical staff determined the non-conformances would not render
the evaluated component as inoperable or unable to perform its safety function;
(2) it was not a deficiency affecting the design and qualification of a mitigating
structure, system, or component; and (3) it did not represent an actual loss of
function of one or more non-Technical Specification trains of equipment
designated as high safety-significance in accordance with the licensees
maintenance rule program. There was no cross-cutting aspect assigned to this
finding because this issue does not reflect present licensee performance
(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, associated with the
licensees failure to follow Station Procedure NOD-QP-31, Operability
Determination Process. Specifically, Step 4.3.15 required, in part, that, A
positive determination of operability must be justified, including a technical
discussion of why the concern identified does not prevent the item from fulfilling
its intended safety function. The team identified that the operability
determination associated with a component identified as beyond its specified
service life lacked adequate technical justification for why the item was operable
with the degraded or nonconforming condition. The licensee addressed this
issue by establishing an adequate basis for operability for the non-conformances.
The licensee entered this deficiency into their corrective action program for
resolution as CR 2013-12255.
The failure to properly assess and document the basis for operability when a
degraded or nonconforming condition was identified is a performance deficiency.
This performance deficiency was more than minor, and therefore a finding,
because it is associated with the equipment performance attribute of the
Mitigating Systems Cornerstone and affected the cornerstone objective to ensure
the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Since the finding involving
inadequate operability determinations occurred while in a shutdown condition,
the team used Manual Chapter 0609, Appendix G, Shutdown Operations
Significance Determination Process, and determined the finding to have very
low safety significance (Green) because the finding: (1) did not increase the
likelihood of a loss of reactor coolant system inventory; (2) did not degrade the
licensees ability to terminate a leak path or add reactor coolant system inventory
-7-
when needed; and (3) did not degrade the licensees ability to recover decay
heat removal once it was lost. This finding has a cross-cutting aspect in the area
of human performance, associated with the decision-making component,
because the licensee failed to use conservative assumptions in decision making
when performing operability determinations H.1(b)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, associated with the licensees failure to conduct an
adequate evaluation of the impacts of modifying the turbine driven auxiliary
feedwater pump (FW-10) during all modes of operation. Specifically, the
licensee instituted an engineering change package to modify the pump from a
variable speed to a constant speed setting and did not consider the dynamic
system changes that could affect the pump operation for all design basis events
and operating conditions. The licensee adequately addressed this issue by
performing a detailed analysis that determined the change did not adversely
affect the function of the pump. The licensee entered this deficiency into their
corrective action program for resolution as CR 2013-10465.
The failure to evaluate the effects of modifying the turbine driven auxiliary
feedwater pump from a variable speed to a constant speed for all modes of
operation was a performance deficiency. This performance deficiency was more
than minor, and therefore a finding, because it was associated with the
configuration control attribute of the Mitigating Systems Cornerstone, and
affected the cornerstone objective to ensure the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Using Inspection Manual Chapter 0609, Appendix A, The
Significance Determination Process (SDP) for Findings At-Power, dated
July 1, 2012, the finding was determined to have very low safety significance
(Green) because it: (1) was not a deficiency affecting the design and
qualification of a mitigating structure, system, or component, and did not result in
a loss of operability or functionality; (2) did not represent a loss of system and/or
function; (3) did not represent an actual loss of function of at least a single train
for longer than its allowed outage time, or two separate safety systems out-of-
service for longer than their Technical Specification allowed outage time; and
(4) did not represent an actual loss of function of one or more non-Technical
Specification trains of equipment designated as high safety-significance in
accordance with the licensees maintenance rule program. This finding has a
cross-cutting aspect in the area of human performance associated with the
decision-making component because the licensee failed to use conservative
assumptions in decision making. Specifically, the licensee did not reanalyze the
pump performance parameters to identify any potentially adverse effects of
changing the pump to a constant speed control H.1(b)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, for the licensees
programmatic failure to conduct adequate operating experience reviews for root
cause evaluations in accordance with Station Procedure FCSG-24-4, Condition
-8-
Report and Root Cause Evaluation, Revision 5. Specifically, during the course
of the inspection, the team identified four specific examples where licensee staff
failed to conduct a thorough operating experience review while performing a root
cause analysis to determine whether the same or similar problems have occurred
at the Fort Calhoun Station or within the industry. Thorough operating
experience reviews are important for the identification of corrective actions that
prevent the issues from recurring and determining the associated extent of
condition and/or generic implications. This issue was entered into the licensees
corrective action program as CR 2013-14205.
The licensees failure to conduct adequate operating experience reviews for root
cause evaluations was a performance deficiency. This performance deficiency is
more than minor, and therefore a finding, because if left uncorrected it has the
potential to lead to a more significant safety concern. Specifically, if the licensee
does not thoroughly evaluate operating experience to determine whether the
same or similar problems have occurred at the Fort Calhoun Station or within the
industry, then effective corrective actions to prevent the issues from recurring
may not be implemented and an adequate extent of condition and/or generic
implications from the issue may not be identified. This finding was associated
with the Mitigating Systems Cornerstone. Using Inspection Manual
Chapter 0609, Appendix G, Shutdown Operations Significance Determination
Process, 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, dated May 25, 2004, this finding was determined to be of very low
safety significance (Green) because the finding did not require a quantitative risk
assessment because adequate mitigating equipment remained available. This
finding has a cross-cutting aspect in the area of problem identification and
resolution associated with the Operating Experience component because the
licensee did not use operating experience information, including vendor
recommendations and internally generated lessons learned, to support plant
safety by implementing and institutionalizing operating experience through
changes to station processes, procedures, equipment, and training programs
P.2(b)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, associated with the licensees failure to fully
incorporate applicable design requirements into the plant design. Specifically,
since initial construction the licensee has failed to incorporate a ventilation
system for the vital switchgear rooms that was capable of maintaining room
temperature within design requirements under all design conditions. This issue
does not represent an immediate safety concern because the licensee has
compensatory measures in place to maintain room temperatures while corrective
actions to resolve the issue are being implemented. This issue was entered into
the licensees corrective action program as CR 2013 9804.
The failure to fully incorporate applicable design requirements is a performance
deficiency. The performance deficiency was determined to be more than minor,
-9-
and therefore a finding, because it affected the design control attribute of the
Mitigating Systems Cornerstone, and it directly affected the cornerstone objective
to ensure availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Using Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings At-Power, dated July 1, 2012, the finding was determined to have very
low safety significance (Green) because it: (1) was not a deficiency affecting the
design and qualification of a mitigating structure, system, or component, and did
not result in a loss of operability or functionality; (2) did not represent a loss of
system and/or function; (3) did not represent an actual loss of function of at least
a single train for longer than its allowed outage time, or two separate safety
systems out-of-service for longer than their Technical Specification allowed
outage time; and (4) did not represent an actual loss of function of one or more
non-Technical Specification trains of equipment designated as high safety-
significance in accordance with the licensees maintenance rule program. This
finding has a cross-cutting aspect in the area of problem identification and
resolution, associated with the corrective action program component, because
the licensee did not thoroughly evaluate the problem and, consequently, the
resolution did not identify the extent of cause as necessary
P.1(c)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action, for the licensees failure to take adequate
corrective actions regarding non-Category I (seismic) piping in the intake
structure raw water vault. The licensees corrective actions for this issue
involved isolating and removing the piping. The licensee entered this deficiency
into their corrective action program for resolution as CRs 2013-04782,
2013-04956, 2013-09256, 2013-10626, and 2013-22090.
The failure to take adequate corrective action regarding non-Category I (seismic)
piping in the intake structure raw water vault is a performance deficiency. The
performance deficiency was more than minor, and therefore a finding, as it is
associated with the design control attribute of the Mitigating Systems
Cornerstone and affected the associated cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events
to prevent undesirable consequences. Using Inspection Manual Chapter 0609,
Appendix A, The Significance Determination Process for Findings At-Power,
dated July 1, 2012, this finding was determined to have very low safety
significance (Green) because it: (1) was not a deficiency affecting the design
and qualification of a mitigating structure, system, or component, and did not
result in a loss of operability or functionality; (2) did not represent a loss of
system and/or function; (3) did not represent an actual loss of function of at least
a single train for longer than its allowed outage time, or two separate safety
systems out-of-service for longer than their Technical Specification allowed
outage time; and (4) did not represent an actual loss of function of one or more
non-Technical Specification trains of equipment designated as high safety-
significance in accordance with the licensees maintenance rule program. The
- 10 -
finding has a cross-cutting aspect in the area of human performance associated
with the decision-making component such that the licensee demonstrates that
nuclear safety is an overriding priority. Specifically, that the licensee uses
conservative assumptions in decision making and adopts 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)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, associated with the
licensees failure to follow Station Procedure NOD-QP-31, Operability
Determination Process, to adequately assess and document the basis for
operability when a nonconforming condition was identified. Specifically, the
licensee did not determine the effect of a ruptured 6-inch pipe in the raw water
system with respect to the safety function provided by the raw water system
during a design seismic event. To address this issue the licensee revised the
operability evaluation and established a reasonable basis for operability. The
licensee entered this deficiency into their corrective action program for resolution
as CRs 2013-13410 and 2013-13634.
The failure to adequately assess and document the basis for operability of the
raw water system with respect to the non-conforming seismic design criteria is a
performance deficiency. The performance deficiency was more than minor, and
therefore a finding, as it is associated with the equipment performance attribute
of the Mitigating Systems Cornerstone and affected the associated cornerstone
objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. Using
Inspection Manual Chapter 0609, Appendix A, The Significance Determination
Process for Findings At-Power, dated July 1, 2012, this finding was determined
to have very low safety significance (Green) because it: (1) was not a deficiency
affecting the design and qualification of a mitigating structure, system, or
component, and did not result in a loss of operability or functionality; (2) did not
represent a loss of system and/or function; (3) did not represent an actual loss of
function of at least a single train for longer than its allowed outage time, or two
separate safety systems out-of-service for longer than their Technical
Specification allowed outage time; and (4) did not represent an actual loss of
function of one or more non-Technical Specification trains of equipment
designated as high safety-significance in accordance with the licensees
maintenance rule program. This finding has a cross-cutting aspect in the area of
problem identification and resolution, associated with the corrective action
program component, because the licensee did not thoroughly evaluate the
problem such that the resolutions address causes and extent of conditions. This
includes properly classifying, prioritizing, and evaluating for operability and
reportability conditions adverse to quality P.1(c)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures and Drawings, involving the licensees
- 11 -
failure to follow procedures when evaluating the flooding mitigation impact of the
removal of the motor for raw water Pump B. Specifically, on June 18, 2013, the
operability determination for Corrective Action 018 of CR 2011-10302 was not
performed in accordance with Station Procedure NOD-QP-31, Operability
Determination Process, Step 4.3.15, and consequently, failed to evaluate the
impact of having only two diversely powered available raw water pumps to
support shutdown cooling system operability during a postulated site flood. This
issue did not represent an immediate safety concern and has been entered into
the corrective action program as CR 2013-15270.
The failure to properly assess and document the basis for operability when a
degraded or nonconforming condition was identified is a performance deficiency.
This performance deficiency was more than minor, and therefore a finding,
because it is associated with the equipment performance attribute of the
Mitigating Systems Cornerstone and affected the cornerstone objective to ensure
the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Using Inspection Manual
Chapter 0609, Appendix G, Shutdown Operations Significance Determination
Process, 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, dated May 25, 2004, this finding was determined to be of very low
safety significance (Green) because the finding did not require a quantitative risk
assessment because adequate mitigating equipment remained available. This
finding has a cross-cutting aspect in the area of human performance associated
with the work control component. Specifically, the team identified that the
licensee failed to adequately plan and coordinate work activities, in which,
interdepartmental coordination was necessary to assure plant and human
performance H.3(b)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, associated with the licensees failure to correctly
translate the acceptance limit of intake sluice gate leakage values into
procedures. Specifically, the acceptance limit from the licensees testing was
applied to 1000 feet of intake level and not to the 983 to 988 feet operating band
prescribed in Section I - Flooding, of Station Procedure AOP-01, Acts of
Nature. This issue did not represent an immediate safety concern and has been
entered into the corrective action program as CR 2013-15287.
The failure to fully incorporate applicable design requirements is a performance
deficiency. This performance deficiency was more than minor, and therefore a
finding, because it is associated with the design control attribute of the Mitigating
Systems Cornerstone and affected the associated cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Using Inspection Manual
Chapter 0609, Appendix G, Shutdown Operations Significance Determination
Process, Attachment 1, 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
- 12 -
Pressurizer, dated May 25, 2004, the team determined that because this finding
did not increase the likelihood of a loss of reactor coolant system inventory; did
not degrade the licensees ability to terminate a leak path or add reactor coolant
system inventory; and did not degrade the licensees ability to recover decay
heat removal. This finding did not require a Phase 2 or 3 analysis as stated in
Checklist 4. Therefore, the finding is determined to have very low safety
significance (Green). This finding has a cross-cutting aspect in the area of
problem identification and resolution associated with the corrective action
program component because the licensee did not thoroughly evaluate problems
such that the resolutions address causes and extent of conditions
P.1(c)(Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, for the licensee's failure to
maintain an adequate procedure for site flooding. Specifically, since
June 2013the licensee failed to include appropriate quantitative or qualitative
acceptance criteria for Section I - Flooding, of Station Procedure AOP-01, Acts
of Nature, on how to proceed if steps taken to maintain intake cell level less than
988 feet were unsuccessful during a flooding event. This issue did not represent
an immediate safety concern and has been entered into the corrective action
program as CR 2013-15289.
The licensees failure to maintain an adequate procedure for maintaining intake
cell level during a flood is a performance deficiency. This performance deficiency
was more than minor, and therefore a finding, because it is associated with the
procedure quality attribute of the Mitigating Systems Cornerstone and affected
the associated cornerstone objective to ensure the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Using Inspection Manual Chapter 0609, Appendix G, Shutdown
Operations Significance Determination Process, Attachment 1, 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, dated May 25, 2004, the
finding is determined to have very low safety significance (Green) because the
finding did not increase the likelihood of a loss of reactor coolant system
inventory; did not degrade the licensees ability to terminate a leak path or add
reactor coolant system inventory; and did not degrade the licensees ability to
recover decay heat removal. This finding did not require a Phase 2 or 3 analysis
as stated in Checklist 4. This finding has a cross-cutting aspect in the area of
problem identification and resolution associated with the corrective action
program component because the licensee did not thoroughly evaluate problems
such that the resolutions address causes and extent of conditions
P.1(c)(Section 4OA4).
- Green. The team identified a non-cited violation of License Condition 3.D, Fire
Protection Program, for the failure to translate Appendix R license exemptions
into the fire protection program design. Specifically, the licensee failed to
translate the exemption from 10 CFR Part 50, Appendix R, Section III.G, that was
- 13 -
granted July 3, 1985, for the Intake Structure, Fire Area 31, into a design that met
those exemptions. The licensee did not protect the cables for both raw water
pumps AC-10A and AC-10B from any credible fire in the intake structure. This
issue did not represent an immediate safety concern and was entered into the
licensees corrective action program as CR 2013-16201.
The failure to translate Appendix R license exemptions into the fire protection
program design is a performance deficiency. This performance deficiency was
more than minor, and therefore a finding, because it was associated with the
protection against external factors attribute of the Mitigating Systems
Cornerstone and affected the associated objective to ensure availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Using Inspection Manual Chapter 0609, Appendix F,
Fire Protection Significance Determination Process, dated September 20, 2013,
Step 1.3, the team determined that the reactor would have been able to reach
and maintain cold shutdown, therefore, this finding was determined to have very
low safety significance (Green). There was no cross-cutting aspect assigned to
this finding because the deficiency was over three years ago and does not reflect
present licensee performance (Section 4OA4).
- Green. The team identified a non-cited violation of 10 CFR 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to
document the extent of condition review for a number of Root Cause Analyses in
accordance with corrective action program procedures. Specifically, during the
course of the inspection, the team identified four examples where the licensee
did not follow Station Procedure FCSG-24-4, Condition Report and Cause
Evaluation, and, as a result, did not evaluate the extent to which the actual
conditions existed with other plant processes, systems, equipment, or human
performance related activities. This issue does not represent an immediate
safety concern and was entered into their corrective action program as condition
report CR 2013-18291.
The failure to follow the requirements of Station Procedure FCSG-24-4 when
documenting extent of condition reviews in multiple Root Cause Analyses was a
performance deficiency. The performance deficiency was more than minor, and
therefore a finding, because if left uncorrected the failure to perform extent of
condition reviews could lead to a more significant safety concern. Specifically,
the failure to identify and address additional conditions adverse to quality in the
extent of condition review has the potential to lead to a failure to recognize
degraded equipment in a timely manner. This finding was associated with the
Mitigating Systems Cornerstone. Using Inspection Manual Chapter 0609,
Appendix G, Shutdown Operations Significance Determination Process,
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, dated
May 25, 2004, the team determined that this finding was of very low safety
significance (Green) because the finding did not require a quantitative risk
assessment because adequate mitigating equipment remained available. The
- 14 -
team determined this finding had a cross-cutting aspect in the area of problem
identification and resolution because the licensee failed to thoroughly evaluate
problems such that the resolutions address the causes P.1(c)(Section 4OA4).
Other Findings
- Severity Level IV. The team identified a non-cited violation of 10 CFR 50.59,
Changes, Tests, and Experiments, associated with the licensees failure to
adequately evaluate Modification EC 33464, Replace AK-50 480 V Main and
Bus-Tie Breakers With Molded Case Type or Equivalent, to determine if it
required prior NRC approval. Specifically, the licensees documented evaluation
failed to identify and evaluate new creditable failure modes to determine whether
they would have an adverse effect on the 480 Vac electrical distribution system.
The licensees corrective action was to revise the evaluation. This issue was
entered into the licensees corrective action program as CR 2013-04474 and
2013-16954.
The licensees failure to implement the requirements of 10 CFR 50.59 and
adequately evaluate changes associated with the electrical distribution system is
a performance deficiency. Because this performance deficiency had the
potential to impact the NRCs ability to perform its regulatory function, the team
evaluated the performance deficiency using traditional enforcement. In
accordance with Section 2.1.3.E.6 of the NRC Enforcement Manual, the team
evaluated this finding using the significance determination process to assess its
significance. Using Inspection Manual Chapter 0609, Appendix A, The
Significance Determination Process for Findings At-Power, the finding is
determined to have very low safety significance (Green) because it: (1) was not
a deficiency affecting the design or qualification of a mitigating structure, system,
or component, and did not result in a loss of operability or functionality; (2) did
not represent a loss of system and/or function; (3) did not represent an actual
loss of function of at least a single train for longer than its Technical Specification
allowed outage time, or two separate safety systems out-of-service for longer
than their Technical Specification allowed outage time; (4) did not represent an
actual loss of function of one or more non-Technical Specification trains of
equipment designated as high safety-significance in accordance with the
licensees maintenance rule program; and (5) did not involve the loss or
degradation of equipment or function specifically designed to mitigate a seismic,
flooding, or severe weather event. Therefore, in accordance with Section 6.1.d.2
of the NRC Enforcement Policy, the team characterized this performance
deficiency as a Severity Level IV violation. The team determined that a cross-
cutting aspect was not applicable to this performance deficiency because the
failure to adequately evaluate changes in accordance with 10 CFR 50.59 was
strictly associated with a traditional enforcement violation (Section 4OA4).
- Severity Level IV. The team identified three examples of a Severity Level IV
non-cited violation of 10 CFR 50.73, Immediate Notification Requirements for
Operating Nuclear Power Reactors, associated with the licensees failure to
submit a Licensee Event Report within 60 days following a discovery of an event
- 15 -
meeting the reportability criteria as specified. The licensees corrective actions
were to submit the licensee event reports. The licensee entered this deficiency
into their corrective action program for resolution as CRs 2013-12863 and
2012-03796.
The team determined that the failure to make a required Licensee Event Report
is a violation of 10 CFR 50.73. The violation was evaluated using Section 2.2.4
of the NRC Enforcement Policy because the failure to submit a required licensee
event report may impact the ability of the NRC to perform its regulatory oversight
function. As a result, this violation was evaluated using traditional enforcement.
In accordance with Section 6.9 of the NRC Enforcement Policy, this violation was
determined to be a Severity Level IV non-cited violation. The team determined
that a cross-cutting aspect was not applicable to this performance deficiency
because the failure to make a required report was strictly associated with a
traditional enforcement violation (Section 4OA4).
- Severity Level IV. The team identified a cited Severity Level IV violation of
10 CFR 50.9, Complete and Accurate Information, and an associated reactor
oversight program finding (NCV 05000285/2013013-19, Failure to Translate
Appendix R License Exemptions into the Plants Fire Protection Program
Design), for the licensees failure to provide information to the Commission that
was complete and accurate in all material respects. Specifically, when
responding to a request for additional information, the licensee supplied incorrect
information to the NRC and this information was subsequently used by the NRC
to support a license amendment for the station. This issue was entered into the
stations corrective action program as CR 2013-15021.
The failure to provide the NRC with complete and accurate information when
responding to a request for additional information is a performance deficiency.
Using Inspection Manual Chapter 0612, Appendix B, Issue Screening, Figure 1,
dated September 7, 2012, the team determined that the failure to provide
complete and accurate information was a performance deficiency that required
evaluation under both traditional enforcement and the reactor oversight program.
The performance deficiency was determined to be more than minor because:
(1) the information was considered material to the NRCs decision making
process; and (2) it affected the equipment performance attribute of the Mitigating
Systems Cornerstone with regard to availability, reliability, and capability of the
raw water pumps to perform their safety function during a fire in the intake
structure. Using Inspection Manual Chapter 0609, Appendix F, Fire Protection
Significance Determination Process, the team determined the finding to have
very low safety significance (Green) because it only affected the ability to reach
and maintain cold shutdown conditions. Under the traditional enforcement
review, the team determined that in accordance with Section 6.9.c.1 of the NRC
Enforcement Policy, this finding represented a Severity Level III violation.
Specifically, the team determined that if this information had been completely and
accurately provided, it would likely have caused the NRC to undertake a
substantial further inquiry. The NRC takes the issue of complete and accurate
- 16 -
license submittals very seriously. For this reason, the NRC considered citing this
as a Severity Level III violation, as discussed in the Enforcement Policy, as the
NRC had approved a licensing action based on the incorrect information.
However, after consideration by NRC management, and with the approval of the
Director of the Office of Enforcement, it was determined that a Severity Level IV,
cited violation was appropriate. This decision was based on the very low safety
significance (Green) of the associated reactor oversight program finding
(05000285/2013013-19). There was no cross-cutting aspect assigned to this
finding because the inaccurate information was provided over three years ago
and this issue does not reflect present licensee performance (Section 4OA4).
B. Licensee-Identified Violations
None.
- 17 -
REPORT DETAILS
4. OTHER ACTIVITIES
4OA4 IMC 0350 Inspection Activities (92702)
The inspection team continued the NRC Inspection Manual Chapter 0350 inspection
activities, which included follow-up on the Restart Checklist contained in Confirmatory
Action Letter (CAL) EA-13-020 issued February 26, 2013. The purpose of this
inspection was to perform an assessment of the causes of the performance decline at
the Fort Calhoun Station (FCS), to assess whether planned corrective actions are
sufficient to address the root causes and contributing causes and to prevent their
recurrence, and to verify that adequate qualitative or quantitative measures for
determining the effectiveness of the corrective actions are in place. These assessments
were used by the NRC to independently determine if plant personnel, equipment, and
processes were ready to support the safe restart and continued safe operation of the
Fort Calhoun Station.
The team used the criteria described in baseline and supplemental inspection
procedures, various programmatic NRC inspection procedures, and Inspection Manual
Chapter 0350 to assess Omaha Public Power Districts (the licensee) performance and
progress in implementing its performance improvement initiatives. The team 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 7, 2013, through
February 18, 2014. Specific documents reviewed during this inspection are listed in the
attachment.
The following inspection scope, observations and findings, and assessments, are
documented by the Confirmatory Action Letter Restart Checklist (CL) 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 the 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 5.
- 18 -
Item 1.c: Electrical Bus Modification and Maintenance - Red Finding
(1) Inspection Scope
a. The team assessed the licensees actions taken since inspection activities
documented in NRC Inspection Report 05000285/2013008. As documented in
Inspection Report 05000285/2013008, the team reviewed this area for closure and
noted discrepancies which lead to area 1.c being left open. The team reviewed the
licensees actions to address the teams concerns to ascertain whether they were
sufficient to ensure plant safety and support closure of the restart checklist items
associated with the Red finding and notice of violation issued to the licensee on
April 10, 2012.
The team assessed the root cause analyses the licensee developed and included in
its closure book for the Red finding (i.e., Closure Book 1.C): RCA 2011-05414,
Breaker Cubicle 1B4A Fire, Revision 3, dated October 5, 2012, and
RCA 2011-06621, 1B3A Main Breaker Trip During Switchgear Fault on 1B4A,
dated May 3, 2012. The focus of RCA 2011-05414 was identifying the conditions
surrounding the initiation of the fire event that occurred on June 7, 2011, and
determining what created the fire and subsequent loss of 480 Vac, Bus 1B4A. The
purpose of RCA 2011-06621 was to determine why an adequate level of separation
between two trains of 480 Vac power was not maintained during the fire event;
however, the purpose statement was redefined several times throughout the
document.
The teams assessment was based on the following objectives:
- Provide assurance that the root and contributing causes of risk-significant
issues were understood
- Provide assurance that the extent-of-condition and extent-of-cause of risk-
significant issues were identified
- Provide assurance that the licensee's corrective actions for risk-significant
performance issues were, or will be, sufficient to address the root and
contributing causes and to preclude repetition
b. Open items (Licensee Event Reports and Violations), specifically related to the Red
finding were reviewed by the team. The team verified the adequacy of the licensees
causal analysis and extent of condition evaluations related to and associated with the
Red finding. In addition, the team verified that adequate corrective actions were
identified and associated with the licensees root and contributing causes and extent
of condition evaluations, and that these corrective actions are either implemented or
appropriately scheduled for implementation.
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(2) Observations and Findings
a. Licensees Assessment of the Red finding
Determine that the problem was evaluated using a systematic methodology to
identify the root and contributing causes.
The team determined that the licensee had evaluated the issue using systematic
methodologies to identify root and contributing causes. Specifically, Root Cause
Analysis (RCA) 2011-06621, Revision 2, stated that the analytical methods used
during the investigation included events and causal factors charting and fault tree
analysis. A fault tree was created for the event in an attempt to identify all possible
means by which load center 1B3A main feeder breaker could have opened
inappropriately given the circumstances. The root cause analysis stated that the
fault tree analysis was essentially a failure modes and effects analysis which
identified: (1) human performance; (2) programmatic; and (3) oversight factors which
were considered to finally arrive at the root cause. The root cause analysis
contained the fault tree analysis created for this investigation.
RCA 2011-06621, Revision 2, documented the following root and contributing
causes of inadequate separation of safety-related equipment:
- Root Cause-1 (8.1): Deleted - see contributing cause-4 (8.6).
- Root Cause-2 (8.2): Design Change Package preparation procedures do not
provide guidance to evaluate design features of new components in regard to
the possibility that they may have adversely affected required performance
characteristics if not properly configured.
- Contributing Cause-1 (8.3): Detailed standards for performing and
documenting wire/continuity checks for new wiring do not exist. It is left to the
test and field engineer to judge the level of detail required.
- Contributing Cause-2 (8.4): The design engineer did not properly employ the
human performance toolbox in regard to maintaining a questioning attitude
about the details of operation of new breakers.
- Contributing Cause-3 (8.5): The field engineer and electricians did not
properly employ the human performance toolbox in that they did not question
the lack of detail in the Construction Work Order for performing wire and
continuity checks.
- Contributing Cause-4 (8.6): The vendor manual for the Masterpact breakers
does not clearly state how the Zone Select Interlock, if not properly
restrained, will impact breaker coordination. The vendor was unaware of the
effect of the Full Function Test Kit on the Zone Select Interlock functionality.
This knowledge gap resulted in a failure to specify a functional test that would
ensure proper breaker performance. The knowledge gap is also being
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investigated by the vendor. (Refer to NLI NCR number 410. Note: Any root
or contributing cause associated with vendor actions will be addressed by the
vendors corrective action program and not by OPPDs program.)
The team determined that in RCA 2011-06621, Revision 2, the licensee had
adequately used systematic methodologies to identify the root and contributing
causes for the failure to maintain separation between two trains of 480 Vac power
during the fire event. The team noted that the licensee had deleted Root
Cause 1 (8.1) and made it part of Contributing Cause 4 (8.6). This addresses the
concerns identified by NRC Inspection Reports 05000285/2012004 and
05000285/2013008 with respect to Root Cause 1 (8.1).
Determine that the root cause evaluation address the extent of condition and the
extent of cause of the problem.
RCA 2011-06621 defined the condition as the failure to properly disable the Zone
Select Interlock breaker feature which resulted in a loss of expected coordination
between adjacent 480 Vac breakers. During the June 7, 2011, fire event, the failure
to restrain the Zone Select Interlock was caused by a wiring error, which occurred
during installation of the restraining jumpers. The licensee identified other conditions
that could cause the Zone Select Interlock not to be adequately restrained, including
snap-in connectors not firmly mounted and popping out during breaker racking and a
damaged mounting-bracket linkage arm that could cause incomplete circuits at the
input of the breaker. The licensee determined that the extent of condition was the
possibility that any or all these failure modes could exist on any of the twelve
Masterpact NW breakers installed in the 480 Vac switchgear. The Zone Select
Interlock wires were checked at all twelve breakers and cradles. In the course of the
root cause analysis, other adverse breaker conditions were identified and checked.
Closure Book 1.c stated that the licensee has verified the correct placement and
continuity of the other Zone Select Interlocks jumpers in the station and was verifying
breaker overcurrent coordination through primary injection testing without using a
Full Function Test Kit. The licensee implemented new guidance for testing control
wiring that is applicable to all modified and maintained electrical circuits. This was
accomplished in condition report action items 2011-06621-28 and 2011-06621-32.
The team determined that the licensee had failed to promptly identify and correct a
condition adverse to quality. Specifically, the team reviewed the licensees corrective
actions and determined that action item 2011-06621-32 had not been performed, but
had been identified as complete and was closed due to an administrative error. The
team identified this performance deficiency as, NCV 05000285/2013013-01, Failure
to Complete all Testing for a Condition Adverse to Quality, which is further
discussed in Section 5 of this report.
RCA 2011-06621, Revision 2, identified the root cause as the lack of specific
direction in the Design Change Package preparation procedure to require the design
engineer to consider the impact of design features of new equipment if not properly
disabled. The root cause analysis stated, An extent of cause is other electrical
modifications susceptible to a lack of appropriate consideration of new failure modes
that could exist because new design features are not properly disabled. The closure
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book stated that the root cause has been corrected by revising the appropriate
design procedures for all engineering disciplines to require a comparison of new
features with the original equipment including a consideration of critical parameters
within the design change process. The licensee implemented corrective actions to
review other electrical/I&C modifications from the last five years to determine if
failure modes introduced by features not part of the original equipment could have
been introduced.
Determine that the root cause, extent of condition, and extent of cause evaluations
appropriately considered the safety culture components as described in IMC0310.
The safety culture analysis portion of the root cause analysis failed to identify the
reasons for why some safety culture aspects were not applicable, as required by
station procedure. This information was important for complete understanding of the
circumstances surrounding the event, and to ensure that other root and contributing
causes were not inappropriately ruled out. The form for documenting the safety
culture analysis was not consistent with the instructions in the governing procedure
with respect to documenting the reasons why a safety culture aspect was not
applicable. The form required the licensee to bin the root cause and contributing
causes into the various components, which would not provide an opportunity to
determine if the causal analysis failed to identify other root and contributing causes.
Determine that appropriate corrective actions are specified for each root and
contributing cause.
Corrective action items and schedules for implementing these items were specified
for the root and contributing causes discussed in RCA 2011-06221. Closure
Book 1.c provided a table that outlined which corrective actions correlated to various
causes. The team determined that these corrective actions were adequate to
address those causes.
During their review the team determined that the licensee had failed to provide an
appropriate calculation to establish the basis for testing of safety related breakers.
The team identified this performance deficiency as NCV 05000285/2013013-02,
Failure to Furnish Evidence of an Activity Affecting Quality. The team also
determined that the licensee had performed an inadequate 10 CFR 50.59 evaluation
for modifications performed on safety related breakers. The team identified this
performance deficiency as NCV 05000285/2013013-03, Failure to Evaluate
Changes to Ensure They Did Not Require Prior Approval. These issues are further
discussed in Section 5 of this report.
Determine that a schedule has been established for implementing and completing
the corrective actions.
Corrective action items and schedules for implementing these items were specified
for the root and contributing causes discussed in RCA 2011-06621. Remaining
corrective actions were discussed in the previous sections of this report. The team
did not identify any issues associated with licensees schedule.
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Determine that quantitative and qualitative measures of success have been
developed for determining the effectiveness of the corrective actions to prevent
recurrence.
RCA 2011-06621, Revision 2, does not address the concern identified in NRC
Inspection Report 05000285/2013008. Specifically, because a procedural correction
may not be effective in precluding repetition of events, the licensee should have
established more frequent effectiveness reviews for the procedural corrective
actions. This effectiveness review has acceptable acceptance criteria (i.e., no issues
in form, fit, or function); however, the team determined that the corrective actions
need more run-time and interim effectiveness reviews in accordance with Procedure
FCSG-24-5, Cause Evaluation Manual, Revision 5 before a conclusion can be
made about their effectiveness.
b. Resolution of Open Items Related to the Red Finding
The team reviewed the following open items:
LER 2011010-01 Fire Causes a Circuit Breaker to Open Outside Design
Assumptions
VIO 2012010-01 Failure to Ensure that the 480 VAC Electrical Power Distribution
System Design Requirements were Implemented and Maintained
VIO 2012007-02 Failure to Maintain Command and Control Function During Fire
Fighting Activities in the Protected Area
VIO 2012004-04 Failure to Ensure Breaker Coordination of 480 Vac Electrical
Power Distribution System Was Maintained
The team verified the adequacy of the licensees causal analyses and extent of
condition evaluations. In addition, the team verified that adequate corrective actions
were identified and associated with the licensees root and contributing causes and
extent of condition evaluations, and that, implementation of these corrective actions
are either implemented or appropriately scheduled for implementation.
During this review, the team determined that the licensee had failed to make a
required licensee event report to the NRC. The team identified this performance
deficiency as NCV 05000285/2013013-04, Failure to Submit Licensee Event
Report, which is further discussed in Section 5 of this report.
(3) Assessment Results
a. The team has concluded, based on their reviews of the cause evaluations and the
extent of cause/extent of condition reviews, that this area was adequately addressed
by the licensee and the following Restart Checklist Items are closed:
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1.c.1 Electrical Fire Red Finding root and contributing cause evaluation
1.c.2 Electrical Fire Red Finding extent-of-condition and cause evaluation
1.c.3 Electrical Fire Red Finding corrective actions addressing root and
contributing causes
1.3.1.1 Rebuild the 1B4A load center
1.3.1.2 Provide documentation for the dedication of the rebuilt load center in
accordance with Contract 163495
1.3.1.3 Complete Engineering Change 53257 and obtain PRC approval to
authorize the use of the rebuilt load center, 1B4A
1.3.1.7 Complete Engineering Change 53517 that details the repair to the
cable jackets for cables located in the cable tray above 1B4A load
center
1.3.1.8 Repair or replace the cables located in the cable tray above load
center 1B4A that have had jacket damage
1.3.1.10 Calibration of the internal relays and protection equipment for
Bus 1B4A
1.3.1.12 Calibrate new Square D circuit breakers
1.3.1.17 Perform testing of all circuits associated with 1B4A load center
1.3.1.19 Submit, track, and seek approval of procedures that are changed as
the result of EC 53257 and are required to be issued before the
System Acceptance Process.
1.3.1.21 Declare Bus 1B4A Operable
1.3.1.23 Extent-of-condition repair requirements. Provide repair requirements
for extent-of-condition.
1.3.1.24 Implement the requirements supplied by System Engineering
regarding the extent-of-condition.
LER 2012010-01 Fire Causes a Circuit Breaker to Open Outside Design
Assumptions
VIO 2012010-01 Failure to Ensure that the 480 Vac Electrical Power Distribution
System Design Requirements were Implemented and Maintained
VIO 2012007-02 Failure to Maintain Command and Control Function During Fire
Fighting Activities in the Protected Area
VIO 2012004-04 Failure to Ensure Breaker Coordination of 480 Vac Electrical
Power Distribution System Was Maintained
- 24 -
Item 1.g: Safety System Functional Failures White Performance Indicator
(1) Inspection Scope
The team reviewed the licensees programmatic evaluation associated with safety
system functional failures, as well as the cause evaluations associated with the
individual licensee event reports identified in Area 1.g of Restart Checklist Basis
Document, Revision 4. The purpose of these reviews was to independently verify
that the licensee had performed adequate casual analyses and extent of condition
evaluations related to these issues. In addition, the team verified that adequate
corrective actions were identified and associated with the causes and extent of
condition evaluations, and that, implementation of these corrective actions were
either implemented or appropriately scheduled for implementation.
(2) Observations and Findings
Determine that the problem was evaluated using a systematic methodology to
identify the root and contributing causes.
The team determined that the licensee evaluated the condition using systematic
methodologies and problem analysis techniques to identify the root and contributing
causes. The licensee used the following systematic methods to complete the root
cause analysis: (1) event and causal factors charting to allow complex issues to be
organized to clearly identify the structure of the event and its cause; and (2) common
factors analysis to understand the major common issues that factored into the
Mitigating Systems Performance Indicator (MSPI) degradation.
The team concluded that the use of the techniques provided an adequate
methodology for evaluating the problem.
Determine that the root cause evaluation was conducted to a level of detail
commensurate with the significance of the problem.
The team determined that the root cause evaluation was appropriately conducted to
a level of detail commensurate with a Significance Level 1 event or condition - An
event or condition that is a Significant Condition Adverse to Quality that has major
potential or actual impact. The event presents significant risk or consequences to
the safe, reliable operation of the plant, personnel safety, or organizational and
human behaviors, such that, recurrence is unacceptable - in accordance with
Licensee Procedure FCSG-24-3, Condition Report Screening, Revision 7.
Determine that the root cause evaluation included a consideration of prior
occurrences of the problem and knowledge of prior operating experience.
The team determined that the root cause evaluation included a consideration of prior
occurrences of the problem and knowledge of prior operating experience, as
required, by Station Procedure FCSG-24-4, Condition Report and Cause
Evaluation, Revision 7.
- 25 -
Determine that the root cause evaluation addressed the extent of condition and the
extent of cause of the problem.
The team determined the evaluation of the extent of condition was not complete.
RCA 2013-03424 determined the bounding condition as:
MSPI Safety System Functional Failure indicator degrading trend (increase in
LER submittals due to Safety System Functional Failures as a result of
discovering latent design basis/configuration control issues).
The root cause concluded that an extent of condition exists, and that, this condition
has been repeatedly identified as design/configuration control anomalies. The root
cause also concluded that any processes which rely upon clear and accurate design
basis could be impacted by latent undiscovered design anomalies.
The root cause acknowledged that the condition could extend to other processes and
programs, such as, fuel loading analysis, surveillance testing, preventative
maintenance, and equipment qualification; however, it did not determine to what
extent the actual processes and programs were affected. This is contrary to Station
Procedure FCSG-24-4, Attachment 1, Section F, Extent of Condition,
Paragraph 1.2, which states, in part, The extent to which the actual condition of the
Problem Statement exists in other applicable plant processes, systems, equipment,
or human performance related activities (programs) SHALL be determined.
In interviews with licensee personnel, the team was told that the extent of condition
review was scheduled for a later date because the depth of review would be large
and corrective actions in CRs 2012-08134 and 2012-02857 would address some of
the programs already mentioned. Delaying the extent of condition review is allowed
by Station Procedure FCSG-24-5, Cause Evaluation Manual, when the investigator
and condition report owner may exercise conservative judgment to determine how
deep to pursue the extent of condition. However, if the full scope or impact is to be
determined later, then the corrective action plan must include one or more supporting
actions to do so. Corrective actions to perform the full extent of condition were not
included in RCA 2013-03424.
The team determined the evaluation of the extent of cause to be inadequate.
RCA 2013-0324 determined the failure, to maintain an environment, in the
Engineering Division, that valued maintaining the license and design basis of the
station over continued operation of the facility, to be the root cause of the declining
performance indicator. The root cause also established that the potential existed for
this cause to further impact other processes within Engineering (e.g. that an extent of
cause existed). It did not, however, determine what the extent of cause was, and
thus, could not assure that corrective actions would be broad enough to prevent
repetition (e.g. another safety system functional failure related to the extent of root
cause elsewhere in Engineering or outside of Engineering).
Specifically, the licensee determined the declining performance indicator to be a
significant condition adverse to quality (SCAQ), and that, the potential existed both:
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(a) for its root cause to impact other processes; and (b) for that cause which
triggered behaviors associated with the condition to trigger similar behaviors in other
processes (e.g. failure to maintain an environment in other divisions that valued
maintaining the license and design basis of the station over continued operation of
the facility), but did not determine the actual extent of cause (e.g. in which divisions
this cause could repeat and result in or contribute to White Performance Indicator
repetition). Instead, the RCA established future tasking actions to determine the
extent of cause corrective actions intended to prevent repetition without knowing the
actual extent of cause.
The team reviewed the RCA established future tasking actions, intended to
determine extent of cause, to determine if they could be relied upon to assure
revision to RCA 2013-03424 corrective actions to prevent repetition (CAPRs). The
team determined that the actions tasked against RCA 2013-05570 could not be
relied upon for at least three reasons. First, the tasking was not directed to any
specific element. Secondly, the teams review of RCA 2013-05570 found that it
lacked any meaningful linkage back to RCA 2013-03424 to assure that it would
provide the specific extent-of-cause information being sought. Finally, the team
determined that RCA 2013-05570 was itself, inadequate. As discussed further
below, this lack of meaningful linkage also placed at risk the bulk of
RCA 2013-03424 corrective actions which, like the extent of cause tasking, were
assigned to RCA 2013-05570.
The team informed the licensee of these concerns, and the licensee initiated
CR 2013-14584 to capture this issue in the station corrective action program. The
licensee revised RCA 2013-03424 to address the issues identified by the team.
In the revised root cause analysis the licensee determined that the identified root
cause extended beyond the engineering organization, and had been repeatedly
identified as design basis/configuration issues, but actions taken by management to
address the dormant nature of the existing design basis issues had limited
effectiveness. To address the identified extent of cause the licensee developed
corrective actions specified in CR 2013-03424, and linked corrective actions from
CR 2013-05570 to CR 2013-03424 in the corrective action program. The team
determined that these actions were adequate to identify the extent of cause, and to
implement corrective actions to address the extent of cause.
Determine that the root cause, extent of condition, and extent of cause evaluations
appropriately considered the safety culture components as described in Inspection
Manual Chapter 0310.
The team determined that the root cause evaluations appropriately considered the
safety culture components as described in Inspection Manual Chapter 0310. The
licensee reviewed each safety culture component and determined if the condition
was applicable. Station Procedure FCSG-24-4, Condition Report and Cause
Evaluation, Revision 7, Section L, Paragraph 1.3, states, For Safety Culture
Aspects that are found to be applicable, reference the root and contributing causes
- 27 -
and the specific corrective actions that address that aspect issue. The team
determined that the actions were appropriate.
Determine that appropriate corrective actions are specified for each root and
contributing cause.
Revision 0 of RCA 2013-03424 originally identified the root cause as, Fort Calhoun
Station engineering management failed to maintain control over the design and
configuration of the Fort Calhoun Station. The corrective action to prevent
recurrence in Revision 0 of RCA 2013-03424 was documented as:
Identify and define the Licensing bases and assure licensing bases
documentation remains current, accurate, complete, and retrievable.
- Identification includes determining the record types.
- Identify a consistent numbering system.
- Establish methodology (database) for ensuring current and historical
licensing bases records are readily retrievable.
- Reconstitute (identify, locate, and store in a retrievable method) the
licensing bases including historical records required to establish the
current bases.
- If conflicts are identified during identification and location of licensing
bases documentation, a Condition Report is initiated to document and
track the resolution.
- Establish process for assuring licensing bases documentation remains
current, accurate, complete, and retrievable. Current processes may be
retained or revised to assure needed results.
- Closure determination: Conduct an outside independent assessment to
validate the completion of identifying all license bases documents are
retrievable, and that, the process for updates is implemented.
The team determined that the corrective action to prevent recurrence for the root
cause specified in Revision 0 of RCA 2013-03424 was not appropriate and would not
prevent recurrence of the root cause. The team determined that the root cause was
narrowly focused on the management of the engineering division and failed to
identify a culture in the engineering division, as a whole, that failed to maintain the
design and configuration control. This condition was captured in CR 2013-12236.
The team identified this performance deficiency as NCV 05000285/2013013-05,
Inadequate Corrective Actions to Prevent Repetition of A Significant Condition
Adverse to Quality, a White MSPI SSFF Degrading Trend, which is further
discussed in Section 5 of this report.
- 28 -
The licensee revised RCA 2013-03424 to include a new root cause and an additional
corrective action. Revision 1 of RCA 2013-03424 revised the root cause to, Fort
Calhoun Station failed to maintain an environment, in the Engineering Division, that
valued maintaining the license and design basis of the station over continued
operation of the facility. This led to a loss of control over the design and
configuration of the Fort Calhoun Station. An additional corrective action to prevent
recurrence was included to strengthen the function of the oversight group that
performs reviews of engineering products.
The team determined that these corrective actions were adequate to address the the
identified causes.
Determine that a schedule has been established for implementing and completing
the corrective actions.
The team determined that a schedule had been established for implementing and
completing the corrective actions. However, the due dates for corrective actions to
preclude repetition were not explicitly documented in the corrective action matrix of
RCA 2013-03424. Rather, the reader is referred to RCA 2015-05570.
Determine that quantitative or qualitative measures of success have been developed
for determining the effectiveness of the corrective actions to prevent recurrence.
Similar to observations above, in which RCA 2013-3424 leveraged RCA 2013-05570
extensively, it also leverage the effectiveness review of that RCAs corrective actions
to prevent recurrence of that RCAs root cause. However, because the root causes
of RCA 2013-05570 differed substantively from the root cause in RCA 2013-03424,
the team determined that the RCA 2013-05570 effectiveness review did not
constitute an appropriate measure of success of the corrective actions to prevent
recurrence of the RCA 2013-03424 root cause and its extent of cause.
Following revision of RCA 2013-03424 the licensee incorporated adequate
effectiveness reviews into this root cause, as well as linking corrective actions from
RCA 2013-05570. Specifically, the team noted that RCA 2013-05570 had
effectiveness reviews associated with the corrective actions, and by linking the
corrective actions from 2013-05570 to 2013-03424 in the corrective action program
any identified weaknesses with corrective actions in 2013-05570 would trigger a
review under 2013-03424 as well. The team determined this to be adequate.
(3) Assessment Results
The team has concluded, based on their reviews of the cause evaluations and the
extent of cause/extent of condition reviews, that this area was adequately addressed
by the licensee. Restart Checklist Item 1.g is closed.
- 29 -
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 and safety
significant structures, systems, and components at the Fort Calhoun Station are in
appropriate condition to support safe restart and continued safe plant operation.
Item 2.c: Qualification of Containment Electrical Penetrations
(1) Inspection Scope
a. The team reviewed the adequacy of the licensees actions associated with the
presence of Teflon used in a number of containment electrical penetration
feedthrough assemblies. Specifically, the team assessed Condition Report
CR 2012-1947, for which the Description section stated, in part,
Test data and analytical techniques demonstrate that FCS feedthrough
subassemblies used at FCS containing conductors with Teflon insulation and
Teflon seals are susceptible to significant degradation from a postulated Design
Basis Event environment.
The teams assessment of the licensees effectiveness in addressing the deficiency
was based on the following criteria:
- Provide assurance that the root and contributing causes of risk-significant
issues were understood;
- Provide assurance that the extent-of-condition and extent-of-cause of risk-
significant issues were identified;
- Provide assurance that the licensee's corrective actions for risk-significant
performance issues were, or will be, sufficient to address the root and
contributing causes and to preclude repetition
b. An open item (Licensee Event Report) specifically related to the containment
electrical penetration issue was reviewed by the team. The team verified the
adequacy of the licensees causal analysis and extent of condition evaluation. In
addition, the team verified that adequate corrective actions were identified and
associated with the licensees root and contributing causes and extent of condition
evaluations, and that, implementation of these corrective actions are either
implemented or appropriately scheduled for implementation.
- 30 -
(2) Observations and Findings
a. Licensees Assessment of the Containment Penetration Issue
Determine that the problem was evaluated using a systematic methodology to
identify the root and contributing causes.
The licensee performed a root cause analysis associated with CR 2012-01947 for
the condition. The team noted, at the time of the inspection that the licensee had
revised the original version of the root cause analysis and the version the team
reviewed, was Revision 2, dated July 8, 2013.
The team determined that the licensee evaluated the problem using three systematic
methodologies and problem analysis techniques to identify the root and contributing
causes. The licensee used the following systematic methods to complete the root
cause analysis report: (1) Event and Causal Factors Chart; (2) Barrier Analysis; and
(3) Streaming Analysis.
The licensee developed an Event and Causal Factor Chart using historical events to
graphically display the timeline of events and factors associated with the events.
The licensee then evaluated those events to identify the barriers that could have
prevented the condition. From this, the licensee derived the causal factors and
performed a streaming analysis on the causal factors to determine which factors
were the more fundamental causes that drive the others. Then, the licensee
conducted a qualitative evaluation of each causal factor to identify causal factors
related to the root cause. The team concluded that the use of these techniques
provided an adequate analysis for evaluating the problem.
Determine that the root cause evaluation was conducted to a level of detail
commensurate with the significance of the problem.
The team determined that the licensee conducted the root cause analysis to a level
of detail commensurate with the significance of the problem. The presence of Teflon
in containment penetrations represented a potential significant degradation of the
containment under accident conditions. The licensee appropriately treated this
deficiency as a high level condition in the corrective action process. The licensee
identified the following root cause for the condition:
There was a lack of technical oversight to ensure the information associated with
Teflon material used in EQ Containment electrical penetration subassemblies
was applied to non-EQ electrical penetrations.
The team considered the identification of this root cause to have been done with an
appropriate level of inquiry and depth. The licensee employed their root cause
analysis methodology as called for in Procedures NOD-QP-19, Cause Analysis
Program, and FCSG-24-5, Cause Evaluation Manual.
- 31 -
Determine that the root cause evaluation included a consideration of prior
occurrences of the problem and knowledge of prior operating experience.
The team determined that the RCA included a consideration of prior occurrences of
the problem and knowledge of prior operating experience. The licensee identified
occurrences and operating experience of the problem as a part of their evaluations.
The licensees search concluded that information was available in the late 1960s
that Teflon was not resistant to high radiation levels in reports from Oak Ridge
National Laboratory and the Western New York Nuclear Research Center.
The licensees review of external operating experience identified cases where the
Fort Calhoun Station missed opportunities to use operating experience effectively.
The licensee identified that few plants used Teflon seals and insulation for
containment electrical penetrations, which could have been a missed opportunity to
question their practice. The team noted that the licensee did capture this missed
opportunity in their corrective action program.
The licensee learned that containment electrical feedthrough subassemblies with a
multi-conductor design containing Teflon seals and insulation were only supplied to
the Fort Calhoun Station in the United States. In addition, subassemblies with
coaxial or triaxial cables with Teflon jackets were only supplied to Salem, Crystal
River, and the Fort Calhoun Station. The seals and electrical conductor insulation
were made from environmentally qualified material. Based on these reviews, the
team concluded the root cause analysis had adequately reviewed operating
experience.
Determine that the root cause evaluation addressed the extent of condition and the
extent of cause of the problem.
The team observed that the licensee did, separately and adequately, address both
extent of cause and extent of condition. For extent of condition, the licensee
considered the extent of condition to be the extent to which the actual condition
exists with similar plant processes, equipment, or human performance. Using this,
the licensee evaluated the extent of condition (1) the containment personnel air lock
electrical penetration subassemblies, which contained Teflon seals and wiring
insulation, (2) containment personnel air lock mechanical components, which
contained Teflon, and (3) mechanical equipment located in a harsh environment that
contained Teflon and performed a containment integrity function. The team
confirmed that corrective actions had been generated for these extents of condition
and that the actions supported plant safety and restart.
The team also observed that the licensee screened extent of cause to be the extent
to which the root cause of an identified problem exists (or may potentially exist) in
other plant processes, systems, equipment or human performance related activities.
The extent of cause for the root cause was determined to exist in several plant
processes, systems, equipment, and human performance related activities. The
licensee addressed these in other root cause analyses performed for their
performance improvement efforts. These included RCA 2012-08137, "Regulatory
- 32 -
Processes and Infrastructure," RCA 2012-09494, "Deficiencies in Identifying
Degraded/Nonconforming Conditions and Performance of Operability
Determinations," RCA 2012-08132, "Site Operational Focus," and RCA 2013-02857,
"HELB/EEQ not in accordance with 10 CFR 50.49."
Determine that the root cause, extent of condition, and extent of cause evaluations
appropriately considered the safety culture components as described in IMC 0310.
The team determined that the root cause, extent of condition, and extent of cause
evaluations appropriately considered the safety culture components as described in
Inspection Manual Chapter 0310. The licensee reviewed each safety culture
component and determined if the condition was applicable so that they could link the
component to a root or contributing cause.
The safety culture review was aimed at identifying issues with cross-cutting
tendencies that warrant enhanced corrective actions to address. Five safety culture
aspects were found to be applicable to this root cause. These five cross-cutting
aspects were:
- H.1(b) - conservative decision making
- H.2(a) - availability of resources to maintain design margins and minimize
long standing issues
- P.1(c) - addressing extent of condition when resolving problems
- P.2(b) - use of operating experience
- O.1(b) - management reinforcing standards and behaviors
The team reviewed that the licensees assignment of safety culture aspects and
confirmed that the applicable aspects had been addressed by corrective actions.
Determine that appropriate corrective actions are specified for each root and
contributing cause.
The team determined that the licensee specified appropriate corrective actions for
the root cause. The licensee specified three corrective actions designated to prevent
recurrence. These included integrating leaders having external perspectives and
broad experience based insights from external organizations, revising and
implementing human performance procedures utilizing best industry practices, and
improving the station issue prioritization procedures and processes. Other actions
included training on human performance, incorporating current industry best decision
making practices, developing and implementing a plan to increase the depth of plant
equipment and systems knowledge for engineering personnel, and developing and
implementing a plan to increase the depth of licensing and design basis knowledge
for engineering personnel. To correct the issue the licensee replaced or capped
containment electrical penetrations that used Teflon as electrical insulation or sealant
prior to plant startup.
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Determine that a schedule has been established for implementing and completing
the corrective actions.
The team determined that the Fort Calhoun Station established a schedule for
implementing and completing corrective actions. The team noted that
CR 2012-01947 and 2010-02387 contained a long list of corrective actions identified
to resolve the issue. The team sampled the items to assure that the more risk
significant issues were given higher priority. The team concluded that the schedule
of corrective actions was adequate.
Determine that quantitative or qualitative measures of success have been developed
for determining the effectiveness of the corrective actions to prevent recurrence.
The team determined that the Fort Calhoun Station developed quantitative and
qualitative measures of success for determining the effectiveness of the corrective
actions to prevent recurrence. These effectiveness reviews were broken down into
separate actions in the corrective actions for the root cause analysis. Each of these
corrective actions contained detailed means to ascertain the effectiveness measures.
b. The team reviewed the licensees causal analyses, corrective actions, and extent of
condition associated with Licensee Event Report 2012-002, Inadequate
Qualifications for Containment Penetrations Renders Containment Inoperable. In
addition, the team verified that adequate corrective actions were identified
associated with the causes and extent of condition evaluations and that
implementation of these corrective actions were either implemented or appropriately
scheduled for implementation.
(3) Assessment Results
a. The team concluded, based on their reviews of the cause evaluations and the extent
of cause/extent of condition reviews, that this area has been adequately addressed
by the licensee. The following restart checklist items for Area 2.c are closed:
2.c.1 Containment electrical penetrations root and contributing cause
evaluation
2.c.2 Containment electrical penetrations extent-of-condition and cause
evaluation
2.c.3 Containment electrical penetrations corrective actions
b. Licensee Event Report 2012-002, Inadequate Qualifications for Containment
Penetrations Renders Containment Inoperable, will be closed.
3. Adequacy of Significant Programs and Processes
Section 3 of the Restart Checklist addresses major programs and processes in place at
the Fort Calhoun Station.
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Item 3.a: Corrective Action Program
(1) Inspection Scope
An open item (Licensee Event Report), specifically related to component cooling
water pump operations was reviewed by the team. The team verified the adequacy
of the licensees causal analysis and extent of condition evaluation. In addition, the
team verified that adequate corrective actions were identified associated with the
licensees root and contributing causes and extent of condition evaluations, and that,
implementation of these corrective actions are either implemented or appropriately
scheduled for implementation.
(2) Observations and Findings
The team reviewed Licensee Event Report 2012-006, Operation of Component
Cooling Pumps Outside of the Manufacturers Recommendation, dated
June 25, 2012. During this review, the team noted that during additional
investigations conducted by the licensee, it had been determined that the flow
instrumentation used during the testing was inaccurate and this caused invalid data
to be used when assessing pump performance. Based on this, the licensee
determined that the pumps had been operated as designed and not outside of
manufacturers recommendations. The licensee retracted LER 2012-006 via letter
LIC-12-182, Withdrawal of Licensee Event Report 2012-006, Revision 0, for the Fort
Calhoun Station, dated December 12, 2012.
(3) Assessment Results
The team reviewed the licensees testing data as well as the subsequent
investigation data and determined that the licensees conclusion to retract Licensee
Event Report 2012-006, Operation of Component Cooling Pumps Outside of the
Manufacturers Recommendation, was appropriate.
This restart checklist item is closed.
Item 3.b: Equipment Design Qualifications
(1) Inspection Scope
a. Open items specifically related to maintaining systems, structures, and components
within their licensing and design basis were reviewed by the team. Specifically, the
team reviewed Restart Checklist Item 4.6.1.3 to assess the licensees actions related
to deficiencies that had been identified in the steam generator accident ring
analyses. The inspection verified that the licensee resolved the deficiencies in the
structural calculations by including the potential accident loads on major
subcomponents of the steam generators. The team also reviewed an independent
sample of other reactor coolant system structural calculations.
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The team verified that the licensee performed adequate causal and extent of
condition evaluations and that corrective actions are either implemented or
appropriately scheduled for implementation.
b. Open items (Licensee Event Reports) related to pump mechanical seals and
unanalyzed welds in the reactor coolant system were reviewed by the team. The
team verified the adequacy of the licensees causal analyses and extent of condition
evaluations. In addition, the team verified that adequate corrective actions were
identified associated with the licensees root and contributing causes and extent of
condition evaluations, and that, implementation of these corrective actions are either
implemented or appropriately scheduled for implementation.
(2) Observations and Findings
a. CAL Action Item 4.6.1.3 (Provide analysis of Steam Generator accident ring)
The teams review of the selected calculations identified several significant errors
with the calculations and inadequate extent of condition reviews. The apparent
cause analysis report generated for Action Item 4.6.1.3 was narrowly focused. The
licensee failed to analyze significant loads for a large component on the steam
generator. The licensees apparent cause stated, Intimate knowledge of the effort
led to complacency during the review, and the omission was not identified. The
report focused on communication issues that occurred between various vendors,
suppliers, and the licensee. Despite the fact that structural supports were removed
during the steam generator replacement project, and loads were increased, a major
structural component was not analyzed for design loads. Further, the extent of
condition review determined there were no other errors or omissions in all
calculations supporting the replacement steam generator design report. During the
NRC inspection the team uncovered a number of errors that were not identified by
the licensees reviews.
The team noted that details in the calculations were challenging to follow. The
licensee did not originate the calculations; an outside contractor prepared them. The
licensees staff was unable to effectively discuss the calculations with the team
involving the calculation methodology, license basis requirements, and conclusions,
without the vendor who originated them.
The team determined that the licensee had failed to provide adequate oversight over
the contractors preparation of the replacement steam generator calculation because
the vendor utilized several inputs in the analyses that were not in conformance with
the stations licensing basis. Further, the team found an example in the reactor
coolant system structural calculations where the licensee had derived allowable
stresses from vendor manuals, but did not actually possess the vendor manual. The
licensee generated CRs 2013-14540 and 2013-14741 in response to this concern,
and ultimately procured the vendor manual. The overarching issue of vendor
manuals and vendor oversight was previously discussed in NRC Inspection
Report 05000285/2013-008 (Accession No. ML13197A261), and was on the Restart
Checklist as Item 3.d.1.
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The team noted that the engineering staff continues to demonstrate gaps in their
knowledge and understanding of the stations design basis with respect to load
combinations. A specific example of this occurred during interviews related to the
structural adequacy of the reactor coolant system. Specifically, the team questioned
why it was acceptable for stress ratios to exceed the code allowable stress limits for
a maximum hypothetical earthquake in conjunction with a maximum accident load
(typically a loss of coolant accident). Station personnel generated CR 2013-14211
and an operability evaluation to address the teams concerns. The inspectors noted
that the licensees basis for the immediate operability determination stated, in part
that, "the stress of the node occurs with a Maximum Hypothetical Earthquake and a
design basis LOCA concurrently this load combination is beyond design basis for
the plant. The team determined that this was contrary to the facility current licensing
basis because this combination is specifically addressed in the Updated Safety
Analysis Report and other design and licensing basis documents. The licensee
agreed that was a design basis load combination and generated CR 2013-19956 to
capture this issue in the stations corrective action program.
The team also determined that the licensee was using a non-conservative procedure
in the design of safety-related structures, systems, and components, and for
evaluating degraded conditions. Specifically, the team noted that criteria from
Station Procedure PED-MEI-17, Interim Operability Criteria, (IOC) was
inappropriately developed and applied to critical quality equipment (CQE) and and
limited critical quality equipment (L-CQE) piping and pipe supports. The team
determined that PED-MEI-17 had been inappropriately used, in some cases, by the
engineering department to bypass evaluating non-conforming components using the
operability process and entering the non-conformances into the corrective action
program for timely resolution. In addition, the team noted that the licensee had made
a commitment to notify the NRC each time they invoked the IOC procedure, but at
some point in the past, the station failed to make required notifications.
During discussions with the licensee, the team was informed that the IOC operability
limits contained in PED-MEI-17 were developed based on another licensees IOC
procedure, and the other licensee had received a safety evaluation report for use of
IOC. The team requested a copy of the other licensees IOC criteria and the safety
evaluation report associated with it.
Subsequently, the team determined that the other licensee did not have a safety
evaluation report for their IOC. Additionally, the team determined that the IOC limits
contained in PED-MEI-17 were significantly less conservative than the other
licensees IOC limits from which they were supposedly based. The other licensees
IOC operability limits mirrored the faulted allowable stresses permitted by ASME
Section III, Appendix F. ASME Section III, Appendix F, is generally endorsed by the
NRC in Inspection Manual Chapter 0326, and by performing a comparison of the
allowable stresses from ASME and PED-MEI-17, the team determined that: (1) the
PED-MEI-17 operability limits were significantly less conservative than the ASME
code allowable limits; (2) PED-MEI-17 did not contain all of the restrictions required
by Appendix F. Therefore, the team determined that the IOC operability criteria was
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non-conservative, and therefore, not suitable for operability determinations and not
appropriate for use in design calculations.
As a result of the teams concerns with the use of IOC the licensee performed a
review of corrective action reports and calculations to identify where the IOC was
applied. In addition, as an immediate corrective action, the station discontinued the
use of the IOC procedure at the station.
The team identified the following deficiencies during their review:
- NCV 05000285/2013013-06, Failure to control deviations from the design
basis requirements for structural calculations related to the reactor coolant
system
- NCV 05000285/2013013-07, Programmatic Failure to Evaluate Safety
Impact of Degraded Conditions during use of Interim Operability Criteria
- NCV 05000285/2013013-08, Failure to Correct Overstressed Components
- NCV 05000285/2013013-09, Non-conservative criteria in operability
procedure
These issues are further discussed in Section 5 of this report.
b. The team reviewed the following open items:
LER 2013-006 Low Pressure Safety Injection and Containment Spray
Pumps Mechanical Seals
LER 2012-016 Unanalyzed Charging System Socket Welds to the Reactor
Coolant System
The team verified the adequacy of the licensees causal analyses and extent of
condition evaluations. In addition, the team verified that adequate corrective actions
were identified associated with the licensees root and contributing causes and
extent of condition evaluations, and that, implementation of these corrective actions
are either implemented or appropriately scheduled for implementation.
(3) Assessment Results
a. The team concluded, based on their reviews of the cause evaluations and the extent
of cause/extent of condition reviews, and corrective actions taken or planned to be
implemented, that the licensee has adequately addressed Restart Checklist Item
4.6.1.3.
Restart Checklist Item 4.6.1.3 is closed.
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b. The team concluded, based on their reviews of the cause evaluations and the extent
of cause/extent of condition reviews, and corrective actions taken or planned to be
implemented, that the licensee has adequately addressed the following LERs:
LER 2013-006 Low Pressure Safety Injection and Containment Spray
Pumps Mechanical Seals
LER 2012-016 Unanalyzed Charging System Socket Welds to the Reactor
Coolant System
With respect to LER 2013-006, Low Pressure Safety Injection and Containment
Spray Pumps Mechanical Seals the licensee identified that the pump mechanical
seals were made of a Teflon material that may not maintain the integrity of the
system under accident conditions. The licensee corrected this deficiency by
replacing the affected mechanical seals with seals qualified for the environmental
conditions they would be subject to under design basis accident conditions.
With respect to LER 2012-016, Unanalyzed Charging System Socket Welds to the
Reactor Coolant System, the licensee identified that the chemical volume and
control system (CVCS) inappropriately used socket welded fittings and the piping
was in an unanalyzed condition involving thermal cycle fatigue. The licensee
corrected these deficiencies by replacing affected piping and completing the thermal
fatigue calculations for all affected piping.
These two LERs and associated Restart Checklist Items are closed.
Item 3.c.2: 10 CFR 50.59 Screening and Safety Evaluations
(1) Inspection Scope
After inspection of the licensees program and conduct of 10 CFR 50.59 Screening
and Safety Evaluations, which was documented in NRC Inspection Report
05000285/2013008, Restart Checklist Item 3.c.2, 10 CFR 50.59 Screening and
Safety Evaluations, remained open. The decision by the team to leave the area
open was based on the teams inability to close Restart Checklist Bases Document
Items 3.c.2.2, Adequacy of extent of condition and extent of causes, and 3.c.2.3,
Adequacy of corrective actions, for the root cause analysis for the 10 CFR 50.59
process.
The team reviewed licensee actions taken to address this area. For this follow-up
review of the licensees 10 CFR 50.59 process the team evaluated the thoroughness
of their extent of condition and causal analysis, and the adequacy of identified
corrective actions to ensure proper treatment of changes to the facility.
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(2) Observations and Findings
Determine that the root cause evaluation addressed the extent of condition and the
extent of cause of the problem
During a previous Inspection Manual Chapter 0350 Confirmatory Action Letter
Inspection documented in NRC Inspection Report 05000285/2013008, the team
determined that the licensees root cause evaluation did not fully address the extent
of condition and the extent of cause of the problem. The team determined that the
scope of the licensees root cause analysis focused on events within the past five
years for the extent of condition and the extent of cause of the problem. However, a
number of plant changes were identified by that inspection team outside the scope of
the 50.59 root cause analysis review period that failed to receive prior NRC review
and approval before implementation.
To address this observation, the licensee expanded their scope. The licensee first
expanded scope of their 10 CFR 50.59 reviews back to the year 2005. A
subsequent expansion back to the year 2000 was conducted as a result of the
review of their root cause analysis. Additionally, as a long term corrective action the
licensee has committed to implement a design basis reconstitution project that
addresses ensuring system design requirements are established for all safety
significant systems. Based on these actions the NRC determined the licensee is
adequately addressing the extent of condition and extent of cause of the problem.
Determine that appropriate corrective actions are specified for each root and
contributing cause
During a previous Manual Chapter 0350 Confirmatory Action Letter Inspection
documented in NRC Inspection Report 05000285/2013008, the team determined
that the licensee specified appropriate corrective actions for each root and
contributing cause. However, the team identified that all corrective actions to prevent
reoccurrence for the root causes were not in place and effective.
Specifically, one corrective action by the licensee implemented a team to evaluate all
engineering changes as an interim action. The licensee called the team, established
in accordance with this corrective action, the Engineering Assurance Group (EAG).
The team questioned the effectiveness of the EAG relative to 10 CFR 50.59
evaluations after discovering that the group had reviewed an evaluation for the
stations tornado missile design and came to a different conclusion than the NRC on
the need for a license amendment.
Also, the Manual Chapter 0350 Confirmatory Action Letter inspection team
determined that actions taken had not fully addressed the need for the station to
update their current licensing basis documents and for the licensee to train the Fort
Calhoun Station personnel to understand those documents. The team concluded
that changes to the facility would be impacted by the incomplete understanding of
the existing design and licensing bases.
- 40 -
To address these observations, the licensee conducted additional training for the
EAG on the 10 CFR 50.59 program. After this, the team observed that a subsequent
major design change for high energy line break analysis was properly evaluated by
the licensee per 10 CFR 50.59. The licensee also developed tracking metrics to
monitor the health of the 10 CFR 50.59 program at the station. Finally, the licensee
committed to a long term project to review and update the design and licensing basis
of the station.
Determine that a schedule has been established for implementing and completing
the corrective actions
During the previous Manual Chapter 0350 Confirmatory Action Letter Inspection,
documented in NRC Inspection Report 05000285/2013008, the team determined
that the licensee established a schedule for implementing and completing some of
the corrective actions, and that, one key action had not been completed. The
licensee had scheduled the initial training for March 15, 2013. However, the licensee
had moved the training to an undetermined date. At that time, the team concluded
that the failure of the licensee to not establish or assign a new date was insufficient
to consider this aspect as resolved.
To address this observation, the licensee completed 10 CFR 50.59 training classes
for both evaluators as well as screeners, which were specifically targeted to past
noted deficiencies. The initial round of this training was completed in April 2013.
Another session of this course for additional personnel was planned.
(3) Assessment Results
After reviewing actions taken for gaps noted in the licensees 10 CFR 50.59 program
and process, documented in NRC Inspection Report 05000285/2013008, the team
concluded that the licensee had adequately addressed their deficiencies relative to
the 10 CFR 50.59 program.
The following Restart Checklist Items for Area 3.c are closed:
3.c.2.2 Adequacy of extent-of-condition and extent of causes
3.c.2.3 Adequacy of corrective actions
Item 3.d: Maintenance Programs
(1) Inspection Scope
The team reviewed the licensees assessment of the Fundamental Performance
Deficiency associated with equipment reliability and work management. Specifically,
the team assessed CR 2012-8134, for which the Description section stated, in part:
Equipment problems are not prevented, identified, or resolved in a thorough and
timely manner. Issues contributing to this problem include intolerance to
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equipment failures has not been established, long term strategies have not been
developed for age related degradation, the maintenance rule function to monitor
the performance of plant equipment has not been effectively implemented, and
work activities are not effectively managed to ensure long-term equipment
reliability. As a result, the station has experienced low levels of equipment
reliability that affect nuclear safety and work management practices challenge
the safe and reliable operation of the plant.
The team also assessed the adequacy of the extent of condition, extent of causes,
and corrective actions.
The teams assessment of this Fundamental Performance Deficiency was based on
the evaluation criteria from Section 02.02 of NRC Inspection Procedure 95001, which
aligns with this item. The inspection objectives were to:
- Provide assurance that the root and contributing causes of risk-significant issues
were understood;
- Provide assurance that the extent-of-condition and extent-of-cause of risk-
significant issues were identified; and
- Provide assurance that the licensee's corrective actions for risk-significant
performance issues were, or will be, sufficient to address the root and
contributing causes and preclude repetition.
(2) Observations and Findings
Determine that the problem was evaluated using a systematic methodology to
identify the root and contributing causes
The team determined that the licensee evaluated this problem using a systematic
methodology to identify the potential root and contributing causes. Specifically, Root
Cause Analysis 2012-08134 used the analytical techniques of event and causal
factor charting and barrier analysis to identify causal relationships. A safety culture
evaluation was also completed as part of the analytical process.
The licensee identified the following as the root cause and contributing causes:
RC-1: Fort Calhoun Station senior leadership failed to ensure corrective actions
were taken to address safety issues, adverse trends, and assessment-revealed
issues that were identified in the Equipment Reliability programs and processes.
CC-1: Management has not applied an industry-standard Plant Health
Committee process to ensure the success of Equipment Reliability programs
and processes.
CC-2: The training programs or qualification processes have not been fully
effective to ensure station personnel have satisfactory skills and knowledge
- 42 -
enabling them to execute needed work management and long-term equipment
reliability functions.
CC-3: The station leadership team has not demonstrated accountability nor
held station personnel accountable for implementation of the engineering and
work management processes in support of long-term equipment reliability.
CC-4: Procedure and process deficiencies have contributed to the
degraded equipment reliability issue.
CC-5: Fort Calhoun Station failed to ensure that equipment reliability
programs, including regulatory required Maintenance Rule program and
the supporting PM program, were adequately staffed, funded, and trained,
resulting in the inability to identify, correct, and prioritize equipment
problems which resulted in the unacceptable performance of certain safety
related structures, systems, and components.
Determine that the root cause evaluation was conducted to a level of detail
commensurate with the significance of the problem
The licensee conducted the evaluation to a level of detail commensurate with the
significance of the problem. The root cause team interviewed various levels of site
personnel and evaluated station procedures, documents, condition reports,
internal/external operating experience, and related contractor reports.
Determine that the root cause evaluation included a consideration of prior
occurrences of the problem and knowledge of prior operating experience
The licensee reviewed internal and external operating experience to determine
whether the same of similar problems have previously occurred at the Fort Calhoun
Station or within the industry, and if so, what lessons can be learned for the Fort
Calhoun Station. The review also determines if the Problem Statement falls within
the definition for a Repeat Event.
The licensee determined the use of operating experience was not implicated as a
cause/contributor to the condition investigated by this Root Cause Analysis.
Determine that the root cause evaluation addressed the extent of condition and the
extent of cause of the problem
The licensee determined that the conditions discussed in the root cause analysis
continue to impact the reliability of plant structures, systems, and components.
Corrective actions to address the conditions are not short term and require the
restoration, and in some cases, the rebuilding of the programs that have been
allowed to decay over the past few years. In addition, while the Maintenance Rule
and the preventative maintenance (PM) programs are the primary programs that
affect the equipment issues raised by this condition report, there are many more
focused programs that support these programs, such as the Motor Operated Valve
- 43 -
program, the Air Operated Valve program, Flow Accelerated Corrosion program, and
others. All of these would be affected by the cause of this issue since managements
failure to understand the requirements of an effective reliability effort would extend to
any program that dealt with equipment reliability.
The licensee has determined that an extent of condition exists.
The licensee evaluated the potential extent of cause for Root Cause 1. The licensee
determined this cause extended to engineering issues, and procedural issues that
were identified as part of this investigation. There were multiple instances where
conditions/issues were identified internally or externally, identified repetitively, but
never fixed. When an issue was identified, the Fort Calhoun Station wrote a
condition report, instituted a program (BOM, EROP), and then did not ensure that
these actions addressed the identified shortcoming. There is an Extent of Cause as
this issue applies to the entire Corrective Action Program, and thus, to the entire
station.
Determine that the root cause, extent of condition, and extent of cause evaluations
appropriately considered the safety culture components as described in IMC 0310
The root cause, extent of condition, and extent of cause evaluations appropriately
considered the safety culture components as described in Inspection Manual
Chapter 0310. The safety culture review evaluated safety culture aspects against
the data collected during the cause evaluation. Their review identified the cross-
cutting aspects of P.1(d), P.3(c), and P.1(c), were the most applicable.
Determine that appropriate corrective actions are specified for each root and
contributing cause
The team reviewed the licensees corrective actions for each of the root and
contributing causes. RC-1 is addressed by the corrective action to prevent
recurrence, CAPR-1, AI 2012-03986-009, listed in the Organizational Ineffectiveness
at the Fort Calhoun Station RCA. It addresses the oversight and accountability for
Nuclear Safety at all of Fort Calhoun Station to include the cultural aspect of a
Continuous Learning Environment. CAPR-2 revises Station Procedure FCSG-33,
FCS Issue prioritization and Plant Health Committee Process, to improve the
processes of Plant Health Committee (PHC).
Determine that a schedule has been established for implementing and completing
the corrective actions
The team identified that within Root Cause Analysis 2013-08134 a schedule had
been established for implementing and completing the assigned corrective actions.
At the time of the inspection, the corrective actions to prevent recurrence had been
completed and a few of the other corrective actions for the contributing causes had
been designated as complete. The team noted that some of the important corrective
actions related to the engineering programs issues, such as revising the Preventive
Maintenance Program, were not due to be completed until 2014. The team felt that
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these key engineering programs, gaps identified in the licensees Equipment
Reliability Restoration Plan, and coordination of system and component maintenance
activities within the work management process, should have a higher priority so as to
address these potentially significant conditions in a timelier manner.
Determine that quantitative or qualitative measures of success have been developed
for determining the effectiveness of the corrective actions to prevent recurrence
The inspectors noted the licensee had not established specific criteria to assess the
effectiveness of corrective actions to prevent recurrence. However, equipment
issues would be documented in the condition reporting system and screened based
on risk and safety significance for causes. The tracking and trending of these issues
provides reasonable assurance the licensee should detect ineffective corrective
actions.
(3) Assessment Results
The team concluded, based on their reviews of the licensees cause evaluations and
the extent of cause/extent of condition reviews, that this area has been adequately
addressed by the licensee.
The following Restart Checklist Items are closed:
3.d.1 Licensee Assessment of the Fundamental Performance Deficiency
associated with Equipment Reliability/Work Management
3.d.2 Adequacy of extent-of-condition and extent of causes
3.d.3 Adequacy of corrective actions
Item 3.d.2: Equipment Service Life
(1) Inspection Scope
a. The team reviewed the licensees assessment of the engineering area associated
with Equipment Service Life. Specifically, the team assessed CR 2012-9491, for
which the Problem Statement section said, in part,
FCS has operated some equipment beyond its service life.
The team also assessed the adequacy of the extent of condition, extent of causes,
and corrective actions.
The teams assessment of this area was based on the evaluation criteria from
Section 02.02 of NRC Inspection Procedure 95001, which aligns with this item. The
inspection objectives were to:
- 45 -
- Provide assurance that the root and contributing causes of risk-significant issues
were understood;
- Provide assurance that the extent-of-condition and extent-of-cause of risk-
significant issues were identified;
- Provide assurance that the licensee's corrective actions for risk-significant
performance issues were, or will be, sufficient to address the root and
contributing causes and to preclude repetition.
b. Restart Checklist Item NCV 2011003-04, Failure to Provide Procedural Guidance to
Replace or Evaluate Age Degraded Components, was reviewed by the team. The
team verified the adequacy of the licensees causal analysis and extent of condition
evaluations related to this issue. In addition, the team verified that adequate
corrective actions were identified and associated with the licensees root and
contributing causes and extent of condition evaluations, and that, implementation of
these corrective actions are either implemented or appropriately scheduled for
implementation.
(2) Observations and Findings
a. Licensees Evaluation of Equipment Service Life Issues
Determine that the problem was evaluated using a systematic methodology to
identify the root and contributing causes
The team determined that the licensee evaluated this problem using a systematic
methodology to identify the potential root and contributing causes. Specifically, Root
Cause Analysis 2012-9491 used the analytical techniques of event and causal factor
charting, process fault tree, common factors chart, and barrier analysis to identify
causal relationships. A safety culture evaluation was also completed as part of the
analytical process.
The licensee identified the following as the root cause and contributing causes:
RC-1: Leadership failed to provide the level of command and control needed to
prevent Preventative Maintenance (PM) programmatic weaknesses. Shortfalls
include inaccurate or incomplete procedures and programmatic documents,
incomplete PM bases, inconsistent use of end of service life (EOSL) tools,
inadequate system monitoring, and insufficient replacement strategies for
components beyond EOSL. This resulted in the design and implementation of
the stations preventative maintenance (PM) program to not meet industry
standards for operating components beyond end of service life.
CC#1: PM program improvements since 2005 were not effectively managed
resulting in ongoing programmatic deficiencies. For example, resources were
not managed to ensure Equipment Reliability Optimization Project (EROP) PMs
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were developed and implemented, oversight did not ensure components were
correctly scoped, and project plans did not identify equipment at EOSL.
CC#2: Corrective action program behaviors to resolve PM programmatic
weaknesses that would have addressed component EOSL activities were
ineffective. Deficiencies were identified multiple times since 2005.
Determine that the root cause evaluation was conducted to a level of detail
commensurate with the significance of the problem
The licensee conducted the evaluation to a level of detail commensurate with the
significance of the problem. The root cause team interviewed various levels of site
personnel and evaluated station procedures, documents, condition reports,
internal/external operating experience, and related contractor reports.
Determine that the root cause evaluation included a consideration of prior
occurrences of the problem and knowledge of prior operating experience
The licensee reviewed internal and external operating experience to determine
whether the same of similar problems have previously occurred at the Fort Calhoun
Station or within the industry, and if so, what lessons can be learned for Fort Calhoun
Station. The review also determines if the Problem Statement falls within the
definition for a Repeat Event.
The licensee determined that in many situations, the station had opportunities to
identify the overall problems with equipment service life, but tended to focus only on
the issues included in the condition reports. The plant developed corrective actions
to address the specific conditions being evaluated, but did not address the larger
issues.
The licensee determined the use of operating experience was not implicated as a
cause/contributor to the condition investigated by this Root Cause Analysis.
Determine that the root cause evaluation addressed the extent of condition and the
extent of cause of the problem
The licensee evaluated the potential extent of condition that noncritical equipment
may have been operated beyond its service life. They also evaluated whether other
programs governing operation of equipment required for safe and reliable operation
of the station may have deficiencies that result in critical equipment operating in an
unreliable condition. The potential extent of condition is the incomplete status of
station programs intended to improve equipment reliability, including the following:
- PM Program Basis
- System / Component Performance Monitoring
- Life Cycle Management
- Functional Importance Determination
- Component Obsolescence Program
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- Bill of Materials Development Project
- PM Work Order Task Upgrade Project
- EROP/First Time PMs
The licensee has determined that an extent of condition exists.
The licensee evaluated the potential extent of cause for Root Cause 1. The licensee
determined that an extent of cause exists.
Determine that the root cause, extent of condition, and extent of cause evaluations
appropriately considered the safety culture components as described in IMC 0310
The root cause, extent of condition, and extent of cause evaluations appropriately
considered the safety culture components as described in IMC 0310. The safety
culture review evaluated safety culture aspects against the data collected during the
cause evaluation. Their review identified the cross-cutting aspects of H.2(a), H.2(c),
P.1(c), and O.2(b) as the most applicable.
Determine that appropriate corrective actions are specified for each root and
contributing cause
The team reviewed the licensees corrective action for each of the root and
contributing causes. The corrective actions to prevent recurrence were to: (1) revise
or replace FCSG-33, FCS Issue Prioritization and Plant Health Committee Process,
and; (2) improve the processes of the Plant Health Committee and develop and
implement a PM program with component EOSL strategy that meets the industry
standards.
Determine that a schedule has been established for implementing and completing
the corrective actions
Due dates are established for corrective actions for CR 2012-9491. At the time of
the inspection, corrective action to prevent recurrence 1 had been completed and a
few of the other corrective actions for the contributing causes had been completed.
The team noted that the corrective action to prevent recurrence 2, which addresses
the service life documentation issue, is not due until March 31, 2014. The licensee
has evaluated all safety related components to determine actions necessary prior to
returning the unit to service.
During their review the team determined that the licensee had failed to provide an
adequate basis for operability for components that were identified as being past their
specified service life. The team identified this performance deficiency as,
NCV 05000285/2013013-09, Failure to Follow Operability Procedure. This issue is
further discussed in Section 5 of this report.
Determine that quantitative or qualitative measures of success have been developed
for determining the effectiveness of the corrective actions to prevent recurrence
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The inspectors noted the licensee had not established specific criteria to assess the
effectiveness of corrective actions to prevent recurrence. However, equipment
service life issues would be documented in the condition reporting system and
screened based on risk and safety significance for causes. The tracking and
trending of these issues provides reasonable assurance the licensee should detect
ineffective corrective actions. Additionally, the licensee has long term actions to
perform self-assessments of the equipment reliability, preventative maintenance and
performance monitoring programs, including the Plant Health Committee oversight of
equipment reliability.
b. The team reviewed the licensees causal analyses, corrective actions, and extent of
condition associated with previously identified issue, NCV 05000285/2011003-04,
Failure to Provide Procedural Guidance to Replace or Evaluate Age Degraded
Components. The team verified that adequate corrective actions were identified
associated with the causes and extent of condition evaluations and that these
corrective actions were either implemented or appropriately scheduled for
implementation.
(3) Assessment Results
a. The team has concluded, based on their reviews of the cause evaluations and the
extent of cause/extent of condition reviews, that this area has been reviewed by the
licensee to a sufficient level of detail. The following Restart Checklist Items are
closed:
3.d.2.1 Licensee Assessment of equipment service life program
3.d.2.2 Adequacy of extent-of-condition and extent of causes
3.d.2.3 Adequacy of corrective actions
3.4.1.1 Replace Non-RPS CQE (reactor protection system critical quality
equipment) power supplies that will be beyond their recommended
service life.
3.4.2.2 Identify all CQE power supplies; priority will be on RPS CQE power
supplies and then non-RPS CQE power supplies.
3.4.2.3 Determine the installation date for FCS CQE power supplies; these
dates will be used to define those CQE power supplies that are beyond
their service life.
3.4.2.4 Conduct an industry and FCS specific analysis of historical performance
for CQE power supplies; determine the effectiveness of the current
Equipment Reliability (ER) Strategies at the FCS component level.
3.4.2.5 Conduct an analysis of the current FCS ER Strategy for power supplies;
contact vendors, review industry documentation, and benchmark other
plants.
3.4.2.6 Determine the recommended service life for CQE power supplies based
on analyses performed earlier in this action plan.
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These service lives will be based on: (1) manufacturer and model, (2)
qualified life testing, (3) vendor recommendations and communication
with vendors, (4) remnant life based on stress testing of removed power
supplies, (5) industry and FCS specific historical performance, and (6)
actual duty cycle and service condition where these power supplies are
installed .
3.4.2.7 Conduct a failure modes and effects analysis on each power supply to
ensure the impact of failures is understood.
3.4.2.8 Document the time based replacement strategy and basis for CQE and
RPS power supplies. This strategy and basis will provide the tasks to be
performed and the basis for the scope and frequency of those tasks.
This action is being completed before start up to ensure each power
supply has been analyzed and a recommended service life defined.
3.4.2.9 Define those power supplies that are beyond their service life. This will
include power supplies that will be beyond their service life before the
next planned refueling outage.
3.4.2.10 Replace RPS CQE power supplies beyond their service life.
3.4.2.11 Replace Non-RPS CQE power supplies that will be beyond their
recommended service life.
b. The team concluded, based on their reviews of the cause evaluations and the extent
of cause/extent of condition reviews associated with the licensees response to
NCV 05000285/2011003-04, Failure to Provide Procedural Guidance to Replace or
Evaluate Age Degraded Components, that this item is closed.
4. Assessment of NRC Inspection Procedure 95003 Key Attributes
Section 5 of the Restart Checklist is provided to assess the key attributes of NRC
Inspection Procedure 95003. The key attributes are listed as separate subsections
below. It is intended that the activities in these subsections be conducted in conjunction
with reviews and inspections for Sections 1 - 4, rather than a stand-alone review. In
addition, the NRC will review the effectiveness of licensee short term and long term
corrective actions associated with these areas to ensure they are adequate to support
sustained plant performance improvement.
Item 5.a: Design
(1) Inspection Scope
a. The team independently assessed the extent of risk significant design issues. The
review covered the as-built design features of the auxiliary feedwater system. This
review verified its capability to perform its intended functions with a sufficient margin
of safety. The basis for selecting the auxiliary feedwater system was its high risk
significance in the specific individual plant evaluation, and input from system health
reports, performance indicators, condition reports, and licensee event reports. Focus
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was on modifications rather than original system design. Information from this
inspection was used to assess the licensees ability to maintain and operate the
facility in accordance with the design basis.
The teams review included the following:
- Assessment of effectiveness of corrective actions for deficiencies involving
design
- Selection of several modifications to the auxiliary feedwater system to
determine if the system is capable of functioningas specified by the current
design and licensing documents, regulatory requirements, and commitments
for the facility
- Determination if the auxiliary feedwater system is operated consistent with
the design and licensing documents
- Evaluation of the interfaces between engineering, plant operations,
maintenance, and plant support groups
b. The team reviewed the licensees assessment of the Fundamental Performance
Deficiency associated with Engineering Design/Configuration Control. Specifically,
the team assessed the RCA associated with CR 2012-08125, for which the problem
statement was:
Changes to plant configuration and design and licensing bases are not
effectively analyzed, controlled, and implemented. These change processes are
not always conducted in a manner that maintains configuration control and
operating design margins.
The team also assessed the adequacy of the extent of condition, extent of causes,
and corrective actions.
The teams assessment of this Fundamental Performance Deficiency was based on
the evaluation criteria from Section 02.02 of NRC Inspection Procedure 95001 which
aligns with this item. The inspection objectives were to:
- Provide assurance that the root and contributing causes of risk-significant
issues were understood;
- Provide assurance that the extent-of-condition and extent-of-cause of risk-
significant issues were identified;
- Provide assurance that the licensee's corrective actions for risk-significant
performance issues were, or will be, sufficient to address the root and
contributing causes and to preclude repetition
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c. Restart Checklist Item NCV 2010006-01 specifically related to the failure to correct
repeated tripping of the turbine driven auxiliary feed water pump was reviewed by the
team. The team verified the adequacy of the licensees causal analysis and extent of
condition evaluations related to and associated with the issue. In addition, the team
verified that adequate corrective actions were identified and associated with the
licensees root and contributing causes and extent of condition evaluations, and that,
implementation of these corrective actions are either implemented or appropriately
scheduled for implementation.
(2) Observations and Findings
a. Auxiliary Feedwater System Design Review
The team completed an in depth assessment of select risk significant design issues
associated with the auxiliary feedwater system. During this review the team
identified some issues associated with the auxiliary feedwater system. Specifically:
- NCV 05000285/2013013-10, Failure to Evaluate the Effects of Modifying the
Turbine Driven Auxiliary Feedwater Pump
- NCV 05000285/2013013-16, Failure to Submit Licensee Event Report
(Example 3)
These specific issues are documented in Section 5 of this report.
b. Fundamental Performance Deficiency Review Deficiency Associated with
Engineering Design/Configuration Control
Determine that the problem was evaluated using a systematic methodology to
identify the root and contributing causes
The team determined that the licensee evaluated this problem using a systematic
methodology. Specifically, the licensee developed comparative timelines, a common
factors chart, and conducted a barrier analysis to complete Root Cause
Analysis 2013-05570, Design and Licensing Bases Configuration Control.
However, the licensee did not strictly follow the process in all cases for using the
systematic reviews to identify the root and contributing causes. Specifically, Root
Cause Analysis 2013-05570 documented the following root causes:
RC-1: OPPD Design and Licensing Bases information was incomplete at the
beginning of commercial operation.
RC-2: The early culture established standards and expectations for the organization
that resulted in behaviors demonstrating that the operation of the facility was more
important than maintaining the license and design basis of the station.
The team noted that RC-1 more closely fits the definition of a contributing cause in
station procedures. For instance, to supplement RC-1 the licensee stated: This
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initial condition [the incomplete design and licensing bases], combined with a
weakness in licensing bases knowledge and a failure to internalize the importance of
the design bases, resulted in the organization missing repeated opportunities to
correct the initial deficiencies and additional errors were created over time. A root
cause is defined in Station Procedure FCSG-24-4, Attachment 1, Section 1.17, as
the most basic, fundamental cause(s) of a problem, which, if corrected, will prevent
recurrence of the identified problem and similar problems. When evaluated against
the cause testing criteria used by the licensee and described in Station
Procedure FCSG-24-5, Cause Evaluation Manual, the team concluded that RC-1,
without accounting for the knowledge aspect, does not, by itself, constitute a root
cause.
Similarly, when applying the cause test to RC-2, the team concluded that the
following cause test questions could have been answered Yes, suggesting that
RC-2 is a contributing and not a root cause: (1) If this cause being considered was
absent, would the event that initiated the evaluation have occurred?; (2) If this cause
is eliminated, is there a way for the same event to occur?; and (3) If this cause is
eliminated, will there be future similar events?
Determine that the root cause evaluation was conducted to a level of detail
commensurate with the significance of the problem
The team determined that the root cause analysis was conducted to a level of detail
commensurate with the significance of the problem. Specifically, as discussed
above, the licensee conducted Root Cause Analysis 2013-05570 using comparative
timelines, a common factors chart, and a barrier analysis. The analysis was also
supplemented by information gathered through interviews and a historical overview
which helped illustrate the magnitude and precedence of Fort Calhoun Stations
inability to maintain design control and documentation associated with structures,
systems, components, and activities affecting quality. The licensees root cause
analysis techniques were generally thorough and to a level of detail commensurate
with the significance of the problem.
Determine that the root cause evaluation included a consideration of prior
occurrences of the problem and knowledge of prior operating experience
The team determined that the root cause analysis included evaluations of both
internal and external industry operating experience. The licensees evaluations of
industry operating experience provided sufficient detail such that general conclusions
could be established regarding any similarities. The root cause analysis teams
operating experience review also determined this problem fell within the definition of
a repeat event. In accordance with Station Procedure FCSG-24-4, Condition Report
and Cause Evaluation, a repeat event is a significance Level A condition or event
that shares the same or similar root causes as a previous event. The root cause
analysis write up stated that, while the team did not identify similar corrective actions
to prevent recurrence associated with a root cause, it is clear by a review of the
timeline presented in the report that this event was preventable through the use of
internal and external operating experience.
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The team identified, however, that the licensee did not document the repeat event in
accordance with station procedures. Specifically, Station Procedure FCSG-24-4
states that, if the problem is determined to be a repeat event then the root cause
analysis shall explain why previous root cause analysis corrective actions to prevent
recurrence did not prevent the repeat event, and the new corrective action to prevent
recurrence should consider why the previous corrective actions to prevent
recurrence were not effective. In addition, a condition report should be issued
describing the problem with the previous root cause analysis(s) and reference the
condition report in this section of the root cause analysis report. Although
documented as a repeat event, the licensee did not perform the required actions.
The specific issue is documented as NCV 05000285/2013013-11, Failure to
Perform Adequate Operating Experience Reviews In Accordance with Station
Procedure FCSG-24-4. This issue is further discussed in Section 5 of this report.
Determine that the root cause evaluation addressed the extent of condition and the
extent of cause of the problem
The team reviewed Root Cause Analysis 2013-05570 as it relates to extent of
condition and extent of cause.
For the extent of condition, the licensee evaluated the extent to which the actual
condition existed with other plant processes, equipment, or human performance.
The condition, in this case, is that the licensee did not maintain adequate
configuration control of the structures, systems, components, or activities in
accordance with 10 CFR Part 50, Appendix B. The licensee used the approaches of
Station Procedure FCSG-24--4, Course Evaluation Manual, for their review and
concluded that there was no extent of condition. In their review, the licensee stated
that the problem includes all station structures, systems, components, and processes
encompassed by the design and licensing bases, and as such, it could not cause
further impact to other structures, systems, components, or processes. The team
noted that overall, the licensees extent of condition review was superficial and the
answers were broad. Essentially, the licensee presumed that because the problem
statement is so broad, it implicitly includes every plant process that is impacted by
the problem. Consequently, the licensee saw no need to specifically list them in the
review. However, the team noted that since other processes are significantly
impacted by this problem, listing them as part of the review would have generated
corrective actions associated with each specific process. For instance, processes
such as operability determination, 50.59 reviews, configuration control (tagging),
design, vendor modifications, work control, surveillance program, preventive
maintenance, and nondestructive examination would be impacted by the licensees
failure to maintain adequate configuration control of the structures, systems,
components, or activities, in accordance with, 10 CFR Part 50, Appendix B.
For the extent of cause, the licensee reviewed the root causes of the identified
problems to determine where they may have impacted other plant processes,
equipment, or human performance. The licensee concluded that RC-1 extended to
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the procedures of other site organizations that could have been incorrectly translated
or impacted due to the lack of knowledge and understanding of design and licensing
bases. Specifically, the licensee considered the following departments and
processes as being impacted: Radiation Protection, Emergency Planning,
Chemistry, Security, Operations procedures, Maintenance procedures, and
Engineering implementing procedures. The team noted that the extent of cause did
not document the basis for the vulnerable/not vulnerable conclusion for each area of
the potentially vulnerable list as required in Station Procedure FCSG-24-5.
Determine that the root cause, extent of condition, and extent of cause evaluations
appropriately considered the safety culture components as described in Inspection
Manual Chapter 0310
The root cause, extent of condition, and extent of cause evaluations appropriately
considered the safety culture components as described in Inspection Manual
Chapter 0310. The licensee identified that a majority of the cross-cutting aspects
were applicable to issues related to the stations inability to maintain design control
and documentation associated with structures, systems, components, and activities
affecting quality. Specifically, the areas of human performance, problem
identification and resolution, safety conscious work environment, and other
components were applicable to issues related to design and licensing bases
maintenance.
Determine that appropriate corrective actions are specified for each root and
contributing cause
The team reviewed the licensees corrective actions for each of the root and
contributing causes for both root cause analyses. The corrective actions to prevent
recurrence and implemented to address the root causes identified in Root Cause
Analysis 2013-05570, were to identify and define the licensing and design bases and
assure licensing and design bases documentation remains current, accurate,
complete, and retrievable. The corrective action to prevent recurrence also included
modifying the engineering support personnel initial and continuing training programs
to incorporate the corrective action to prevent recurrence previously mentioned (the
identification and definition of licensing and design bases to assure they remain
current, accurate, complete, and retrievable). Lastly, the licensee stated that, as an
additional corrective action to prevent recurrence, they would strengthen the function
of the oversight group that performs reviews of documentation, including
10 CFR 50.59 reviews, modifications, operability evaluations, and other documents
developed that utilized design and licensing bases information. Other corrective
actions included: (1) providing training to personnel who utilize the design and
licensing bases, including the individuals involved with the processes already
mentioned; (2) developing and implementing performance metrics for the
implementation of the corrective action to prevent recurrence and corrective actions
mentioned.
The team determined that the corrective actions identified for the root and
contributing causes appear to be adequate in principle. However, the team noted
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that the due dates for the corrective actions to prevent recurrence are set in the
distant future, and as a result, it will be a significantly long time before all the actions
to address the licensees inability to maintain design control and documentation
associated with structures, systems, components, and activities affecting quality, will
prevent recurrence of these issues. At the time of this inspection, none of the
corrective actions to prevent recurrence or corrective actions associated with this
root cause analysis had been completed.
The team also reviewed several interim actions implemented by the licensee.
Interim actions were taken to temporarily prevent the effects of a condition or make
an event less likely to recur during the period when final corrective actions or
corrective actions were completed. The team noted that, as part of the interim
action, the licensee completed an operability evaluation to allow the use of the
Alternate Seismic Criteria Methodology (ASCM) to support plant startup. However,
the NRC had already communicated with the licensee that the use of ASCM is not
permissible.
The team identified the following deficiencies during their review:
- NCV 05000285/2013013-13, Failure to Incorporate Design Requirements
For Switchgear Room Cooling
- NCV 5000285/2013013-14, Inadequate Corrective Action for Non-Seismic
Category 1 Piping
- NCV 05000285/2013013-15, Lack of an Adequate Operability Evaluation for
Class 1 Raw Water Piping in Non-Class 1 Service Building
- NCV 05000285/2013013-16, Inadequate Operability Determination due to
Failure to Consider an Unavailable Raw Water Pump
- NCV 05000285/2013013-17, Failure to Translate Design Sluice Gate
Leakage Into Operating Procedure
- NCV 05000285/2013013-18, Inadequate Procedure for Intake Cell Level
Control During a Flooding Event
- NCV 05000285/2013013-19, Failure to Translate Appendix R License
Exemptions into the Plants Fire Protection Program Design
- NOV 05000285/2013013-20, Failure to Provide Complete and Accurate
Information to the NRC
- NCV 5000285/2013013-21, Failure to Perform Adequate Extent of Condition
Reviews
- URI 05000285/2013013-22, Shutdown Cooling Piping and Pipe Supports
Calculation Has Incorrect Acceptance Criteria for Anchor Displacement
- 56 -
These issues are further discussed in Section 5 of this report.
Determine that a schedule has been established for implementing and completing
the corrective actions
The team determined that a schedule has been established for implementing and
completing the corrective actions associated with Root Cause Analysis 2013-05570.
However, the team also noted that most of the corrective actions are scheduled for
completion in the future, and the team was not able to verify them by the end of the
inspection period. In addition, even though the licensee has implemented interim
corrective actions, the team still found many issues with the licensees design and
licensing bases maintenance. Notwithstanding, the team concluded that due to the
extent and magnitude of the corrective actions, the schedule for the dates
established for completion appeared to be reasonable.
Determine that quantitative or qualitative measures of success have been developed
for determining the effectiveness of the corrective actions to prevent recurrence
The licensee developed effectiveness reviews to measure the progress and success
of the corrective action to prevent recurrence for Root Cause Analysis 2013-05570.
The licensee established effectiveness reviews that will include, in part, the
determination of the reconstitution of the design and licensing bases was
implemented properly and in a timely manner. In addition, the licensee will check if
there have been any recurring instances of failure to maintain the licensing bases.
Furthermore, the licensee established interim effectiveness reviews that consist of
periodic assessments tracking the progress of the reconstitution of the licensing
bases. The reviews will evaluate the implementation of the reconstitution and
determine if the milestones are met and documentation is retrievable. In addition,
the interim effectiveness reviews will evaluate the determination of the records after
they are established and before the actions to reconstitute records begin. These
interim effectiveness reviews will occur every eight months.
The team noted that the effectiveness reviews have been determined/decided
conceptually. However, at the time of this inspection (and because it is so early in
the process), the licensee had no details established as to what the specific
methodology to conduct the effectiveness reviews will be. Specifically, the licensee
has established the dates of the effectiveness reviews, which will be conducted
throughout the reconstitution of the licensing and design basis documents. However,
the action items in Root Cause Analysis 2013-05570 do not provide detail of the
process/methodology. At the time of this inspection, none of the effectiveness
reviews were ready for inspection since, as mentioned before, the due dates are in
the future.
c. The team reviewed the licensees causal analyses, corrective actions, and extent of
conditions associated with the previously identified issue,
NCV 05000285/2010006-01, Failure to Correct Repeated Tripping of the
Turbine-driven Auxiliary Feedwater Pump FW-10. In addition, the team verified that
adequate corrective actions were identified and associated with the causes and
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extent of condition evaluations, and that, these corrective actions were either
implemented or appropriately scheduled for implementation.
(3) Assessment Results
a. The team concluded, based on their engineering inspection activities associated with
the auxiliary feedwater system, their reviews of the cause evaluations, and the extent
of cause/extent of condition reviews, that this area has been adequately addressed
by the licensee. The following Restart Checklist Items are closed:
5.a.1 Perform NRC design engineering team inspection of the Auxiliary
Feedwater System
5.a.2 Licensee Assessment of the Fundamental Performance Deficiency
associated with Engineering/Configuration Control
5.a.3 Adequacy of extent-of-condition and extent of causes
5.a.4 Adequacy of corrective actions
b. The team concluded, based on their reviews of the cause evaluations and the extent
of cause/extent of condition reviews associated with the licensees response to
NCV 05000285/2010006-01, Failure to Correct Repeated Tripping of the Turbine-
driven Auxiliary Feedwater Pump FW-10, that this item is closed.
Item 5.d: Equipment performance
(1) Inspection Scope
Restart Checklist Item LER 2012-018 related to the containment air cooling units
being operated outside of Technical Specification requirements was reviewed by the
team. The team verified the adequacy of the licensees causal analyses and extent
of condition evaluations. In addition, the team verified that adequate corrective
actions were identified and associated with the licensees root and contributing
causes and extent of condition evaluations, and that, implementation of these
corrective actions are either implemented or appropriately scheduled for
implementation.
(2) Observations and Findings
The team reviewed the licensees causal analyses, corrective actions, and extent of
condition associated with Licensee Event Report 2012-018, Containment Air
Cooling Units Operated Outside of Technical Specification during Cycle 26. In
addition, the team verified that adequate corrective actions were identified
associated with the causes and extent of condition evaluations and that these
corrective actions were either implemented or appropriately scheduled for
implementation.
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(3) Assessment Results
The team has concluded, based on their reviews of the cause evaluations and the
extent of cause/extent of condition reviews associated with Licensee Event
Report 2012-018, Containment Air Cooling Units Operated Outside of Technical
Specification during Cycle 26, that this item is closed.
5. Specific Issues Identified During This Inspection
(1) Introduction. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Actions, for the licensees failure to promptly identify and
correct a condition adverse to quality.
Description. On May 2, 2012, the licensee completed Root Cause Analysis 2011-06621
associated with 480 Vac circuit breaker 1B3A tripping open due to excessive current
draw during the fire event in the 480 Vac 1B4A load center that occurred on
June 7, 2011. The licensee determined that zone select interlock jumpers for the 1B3A
Nuclear Logistics Incorporated/Square-D Masterpact circuit breaker was incorrectly
installed during the replacement of the original General Electric AK-50 low voltage power
circuit breaker in the 480 Vac 1B3A load center. With the jumpers incorrectly installed,
the zone select interlock feature for circuit breaker 1B3A was not disabled. This
configuration resulted in the breaker 1B3A tripping at the instantaneous overcurrent
setpoint (immediately) when it sensed a fault, instead of tripping at the appropriate timed
overcurrent setpoint, which would have allowed bus tie breaker BT-1B3A to open, and
not result in the loss of load center 1B3A during the fire event. The licensee also
identified that injection testing with the full function test kit bypassed the zone select
interface feature, regardless of the configuration of the zone select interface jumpers
installed at the breaker. Therefore, the testing that had been performed would not have
identified the zone select interface jumper issues. The licensee initiated corrective
action item CR 2011-06621-32 to perform current injection testing on all 480 Vac
breakers without the use of a full function test kit to ensure that the zone select interface
does not adversely impact breaker coordination. The licensee documented that this
action as complete on January 15, 2013.
The team reviewed Root Cause Analysis 2011-06621, and its associated corrective
actions. The team noted that 10 of the 12 480 Vac circuit breakers had current injection
testing conducted without the full function test kit to verify the proper zone select
interface jumper installation and proper breaker performance. Specifically, the
480 Vac load center main breaker 1B4A and the bus tie breaker BT-1B4A were not
tested in accordance with corrective action item CR 2011-06621-32 prior to the action
being closed. The team informed the licensee of this issue and the licensee initiated
CR 2013-13262 to capture this in the stations corrective action program.
The licensee determined that Work Orders WO461130 and WO461131 were planned to
conduct 480 Vac 1B4A load center breaker current injection testing without the full
function test kit, but the work was not completed, and the corrective action item was
incorrectly closed as completed. On July 7, 2013, the licensee performed current
injection testing without the full functional test kit on main breaker 1B4A and the bus tie
- 59 -
breaker BT-1B4A to verify zone select interface jumpers were properly installed and
proper breaker performance.
The team determined that the apparent cause of this finding was that the licensee failed
to use conservative assumptions and conduct effectiveness reviews to validate injection
testing without the full functional test kit was completed for all twelve 480 VAC circuit
breakers prior to closing corrective action item CR 2011-06621-32.
Analysis. The licensees failure to promptly identify and correct a condition adverse to
quality is a performance deficiency. This performance deficiency was more than minor,
and therefore a finding, because it was associated with the equipment performance
attribute of the Mitigating Systems Cornerstone, and affected the associated objective to
ensure availability, reliability, and capability of systems that respond to initiating events
to prevent undesirable consequences. The team evaluated the finding using Inspection
Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination
Process, 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, dated
May 25, 2004, and determined that the finding is of very low safety significance (Green)
because the finding did not require a quantitative risk assessment because adequate
mitigating equipment remained available. The finding had a cross-cutting aspect in the
area of human performance associated with the decision-making component because
the licensee did not ensure that the proposed action was safe in order to proceed, rather
than unsafe in order to disapproved the action H.1(b).
Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, requires,
in part, that, Measures shall be established to assure that conditions adverse to quality,
such as failures, malfunctions, deficiencies, deviations, defective material and
equipment, and nonconformances are promptly identified and corrected. Contrary to
the above, an action to correct a condition adverse to quality was not completed when it
was identified that injection testing with the full functional test kit would not verify proper
zone select interface operation and proper breaker performance. Specifically, from
January 15, 2013 to July 7, 2013, the licensee failed to conduct injection testing without
the full functional test kit for the 480 Vac load center main breaker 1B4A and bus tie
breaker BT-1B4A. On July 7, 2013, the licensee conducted injection testing without the
full functional test kit for main breaker 1B4A and tie bus breaker BT-1B4A to verify
proper zone select interface jumper installation and proper breaker performance.
Because the finding was of very low safety significance (Green) and has been entered
into the corrective action program as CR 2013-13262, this violation is being treated as a
non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy:
NCV 05000285/2013013-01, Failure to Complete all Testing for a Condition Adverse to
Quality.
(2) Introduction. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion XVII, Quality Assurance Records, associated with the failure to furnish
evidence of an activity affecting quality associated with the 480 V breakers.
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Description. On June 7, 2011, a fire occurred in the west switchgear room that caused
extensive damage to 480 Vac switchgear 1B4A and associated equipment. The root
cause of the fire was determined to be, The design process failed to identify critical
parameters and interfaces such as the silver plating contact area on the switchgear
cubicle stabs, during a prior breaker replacement. One of the contributing causes to the
fire was determined to be, The design change specifications did not consider the partial
plating of the switchgear stabs, resulting in the replacement breaker cradles engaging
the bus stabs at the edge of and beyond the silver-plated contact area. Corrective
Action 2 stated that the licensee would, Re-align NLI breaker cradles so finger to bus
stab engagement is in the silver plated contact surface, obtain acceptable as left digital
low resistance ohmmeter (DLRO) readings under work orders, and corrective
Action 28 stated that the licensee would, Develop a testing, inspection, and trending
program to verify electrical connection adequacy. Use the resistance measurements
obtained from the work order and trend the changes for appropriate adjustments to
maintenance frequency and corrective actions.
During the teams review of the root cause analysis, they requested the basis for the
licensee determining the DLRO values were acceptable. The licensee discovered that
the engineering process for determining the acceptable DLRO values could not be found
or identified because the individual who had provided the criteria had since retired. The
licensee generated CR 2013-04032 to capture this concern in the stations corrective
action program.
Corrective actions for CR 2013-04032 did not require the licensee to establish DLRO
values for ensuring proper connections until the next refueling outage. The team
questioned how the licensee was ensuring the DLRO measurements that were already
taken were satisfactory and would ensure operability of the 480 Vac breakers. The
licensee generated acceptance criteria to address this issue and reviewed the previously
obtained DLRO values. Subsequently, during the review of previously obtained DLRO
values the licensee found values outside the acceptance range. The licensee generated
CRs 2013-14398 and 2013-14404 to capture this issue in the stations corrective action
program.
Analysis. The licensees failure to furnish evidence that showed the required DLRO
values ensured proper connections between the Square D Masterpact breaker/cradle
assemble to the GE AKD-5 480 V cubicle stabs was a performance deficiency. The
performance deficiency was determined to be more than minor, and therefore a finding,
because it affected the design control attribute of the Mitigating Systems Cornerstone,
and it directly affected the cornerstone objective to ensure availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. Using Inspection Manual Chapter 0609, Appendix A, The Significance
Determination Process (SDP) for Findings At-Power, dated July 1, 2012, the finding
was determined to have very low safety significance (Green) because it: (1) was not a
deficiency affecting the design and qualification of a mitigating structure, system, or
component, and did not result in a loss of operability or functionality; (2) did not
represent a loss of system and/or function; (3) did not represent an actual loss of
function of at least a single train for longer than its allowed outage time, or two separate
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safety systems out-of-service for longer than their Technical Specification allowed
outage time; and (4) did not represent an actual loss of function of one or more non-
Technical Specification trains of equipment designated as high safety-significance in
accordance with the licensees maintenance rule program. This finding had a cross-
cutting aspect in the area of human performance, associated with the resources
component, because the licensee failed to maintain complete, accurate and up-to-date
design documentation. Specifically, the licensee did not maintain the engineering
process for determining acceptable DLRO values H.2(c).
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion XVII, Quality Assurance
Records, states, in part, that, Sufficient records shall be maintained to furnish evidence
of activities affecting qualityThe records shall also include closely-related data such as
qualifications of personnel, procedures and equipmentRecords shall be identifiable
and retrievable. Contrary to the above, from June 2011 through July 2013, the licensee
did not maintain records related to the qualification of equipment in an identifiable and
retrievable manner. Specifically, the licensee failed to maintain design documents that
detailed the correct DLRO acceptance values required for ensuring proper connections
between the Square D Masterpact NW breaker/cradle assemble to the GE AKD-5
480 Vac cubicle stabs. Because this finding is of very low safety significance (Green)
and has been entered into the corrective action program as Condition Report
CR 2013-04032, this violation is being treated as a non-cited violation, consistent with
Section 2.3.2 of the NRC Enforcement Policy: NCV 05000285/2013013-02, Failure to
Furnish Evidence of an Activity Affecting Quality.
(3) Introduction. The team identified a Severity Level IV violation of 10 CFR 50.59,
Changes, Tests, and Experiments, associated with the licensees failure to adequately
evaluate modification EC 33464, Replace AK-50 480 V Main and Bus-Tie Breakers
With Molded Case Type or Equivalent, to determine if it required prior NRC approval.
Description. In November 2009, the licensee implemented a modification to replace
twelve General Electric AK-50 low voltage power circuit breakers with Nuclear Logistics
Incorporated/Square-D Masterpact circuit breaker/cradle assemblies and digital trip
devices. This modification was developed to address obsolescence issues and
maintenance problems with the older AK-50 circuit breakers.
The licensee used General Electric AKD-5 Powermaster Low Voltage Drawout
Switchgear, with a welded aluminum bus bar structure that transitioned to copper bus
stabs in each breaker cell. The original AK-50 circuit breakers connected directly to the
silver-plated areas on the line and load stabs. The new Nuclear Logistics
Incorporated/Square-D circuit breaker design was an integrated unit consisting of a
circuit breaker and cradle assembly. The cradle assembly converted the internal vertical
breaker connectors to top and bottom spring-loaded horizontal finger assemblies which
connected to the switchgear bus stabs.
Root Cause Analysis 2011-05414, which was performed to evaluate the June 7, 2011,
fire in the 480 Vac Class 1E load center 1B4A, identified that the root cause of the fire
was, the design process failed to identify critical parameters and interfaces such as the
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silver plating contact area on the switchgear cubicle stabs. It was determined that the
finger assemblies extended beyond the silver-plated area on the switchgear bus stabs
and interfaced directly with the copper portion of the stabs. The over extension of the
finger assemblies, buildup of copper oxide, and residual hardened grease residue led to
high resistance between the finger assemblies and stabs leading to the fire.
CR 2011-06319 was written after the fire for the discovery of the improper engagement
of cradle fingers to silver plating on the stabs. The licensee re-analyzed the 50.59 that
was completed as part of the initial breaker replacement modification (EC 33464). The
team reviewed the licensees implementation of the requirements in 10 CFR 50.59 for
the modification. The team also reviewed the licensees implementation of the
requirements in Procedure FCSG-23, 10 CFR 50.59 Resource Manual, Revision 8,
and Nuclear Energy Institute, Guideline for 10 CFR 50.59 Implementation, (NEI-96-07),
Revision 1. Procedure FCSG-23 is based on and incorporates the guidance in
The team noted that the screening process had determined that the finger assemblies
engagement with the stabs was not considered a credible failure mode, and that, it was
stated that the Masterpact circuit breaker/cradle interface would not decrease the
reliability of the equipment. The team recognized that this was in direct contradiction of
the root cause documented in Root Cause Analysis 2011-05414, and that, if the licensee
had properly implemented the requirements of 50.59 for the new credible failure mode
associated with the finger assemblies engagement, the adverse impact would have
required a 50.59 evaluation with the potential need for prior NRC review and approval.
In addition, the team identified that the new potential failure modes could have a
significant impact regarding the reliability of the equipment. This is in contradiction with
the NEI 96-07 screening criteria, which states that, [t]he screening process is not
concerned with the magnitude of adverse affects. The qualifier which the licensee
placed on the magnitude of the new potential failure modes may have resulted in the
licensee missing other credible failure modes with adverse effects during the screening
process.
The team informed the licensee of their concerns associated with the finger assemblies
engagement with the stabs not being considered a credible failure mode and the
contradiction between the 50.59 screening and Root Cause Analysis 2011-05414. The
teams also asked about the 50.59 screening using a significant decrease as the criteria
for adverse effects instead of considering all/any adverse effects. The licensee entered
this issue into their corrective action program as CRs 2013-04474 and 2013-16954.
Based on the teams questions, the licensee has determined that a 50.59 evaluation was
needed for modification EC 33464.
Analysis. The licensees failure to implement the requirements of 10 CFR 50.59 and
adequately evaluate changes associated with the electrical distribution system was a
performance deficiency. Because this performance deficiency had the potential to
impact the NRCs ability to perform its regulatory function, the team evaluated the
performance deficiency using traditional enforcement. In accordance with
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Section 2.1.3.E.6 of the NRC Enforcement Manual, the team evaluated this finding using
the significance determination process to assess its significance. Using Inspection
Manual Chapter 0609, Appendix A, The Significance Determination Process for
Findings At-Power, the finding was determined to have very low safety significance
(Green) because it: (1) was not a deficiency affecting the design or qualification of a
mitigating structure, system, or component, and did not result in a loss of operability or
functionality; (2) did not represent a loss of system and/or function; (3) did not represent
an actual loss of function of at least a single train for longer than its Technical
Specification allowed outage time, or two separate safety systems out-of-service for
longer than their Technical Specification allowed outage time; (4) did not represent an
actual loss of function of one or more nonTechnical Specification trains of equipment
designated as high safety-significance in accordance with the licensees maintenance
rule program; and (5) did not involve the loss or degradation of equipment or function
specifically designed to mitigate a seismic, flooding, or severe weather event.
Therefore, in accordance with Section 6.1.d.2 of the NRC Enforcement Policy, the team
characterized this performance deficiency as a Severity Level IV violation. The team
determined that a cross-cutting aspect was not applicable to this performance deficiency
because the failure to adequately evaluate changes in accordance with 10 CFR 50.59
was strictly associated with a traditional enforcement violation.
Enforcement. Title 10 CFR 50.59, Changes, Tests, and Experiments, Section (c)(1),
states, in part, that a licensee may make changes in the facility as described in the
Updated Safety Analysis Report without obtaining a license amendment pursuant to
10 CFR 50.90 only if: (1) a change to the Technical Specifications incorporated in the
license is not required; and (2) the change, test, or experiment does not meet any of the
criteria in Paragraph (c)(2). 10 CFR 50.59, Section (c)(2), states, in part, that a licensee
shall obtain a license amendment pursuant to Section 50.90 prior to implementing a
proposed change, if the change, would result in more than a minimal increase in the
likelihood of occurrence of a malfunction of a structure, system, or component (SSC)
important to safety previously evaluated in the Final Safety Analysis Report (as
updated). Contrary to the above, the licensee failed to identify and evaluate new
creditable failure modes to determine if they represented an adverse effect on the
480 Vac electrical distribution system, and therefore, did not perform the required 50.59
evaluation with the potential need for prior NRC review and approval. In addition, the
licensee placed a qualifier on the magnitude of the adverse effects during the screening
process, potentially missing other adverse effects introduced as part of modification
EC 33464. The licensees corrective action was to revise the evaluation. Because this
violation was entered into the corrective action program as CRs 2013-04474, and
2013-16954, to ensure compliance was restored in a reasonable amount of time, and
the violation was not repetitive or willful, this Severity Level IV violation is being treated
as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy:
NCV 05000285/2013013-03, Failure to Evaluate Changes to Ensure They Did Not
Require Prior Approval.
(4) Introduction. The team identified three examples of a Severity Level IV, non-cited
violation of 10 CFR 50.73, Immediate Notification Requirements for Operating Nuclear
Power Reactors, associated with the licensees failure to submit a licensee event report
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within 60 days following a discovery of an event meeting the reportability criteria as
specified.
Description. The team identified three examples of failure to make a required event
notification within the 60 day time limit specified in 10 CFR 50.73.
Examples 1 and 2: The licensee failed to submit the required 60-day licensee event
report for the 480 Vac 1B3A main breaker trip during the switchgear fault on 480 Vac
1B4A load center as required by: (1) Title 10 CFR 50.73(a)(2)(i)(B) for any operation or
condition which was prohibited by the plants Technical Specifications; and
(2) 10 CFR 50.73(a)(2)(vii) for any event where a single cause or condition caused at
least one independent train or channel to become inoperable in multiple systems or two
independent trains. The licensee entered this issue into the corrective action program
as CR 2013-12863.
Example 3: The licensee failed to submit the required 60-day licensee event report for a
trip of the turbine-driven auxiliary feedwater pump following a start demand signal during
a monthly operability surveillance test as required by 10 CFR 50.73(a)(2)(i)(B) for any
operation or condition which was prohibited by the plants Technical Specifications. The
licensee entered this issue into the corrective action program as CR 2012-03796.
The team determined that, in both of these examples, the licensee had failed to
thoroughly evaluate and identify all the associated reportability criteria for each issue.
Analysis. The team determined that the failure to make a required licensee event report
was a violation of 10 CFR 50.73. The violation was evaluated using Section 2.2.4 of the
NRC Enforcement Policy, because the failure to submit a required licensee event report
may impact the ability of the NRC to perform its regulatory oversight function. As a
result, this violation was evaluated using traditional enforcement. In accordance with
Section 6.9 of the NRC Enforcement Policy, this violation was determined to be a
Severity Level IV, non-cited violation. The team determined that a cross-cutting aspect
was not applicable to this performance deficiency because the failure to make a required
report was strictly associated with a traditional enforcement violation.
Enforcement. Title 10 CFR 50.73(a)(1) requires, in part, that licensees shall submit a
licensee event report for any event of the type described in this paragraph within 60 days
after the discovery of the event. Contrary to the above, between February 17, 2010 and
June 20, 2013, the licensee failed to submit a licensee event report for three events
meeting the requirements for reporting specified in 10 CFR 50.73. Because this
violation has been entered into the corrective action program as CRs 2013-12863 and
2012-03796, compliance was restored in a reasonable amount of time, and the violation
was not repetitive or willful, this Severity Level IV violation is being treated as a non-cited
violation, consistent with Section 2.3.2.a of the Enforcement Policy:
NCV 05000285/2013013-04, Failure to Submit Licensee Event Report.
(5) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, for the licensees approval of Root Cause
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Analysis 2013-03424, Revision 0 and Revision 1, MSPI Safety System Functional
Failures Degrading Trend, which did not assure corrective actions to prevent repetition
of a significant condition adverse to quality.
Description. The licensee approved Root Cause Analysis 2013-03424, Revision 0,
MSPI Safety System Functional Failures Degrading Trend, on July 8, 2013. This root
cause analysis originally identified the root cause as, Fort Calhoun Stations
engineering management failed to maintain control over the design and configuration of
Fort Calhoun Station. The corrective action to prevent recurrence in Root Cause
Analysis 2013-03424, Revision 0, was documented as:
Identify and define the licensing bases and assure licensing bases documentation
remains current, accurate, complete, and retrievable.
- Identification includes determining the record types
- Identify a consistent numbering system
- Establish methodology (database) for ensuring current and historical
licensing bases records are readily retrievable
- Reconstitute (identify, locate, and store in a retrievable method) the licensing
bases including historical records required to establish the current bases
- If conflicts are identified during identification and location of licensing bases
documentation, a condition report is initiated to document and track the
resolution
- Establish a process for assuring licensing bases documentation remains
current, accurate, complete, and retrievable; current processes may be
retained or revised to assure needed results
- Closure determination: Conduct an outside independent assessment to
validate the completion of identifying all license bases, documents are
retrievable, and that the process for updates is implemented.
The team determined that the corrective action to prevent recurrence specified in Root
Cause Analysis 2013-03424, Revision 0, was not appropriate and would not prevent
recurrence of the root cause. The team determined that the root cause was narrowly
focused on the management of the engineering division and failed to identify a culture in
the engineering division, as a whole, that failed to maintain the design and configuration
control. This licensee initiated CR 2013-12236 to place this issue in the stations
corrective action program.
The licensee revised Root Cause Analysis 2013-03424 to include a new root cause and
an additional corrective action. Root Cause Analysis 2013-03424, Revision 1 revised
the root cause to, Fort Calhoun Station failed to maintain an environment, in the
Engineering Division, that valued maintaining the license and design basis of the station
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over continued operation of the facility. This led to a loss of control over the design and
configuration of Fort Calhoun Station. An additional corrective action to prevent
recurrence was included to strengthen the function of the oversight group that performs
reviews of engineering products.
During their review of Root Cause Analysis 2013-03424, Revision 1, MSPI Safety
System Functional Failures Degrading Trend, the team observed that Root Cause
Analysis 2013-03424 extensively leveraged future actions associated with Root Cause
Analysis 2013-05570, Design and Licensing Bases Configuration Control, to
(a) determine the extent of condition and extent of cause, (b) to effect corrective actions
to preclude repetition, and (c) to complete the required effectiveness review.
Consequently, the team examined the alignment between the two root cause analysis
and the licensees quality-related corrective action program requirements to determine
whether such cross-root cause analysis leveraging reasonably assured corrective
actions to prevent repetition of significant conditions adverse to quality.
Although the closure review of Root Cause Analysis 2013-03424 would recognize its
reliance on Root Cause Analysis 2013-05570, no requirement or process assured that
the review would effectively evaluate changes to Root Cause Analysis 2013-05570 that
could invalidate its tasked contribution to Root Cause Analysis 2013-03424. More
importantly, although the corrective action program data system appeared capable of
linking root cause analysis, no specific process was identified to ensure the assignments
from Root Cause Analysis 2013-03424 would be recognized by the owner of Root
Cause Analysis 2013-05570. In fact, the team confirmed there was no reference to Root
Cause Analysis 2013-03424 in Root Cause Analysis 2013-05570 prior to the teams
comments.
Further, the team determined that the use of future tasking to identify the extent of
condition and extent of cause precluded the ability to assure that corrective actions
approved to address the causes of the significant condition adverse to quality would be
broad enough to prevent their repetition. In this specific instance, the significant
condition adverse to quality or Problem was identified as the degradation of the
Mitigating Systems Performance Indicator (MSPI) Safety System Functional Failure
(SSFF) Performance Indicator (PI) to NRC White. The root cause was determined to be,
the failure, to maintain an environment, in the Engineering Division, that valued
maintaining the license and design basis of the station over continued operation of the
facility. The root cause analysis determined that, other areas in the Engineering
Division are susceptible to this cause, and they were not explicitly addressed in the root
cause analysis. Likewise, the root cause analysis determined that, loss of management
oversight and control of programs has been shown to exist in the plant, and the degree
of loss, and specific areas in which it has been identified, were not explicitly addressed
in the root cause analysis. Rather these extent-of-cause determinations were largely
future tasked to Root Cause Analysis 2013-05570.
Analysis. The licensees failure to establish measures to assure that the cause of the
degrading trend in MSPI safety system functional failures would be promptly identified
and action taken to preclude repetition in accordance with 10 CFR Part 50, Appendix B,
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Criterion XVI was a performance deficiency. The performance deficiency was more than
minor, and therefore a finding, because the failure to correct the cause and preclude the
repetition of the cause would have the potential to lead to a more significant safety
concern. Specifically, failure to identify the correct cause and preclude repetition would
lead to a high frequency of safety system functional failures. This finding was
associated with the Mitigating Systems Cornerstone. Using Inspection Manual
Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings
At-Power, dated July 1, 2012, the finding was determined to be of very low safety
significance (Green) because it: (1) was not a deficiency affecting the design and
qualification of a mitigating structure, system, or component, and did not result in a loss
of operability or functionality; (2) did not represent a loss of system and/or function;
(3) did not represent an actual loss of function of at least a single train for longer than its
allowed outage time, or two separate safety systems out-of-service for longer than their
Technical Specification allowed outage time; and (4) did not represent an actual loss of
function of one or more non-Technical Specification trains of equipment designated as
high safety-significance in accordance with the licensees maintenance rule program.
This finding has a cross-cutting aspect in the area of in the area of problem identification
and resolution, associated with the corrective action program component, because the
licensee did not thoroughly evaluate the problem, and consequently, the resolution did
not identify the extent of cause as necessary P.1(c).
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action
requires, in part, that measures shall be established to assure that conditions adverse to
quality, such as failures, malfunctions, deficiencies, deviations, defective material and
equipment, and non-conformances are promptly identified and corrected. 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, on July 8, 2013, measures established by the licensee failed to assure that
the cause of an identified significant condition adverse to quality was corrected and
corrective actions taken would preclude repetition. Specifically, measures established
by the licensee failed to assure that the cause of an identified significant condition
adverse to quality was corrected and corrective actions taken would preclude repetition
involving a White mitigating system performance indicator associated with a degrading
trend in safety system functional failures. Because the finding was of very low safety
significance (Green) and has been entered into the corrective action program as
CRs 2013-584 and 2013-14614, this violation is being treated as a non-cited violation
consistent with Section 2.3.2.a of the NRC Enforcement Policy:
NCV 05000285/2013013-05, Inadequate Corrective Actions to Prevent Repetition of a
Significant Condition Adverse to Quality, a White MSPI SSFF Degrading Trend.
(6) Introduction. The team identified multiple examples of a Green, non-cited violation of
10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to
control deviations from design standards.
Description. In 2005, the licensee generated calculations and engineering documents
needed to replace several reactor coolant system components, including the steam
generators, pressurizer, reactor vessel head, and the associated structural supports. In
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addition to upgrading the reactor coolant system components, the licensee also
optimized the reactor coolant system support system with the removal of several
structural supports and steel members. The team reviewed a small sample of the
associated calculations and found several deficiencies where the station deviated from
design basis requirements without a technical basis or justification.
In the first example, the team reviewed Design Calculation FC6945, FCS RSG: RCS
Structural Evaluation, and identified that the reactor coolant system piping stress levels
exceeded the code allowable stress levels for accident loads. Specifically, the team
found that reactor coolant system piping would exceed the allowable stress level for the
faulted load combinations of an earthquake combined with a loss of coolant accident. In
response to these concerns, the licensee performed an operability determination and
generated CRs 2013-19878 and 2013-18361.
In the second example, the team reviewed Design Calculation FC7100, Ft. Calhoun
RCS Equipment Support Modifications due to NSSSRP, and Design
Calculation FC7285, Replacement Steam Generator (RSG) and Reactor Coolant Pump
(RCP) Snubber Anchorage Upgrade Analysis, and identified that the reactor coolant
system pipe supports credited concrete strength in excess of the design and licensing
basis values. Specifically, the compressive strength of the concrete, per the design
specifications and the Updated Safety Analysis Report, are 4000 psi or 5000 psi,
depending on the location. However, the licensee used compressive strength values as
high as 6000 psi in the calculations. The use of a higher compressive strength of
concrete in the design calculations did not assure that appropriate quality standards are
specified and included in design documents, and that, deviations from such standards
are controlled. In response to this concern, the licensee generated CRs 2013-20281
and 2013-17885, and performed an operability determination. Using the design and
licensing basis values, the anchor bolts were determined to be operable, but non-
conforming.
In the third example, the team reviewed Design Calculations FC7100, FC7285, and
FC6945, and identified that in several locations, the anchor bolts were designed to a
lesser standard than required by the design and licensing basis. Specifically, the
anchorage was designed to a safety factor of less than 4.0, as required by the licensing
basis. The use of a lower safety factor for anchor bolts in the design calculations did not
assure that appropriate quality standards are specified and included in design
documents and that deviations from such standards are controlled. In response to this
concern, the licensee generated CRs 2013-14726 and 2013-20281. Using the design
and licensing basis values, the anchor bolts were determined to be operable, but non-
conforming.
Analysis. The failure to control deviations from quality standards as required by
10 CFR Part 50, Appendix B, Criterion III, was a performance deficiency. This
performance deficiency is more than minor, and therefore a finding, because it is
associated with the design control attribute of the Mitigating Systems Cornerstone, and
affected the cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences. Using
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Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process
(SDP) for Findings At-Power, dated July 1, 2012, the finding was determined to have
very low safety significance (Green) because it: (1) was not a deficiency affecting the
design and qualification of a mitigating structure, system, or component, and did not
result in a loss of operability or functionality; (2) did not represent a loss of system and/or
function; (3) did not represent an actual loss of function of at least a single train for
longer than its allowed outage time, or two separate safety systems out-of-service for
longer than their Technical Specification allowed outage time; and (4) did not represent
an actual loss of function of one or more non-Technical Specification trains of equipment
designated as high safety-significance in accordance with the licensees maintenance
rule program. There was no cross-cutting aspect assigned to this finding because this
issue does not reflect present licensee performance.
Enforcement. 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in
part, that design changes shall be subject to design control measures commensurate
with those applied to the original design, which includes assuring that applicable
regulatory requirements and the design basis are correctly translated into specifications,
drawings, procedures, and instructions. Contrary to the above, prior to
December 5, 2013, the licensee failed to establish provisions to assure that deviations
from specified quality standards were controlled. Specifically, the licensee failed to
establish provisions to control the design of components within the reactor coolant
system. The licensee took action to perform additional analysis to confirm the operability
of the affected components and to determine the scope of the problem.
Because the finding was of very low safety significance (Green) and has been entered
into the corrective action program as CRs 2013-19878, 2013-18361, 2013-20281, and
2013-14726, this violation is being treated as a non-cited violation consistent with
Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000285/2013013-06, Failure to
Control Deviations From the Design Basis Requirements for Structural Calculations
Related to the Reactor Coolant System.
(7) Introduction. The team identified multiple examples of a Green, non-cited violation of
10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings.
Specifically, the licensees failure to follow station procedures for corrective actions,
operability, and calculation preparation for instances where the interim operability
procedure was invoked for degraded conditions identified with piping and pipe supports.
As a result, non-conservative design inputs were used without entering the non-
conformances into the corrective action process or performing procedurally required
operability evaluations.
Description. Station Procedure PED-QP-31, Operability Determination Process,
describes the licensees operability determination process used by station personnel to
assess the operability of structures, systems, and components (SSC) described in the
licensees Technical Specifications. The procedure defines degraded and
nonconforming conditions as, a condition of a SSC that involves a failure to meet the
current licensing basis (CLB) or a situation in which quality has been reduced because
of factors such as improper design.examples of nonconforming conditions include
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when a SSC fails to conform to one or more applicable codes or standards (e.g., the
CFR, operating license, Technical Specifications, Updated Safety Analysis Report,
and/or license commitments). Step 8.1 provides the licensees requirement that
operators immediately determine operability of degraded or nonconforming conditions:
Piping and pipe supports found to be degraded or nonconforming and that support
SSC described in Technical Specifications should be subject to an operability
determination.
Additionally, Station Procedure FCSG-24-1, Condition Report Initiation, states, in part,
that, engineering product errors that have been issued for implementation that would
have had impact on the operation or qualification of a system or component, and errors
in calculations, would require the initiation of a corrective action report.
The team reviewed Station Calculation FC07234, Evaluation of Shutdown Cooling
Mode Temperature and Pressure Increase on the Safety Injection System Piping and
Pipe Supports, and found that the maximum deflection for certain elements of the
shutdown cooling piping would exceed 1/8 inch. The Safety Evaluation Report for
EA-FC-94-003 (dated April 16, 1993) requires an evaluation for deflection that exceeds
1/16 inch. However, the licensee accepted this condition as acceptable because it met
PED-MEI-17, Interim Operability Criteria, and engineering personnel considered the
conditions acceptable without further review. The operations department was never
informed of the degraded nonconforming condition.
The team reviewed Station Calculation FC02400, Input Data Corresponding to Stress
Summary RW-111A and Qualification Summary, Revision 5, and identified that the
licensee used non-design criteria as acceptance criteria for multiple piping supports in
the raw water system. Station Calculation FC02400, Revision 5, was not a restricted
use analysis. The licensee explained that Revision 5 of Station Calculation FC02400
was a temporary analysis, not for full design use because it was marked as,
confirmation required, and such a marking restricted its use.
The team noted that Station Procedure PED-QP-3, Calculation Preparation, Review
and Approval, provides the requirement in Section 4.4.5 for restricting the use of a
calculation:
The use of unsubstantiated design inputs and assumptions in a calculation is permitted
allowing the design process to proceed provided that they are identified as requiring
confirmation (e.g., "Confirmation Required"). Confirmation Required, is only used for
inputs and assumptions which need to be substantiated at a later date, as determined by
the calculation preparer. It shall not apply to the status of calculation methods (e.g.,
equations/computer codes). Confirmation shall be obtained before the modification has
received a Multi-Discipline Independent Design Verification (IDV) or prior to the analysis
becoming As-Built.
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Analysis. The failure to provide adequate acceptance criteria for an activity affecting
quality was a performance deficiency. This performance deficiency is more than minor,
and therefore a finding, because it is associated with the human performance attribute of
the Mitigating Systems Cornerstone, and affected the cornerstone objective to ensure
the availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Using Inspection Manual Chapter 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power,
dated July 1, 2012, and guidance from the Office of Nuclear Reactor Regulation,
Division of Engineering technical staff for issues where the inputs to calculations
deviated from approved standards, the finding was determined to have very low safety
significance (Green) because: (1) the Office of Nuclear Reactor Regulation technical
staff determined the non-conformances would not render the evaluated component as
inoperable or unable to perform its safety function; (2) it was not a deficiency affecting
the design and qualification of a mitigating structure, system, or component; and (3) it
did not represent an actual loss of function of one or more non-Technical Specification
trains of equipment designated as high safety-significance in accordance with the
licensees maintenance rule program. This finding has a cross-cutting aspect in the area
of human performance associated with work practices component because the licensee
failed to define and effectively communicate expectations regarding compliance with
station procedures H.4(b).
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part, that activities affecting quality be prescribed by documented
instructions, procedures, or drawings, of a type appropriate to the circumstances and be
accomplished in accordance with these instructions, procedures, or drawings. Contrary
to the above, prior to December 5, 2013, the licensee failed to complete activities
affecting quality in accordance with prescribed procedures. Specifically, the licensee
failed to recognize deviations from the design and licensing basis in engineering
calculations were non-conforming conditions and follow the requirements of Station
Procedure FCSG-24-1, Condition Report Initiation, Station Procedure PED-QP-31,
Operability Determination Process, and Station Procedure PED-QP-3, Calculation
Preparation, Review and Approval, when invoking Station Procedure PED-MEI-17,
Interim Operability Criteria. The licensees corrective action was to capture the
identified instances in the corrective action program, and discontinue the use of the
interim operability procedure. Because the finding was of very low safety significance
(Green) and has been entered into the corrective action program as CR 2013-03598,
this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of
the NRC Enforcement Policy: NCV 05000285/2013013-07, Programmatic Failure to
Evaluate Safety Impact of Degraded Conditions During Use of Interim Operability
Criteria.
(8) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the licensees failure to correct
conditions adverse to quality in safety-related equipment. The team identified multiple
examples of this violation where an interim operability criteria procedure was applied
instead of correcting the conditions adverse to quality.
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Description. The team reviewed calculations FC06519 and FC06534 and found that the
licensee identified that certain supports on seismic subsystem AC-215A stress levels
exceeded design basis requirements, but failed to correct the condition adverse to
quality.
Fort Calhoun Station, as part of a design basis reconstitution effort, reviewed several
piping supports installed in the plant and performed analyses to confirm the as-installed
configuration met the design basis requirements. In support of this effort, calculations
FC06519 and FC06534 were originated on November 25, 1995 to analyze piping and
piping supports that are a part of seismic subsystem AC-215A. Specifically, calculations
FC06519 and FC06534 analyzed several supports for the raw water and component
cooling water piping on the discharge lines of the containment air coolers. The
calculations determined that the supports for seismic subsystem AC-215A would exceed
the allowable stress specified by the design basis.
The team noted that the licensee had invoked Station Procedure PED-MEI-17, Interim
Operability Criteria, to determine that the supports were operable and were accepted
as-is in the calculations. Corrective actions or configuration changes to restore the pipe
supports in seismic subsystem AC-215A to acceptable stress levels specified by design
basis requirements could not be found.
The team determined that the licensee had failed to promptly identify and correct
conditions adverse to quality.
Analysis. The failure to correct conditions adverse to quality was a performance
deficiency. This performance deficiency is more than minor, and therefore a finding,
because it is associated with the equipment performance attribute of the Mitigating
Systems Cornerstone, and affected the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Using Inspection Manual Chapter 0609, Appendix A, The
Significance Determination Process (SDP) for Findings At-Power, dated July 1, 2012,
the finding was determined to have very low safety significance (Green) because it:
(1) was not a deficiency affecting the design and qualification of a mitigating structure,
system, or component, and did not result in a loss of operability or functionality; (2) did
not represent a loss of system and/or function; (3) did not represent an actual loss of
function of at least a single train for longer than its allowed outage time, or two separate
safety systems out-of-service for longer than their Technical Specification allowed
outage time; and (4) did not represent an actual loss of function of one or more non-
Technical Specification trains of equipment designated as high safety-significance in
accordance with the licensees maintenance rule program. This finding has a cross-
cutting aspect in the area of problem identification and resolution associated with the
corrective action program component because the licensee had failed to implement a
corrective action program with a low threshold for identifying issues to ensure that an
issue potentially affecting nuclear safety are promptly identified and fully
evaluated P.1(a).
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Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, requires,
in part, that, Measures shall be established to assure that conditions adverse to quality,
such as failures, malfunctions, deficiencies, deviations, defective material and
equipment, and nonconformances are promptly identified and corrected. Contrary to
the above, from November 25, 1995 to December 24, 2013, measures established by
the licensee failed to assure that an identified condition adverse to quality was
corrected. Specifically, the licensee failed to correct overstressed piping in the raw
water system. The licensees corrective actions included an extent of condition review
to determine any other cases where Interim Operability Criteria was used but never
addressed and developing a plan to correct the identified issues.
Because the finding was of very low safety significance (Green) and has been entered
into the corrective action program as Condition Report CR 2013-22426, this violation is
being treated as an non-cited violation consistent with Section 2.3.2.a of the NRC
Enforcement Policy: NCV 05000285/2013013-08, Failure to Correct Overstressed
Components.
(9) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees
failure to develop an adequate procedure for assessing operability.
Description. The team reviewed Station Procedure PED-MEI-17, "Interim Operability
Criteria," which is a procedure the licensee used to evaluate critical quality equipment
(CQE) and limited CQE piping and piping supports that are found to exceed design
basis requirements. The procedure specifies specific criteria for evaluating the
degraded piping and pipe supports to determine operability. The team identified a non-
conservative equation used to calculate allowable bending stresses. The current
equations listed in Station Procedure PED-MEI-17, Revision 2, do not comply with the
requirements of ASME Section Ill, Subsection NF, for allowable bending stress criteria.
Specifically, Station Procedure PED-MEI-17 only has one out of the two required
criterion for bending stress. The procedure provides equations and criteria to increase
allowable bending stress by a factor of two. However, an additional constraint is
required by the ASME code. The second constraint is that the maximum allowable
stress shall not exceed 0.7*Su (70 percent of the ultimate strength of the material).
Using the bending stress equations from Station Procedure PED-MEI-17 with common
steel found in the plant would often make 0.7*Su the limiting condition for allowable
stress. Further, in certain cases the non-conservative stress criteria from Station
Procedure PED-MEI-17 had the potential to allow structures to exceed their ultimate
strength, but be within the allowable bending stress criteria found in the procedure.
The team determined that the licensee had invoked this procedure over 40 times since it
was developed in 1990. Station Procedure PED-MEI-17 has been used to demonstrate
operability on a large population of safety related structures, systems, and components,
including the safety injection system, main steam system, feedwater system, steam
generators, reactor coolant system, and raw water system.
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The team informed the licensee of their concerns and the licensee initiated
CR 2013-22342 to capture this concern in the stations corrective action program.
Subsequently, the licensee determined that Station Procedure PED-MEI-17 was
inadequate and suspended use of the procedure.
Analysis. The failure to use an adequate procedure for evaluating degraded or
nonconforming pipe and pipe supports was a performance deficiency. This performance
deficiency is more than minor, and therefore a finding, because it is associated with the
equipment performance attribute of the Mitigating Systems Cornerstone, and affected
the cornerstone objective to ensure the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. Using Inspection
Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for
Findings At-Power, dated July 1, 2012, and guidance from the Office of Nuclear
Reactor Regulation, Division of Engineering technical staff for issues where the inputs to
calculations deviated from approved standards, the finding was determined to have very
low safety significance (Green) because: (1) the Office of Nuclear Reactor Regulation
technical staff determined the non-conformances would not render the evaluated
component as inoperable or unable to perform its safety function; (2) it was not a
deficiency affecting the design and qualification of a mitigating structure, system, or
component; and (3) it did not represent an actual loss of function of one or more non-
Technical Specification trains of equipment designated as high safety-significance in
accordance with the licensees maintenance rule program. There was no cross-cutting
aspect assigned to this finding because this issue does not reflect present licensee
performance.
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part, that activities affecting quality be prescribed by documented
instructions, procedures, or drawings, of a type appropriate to the circumstances and be
accomplished, in accordance, with these instructions, procedures, or drawings.
Contrary to the above, from May 3, 1990 to December 24, 2013, the licensee failed to
provide a procedure appropriate for assessing operability for safety related piping and
piping supports. The licensees corrective action was to capture the identified instances
in the corrective action program, and discontinue the use of the interim operability
procedure. Because the finding was of very low safety significance (Green) and has
been entered into the corrective action program as CR 2013-22342, this violation is
being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC
Enforcement Policy: NCV 05000285/2013013-09, Non-conservative Criteria in
Operability Procedure.
(10) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with the
licensees failure to follow Station Procedure NOD-QP-31, Operability Determination
Process.
Description. CR 2012-09550 was written on August 17, 2012, to identify that
components associated with Valve HCV-400F-O were beyond their currently
documented service life. This represented a potential operability concern, and the
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operability evaluation associated with this condition report determined that surveillance
testing performed on May 29, 2011, provided a reasonable expectation that the valve
was capable of performing its intended function.
In July 2013, during their review of the licensees assessments of equipment service life
issues, the team reviewed CR 2012-09550. The team determined that the documented
operability evaluation did not provide a reasonable expectation of operability.
Specifically, the surveillance testing the licensee had credited was a refueling
surveillance and had an 18-month periodicity and was now outside of its specified
periodicity and had not been performed since May 2011. Therefore, it no longer
demonstrated operability for the degraded/nonconforming condition being evaluated.
The team informed the licensee of their concern with this valve, and asked if other
components were crediting previously performed surveillance testing as a basis for
operability. The licensee initiated CR 2013-12255 to capture this issue in the stations
corrective action program.
The licensee subsequently determined that Valve HCV-400F-O had been repaired on
April 30, 2013, and revised their operability evaluation to reflect this repair as the basis
for operability of the component.
Analysis. The failure to properly assess and document the basis for operability, when a
degraded or nonconforming condition was identified, was a performance deficiency.
This performance deficiency is more than minor, and therefore a finding, because it is
associated with the equipment performance attribute of the Mitigating Systems
Cornerstone, and affected the cornerstone objective to ensure the availability, reliability,
and capability of systems that respond to initiating events to prevent undesirable
consequences. Since the finding involved an inadequate operability determination while
in a shutdown condition, the team used Manual Chapter 0609, Appendix G, Shutdown
Operations Significance Determination Process, and determined the finding to have
very low safety significance (Green) because the finding did not increase the likelihood
of a loss of reactor coolant system inventory, the finding did not degrade the licensees
ability to terminate a leak path or add reactor coolant system inventory when needed,
and the finding did not degrade the licensees ability to recover decay heat removal once
it was lost. This finding has a cross-cutting aspect in the area of human performance
associated with the decision-making component because the licensee failed to use
conservative assumptions in decision making when performing operability
determinations H.1(b).
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and
Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings. Station Procedure NOD-QP-31, Operability Determination
Process, a procedure used to evaluate the operability of safety-related components,
Step 4.3.15, required the licensee to properly assess and document the basis for
operability when a degraded or nonconforming condition is identified. Contrary to the
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above, on July 8, and July 15, 2013, the licensee failed to properly assess and
document the basis for operability in accordance with prescribed procedures. The
licensee addressed this issue by establishing an adequate basis for operability for the
condition. Because the finding was of very low safety significance (Green) and has been
entered into the corrective action program as CRs 2013-15429 and 2013-14006, this
violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the
NRC Enforcement Policy: NCV 05000285/2013013-10, Failure to Follow Operability
Procedure.
(11) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, associated with the licensees failure to
conduct an adequate evaluation of the impacts of modifying the turbine driven auxiliary
feedwater pump (FW-10) during all modes of operation.
Description. The team noted during their review of NCV 05000285/2010006-01, Failure
to Correct Repeated Tripping of the Turbine-Driven Auxiliary Feedwater Pump FW-10,
that the licensee had instituted an engineering change package to modify the turbine-
driven Auxiliary Feedwater Pump FW-10, from a variable speed to a constant speed.
The team reviewed the adequacy of this modification to ensure that the operation of this
mitigating system component could still perform its intended function as required by the
design and licensing basis.
The purpose of the auxiliary feedwater system is to provide an alternate source of
feedwater to either or both steam generators in the event of a loss of main feedwater.
The original design of the turbine-driven pump included a pneumatic loop controller
which adjusted an actuator, determining the steam inlet throttle valve position (i.e. pump
speed). There is also a mechanical speed-limiting governor which prevents the pump
from damaging itself. Another protective feature of the pump is the backpressure trip
device, which will close the throttle valve if sensed pressure in the steam outlet side is
too high, again preventing pump damage.
The modification to change the pump from a variable speed to a constant speed setting
was completed in 2009 as a corrective action for concerns regarding the reliability of the
pneumatic speed control loop. It set the pump speed on the speed-limiting governor to
approximately 7600 rpm (plus or minus 50 rpm); after the pneumatic loop control system
was removed. The reasoning for this value was based on surveillance test data that
indicated an average pump speed of 7550 rpm, which used a specific value for steam
generator pressure. The pump would start and speed up until it reached the pre-set
governor limit and then stay at the value until steam demand was decreased. This
modification essentially resulted in the governor becoming the speed controlling device
and the backpressure trip device acting as a protective measure if the governor were to
fail. The engineering change package stated that, it is not good practice to control a
steam turbines speed with a single device. However, the overpressure trip system is
credited as backup.
While performing a review of Engineering Change Package 34435, FW-10 Pneumatic
Speed Control Removal, the team noted that the speed limiting governor for the pump
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had been set to 7800 rpm previously. This value allowed FW-10 to provide a discharge
pressure slightly higher than the anticipated peak steam generator pressures. It was
also identified, through a review of design calculation models completed to look at a
potential net positive suction head issue, that values of 7800 to 7900 rpm could be
needed to deliver the required flow under certain scenarios and for specific steam
generator pressures. Similar and higher pump speeds were identified as potentially
being needed for specific scenarios analyzed while having only one steam generator
available and for power uprate system upgrades.
New pump curves were not generated for FW-10 after the constant speed modification
was made to analyze the wide variety of system pressures and flow requirements that
could be needed and encountered during accident scenarios. The system changes
could impact the safe operation of the governor or lead to a scenario where the pump
would operate outside of the response of the governor when the pump was needed.
Station Procedure PED-GEI-3, Preparation of Modifications, Revision 91,
Section 4.10.1, requires, in part, that system level functions shall be described in detail
in the modification package, including modes of operation and methods of performing
those functions, and all applicable performance and loading requirements shall be
identified for each mode of operation. Also, Section 4.10.2, requires, in part, that all
performance requirements, such as flow capacity, minimum temperature or pressure,
and net positive suction head, shall be provided for each mode of operation.
Analysis. The failure to evaluate the effects of modifying the turbine driven auxiliary
feedwater pump from a variable speed to a constant speed for all modes of operation
was a performance deficiency. This performance deficiency was more than minor, and
therefore a finding, because it was associated with the configuration control attribute of
the Mitigating Systems Cornerstone, and affected the cornerstone objective to ensure
the availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Using Inspection Manual Chapter 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power,
dated July 1, 2012, the finding was determined to have very low safety significance
(Green) because it: (1) was not a deficiency affecting the design and qualification of a
mitigating structure, system, or component, and did not result in a loss of operability or
functionality; (2) did not represent a loss of system and/or function; (3) did not represent
an actual loss of function of at least a single train for longer than its allowed outage time,
or two separate safety systems out-of-service for longer than their Technical
Specification allowed outage time; and (4) did not represent an actual loss of function of
one or more non-Technical Specification trains of equipment designated as high safety-
significance in accordance with the licensees maintenance rule program. This finding
has a cross-cutting aspect in the area of human performance associated with the
decision-making component because the licensee failed to use conservative
assumptions in decision making. Specifically, the licensee did not reanalyze the pump
performance parameters to identify any potentially adverse effects of changing the pump
to a constant speed control H.1(b).
Enforcement. 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in
part, that design changes shall be subject to design control measures commensurate
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with those applied to the original design, which includes assuring that applicable
regulatory requirements and the design basis are correctly translated into specifications,
drawings, procedures, and instructions. Contrary to the above, from 2009 through
November 2013, the licensee failed to evaluate the effects of modifying the turbine
driven auxiliary feedwater pump from a variable speed to a constant speed for all modes
of operation. Specifically, the licensee did not reanalyze the pump performance
parameters to determine whether any potentially adverse effects would occur from
changing the pump to a constant speed when it is depended upon to mitigate accidents
and respond appropriately to changes in operating conditions or design basis events.
The licensee adequately addressed this issue by performing a detailed analysis which
determined that the change did not adversely affect the function of the pump. Because
the finding was of very low safety significance (Green) and has been entered into the
stations corrective action program as CR 2013-10465, this violation is being treated as a
non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:
NCV 05000285/2013013-11, Failure to Evaluate the Effects of Modifying the Turbine
Driven Auxiliary Feedwater Pump.
(12) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees
programmatic failure to conduct adequate operating experience reviews for root cause
evaluations in accordance with Station Procedure FCSG-24-4, Condition Report and
Root Cause Evaluation, Revision 5.
Description. Station Procedure FCSG-24-4, Condition Report and Root Cause
Evaluation, states that the purpose of conducting an operating experience review is to
determine whether the same or similar problems have occurred at the Fort Calhoun
Station, and if, internal or industry operating experience was unsuccessful in preventing
the problem. The procedure also states that an operating experience review shall be
conducted in a systematic manner and both internal and external events from various
sources shall be included.
A review of the problem statement to determine if the issue was a repeat event per the
definition in the aforementioned procedure is also required. A repeat event is defined as
a significance Level A condition or event that shares the same or similar root causes as
a previous event. Hence, there is a reasonable expectation that the event should not
have occurred because a previous events corrective actions to prevent recurrence
should have prevented the event from occurring and, as such, it demonstrates that
previous corrective actions to prevent recurrence were either ineffective or missing. If an
issue is determined to be a repeat event then previous root cause corrective actions to
prevent recurrence shall be reviewed to explain why they did not prevent the event, new
corrective actions to prevent recurrence should consider why the previous corrective
actions to prevent recurrence were not effective, and a condition report is generated
describing the problem with the previous root cause(s).
The following were the specific examples associated with this performance deficiency:
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1. During a review of the Equipment Service Life Root Cause Analysis
(CR 2012-09491), it was noted by the team that zero failures were identified
by the licensee from an Equipment and Information Exchange System
(EPIX) search related to the failure of a 94/FSA relay, Model CR120B04022,
which had failed on May 4, 1998. A review of industry operating experience
by the team identified that there were failures related to this type of relay and
that the average lifetime of this relay was 8 years. The team identified a
discrepancy between this average lifespan and the sites assigned corrective
actions to clean and inspect these relays every 10 years and to replace
them every 20 years.
2. The team identified that the external operating experience search conducted
for Root Cause Analysis 2012-08134, Equipment Reliability, was limited to
only Institute of Nuclear Power Operations (INPO) documents. FCSG-24-5
states that, external operating experience includes, but is not limited to,
EPIX, INPO website, vendor bulletins, 10 CFR Part 21 reports, NRC
information notices, etc. The team noted that there were several NRC
generic communications (e.g. Information Notices 2012-06 and 1993-64)
related to equipment reliability that were missed in the operating experience
review.
3. The team identified another example where the external operating
experience search was incomplete. The Design and Licensing Bases
Configuration Control Root Cause Analysis 2013-05570 external operating
experience search omitted significant NRC operating experience (e.g.
NUREG-1275, Volume 14, Causes of Significance of Design-Basis Issues
at U.S. Nuclear Power Plants, and NRC Information Notice 1998-40,
Design Deficiencies Can Lead to Reduced ECCS Pump Net Positive
Suction Head During Design-Basis Accidents) as well as other external
operating experience (e.g. licensee event reports from other plants related to
several design issues including conducting a high energy line break
analysis) that would aid the licensee in assigning corrective actions to
prevent recurrence of the same problems.
4. When reviewing the operating experience section related to repeat events in
CR-2013-5570 for the design and licensing basis root cause analysis the
team identified that although the event was considered a repeat event it was
not assessed in accordance with procedure requirements. Specifically, the
questions posed in Station Procedure FCSG-24-4 that included why did
previous corrective actions to prevent recurrence fail or previous root cause
analyses not identify the issue, how will the new corrective actions to prevent
recurrence fill in the gaps of the old ones, and issue a condition report to
describe the missed opportunities with the previous corrective actions to
prevent recurrence/root cause analyses, were not performed. The root
cause analysis team stated that it was clear, by an operating experience
review, that this issue was preventable but previous corrective actions to
prevent recurrence were never written specific to this issue. The reasoning
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for why previous corrective actions to prevent recurrence were never written
or deficient was not evaluated nor were the operating experience
opportunities that were missed and corrective actions/condition reports were
not generated for these areas.
The team determined that this represented a programmatic failure by the licensee to
conduct adequate operating experience reviews for root cause evaluations.
The team informed the licensee of their concerns and the licensee initiated
CR 2013-14205 to capture this issue in the stations corrective action program for
resolution.
Analysis. The licensees programmatic failure to conduct adequate operating
experience reviews for root cause evaluations was a performance deficiency. This
performance deficiency is more than minor, and therefore a finding, because if left
uncorrected it has the potential to lead to a more significant safety concern. Specifically,
if the licensee does not thoroughly evaluate operating experience to determine whether
the same or similar problems have occurred at the Fort Calhoun Station or within the
industry, then effective corrective actions to prevent the issues from recurring may not
be implemented and an adequate extent of condition and/or generic implications from
the issue may not be identified. This finding was associated with the Mitigating Systems
Cornerstone. Using Inspection Manual Chapter 0609, Appendix G, Shutdown
Operations Significance Determination Process, 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, dated May 25, 2004, this finding was determined to be of
very low safety significance (Green) because finding did not require a quantitative risk
assessment because adequate mitigating equipment remained available. This finding
has a cross-cutting aspect in the area of problem identification and resolution associated
with the operating experience component because the licensee did not use operating
experience information, including vendor recommendations and internally generated
lessons learned, to support plant safety by implementing and institutionalizing operating
experience through changes to station processes, procedures, equipment, and training
programs P.2(b).
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part that activities affecting quality be prescribed by documented
instructions, procedures, or drawings, of a type appropriate to the circumstances and be
accomplished in accordance with these instructions, procedures, or drawings. Contrary
to the above, from December 2012 through August 2013, the licensee failed to complete
activities affecting quality in accordance with prescribed procedures. Specifically, the
licensee failed to follow the requirements of Station Procedure FCSG-24-4, and conduct
adequate operating experience reviews during the performance of several root cause
analyses, which could have prevented the identification and implementation of effective
corrective actions to prevent recurrence. The programmatic aspect of this issue does
not represent an immediate safety concern, and the licensee is developing corrective
actions. Because the finding was of very low safety significance (Green) and has been
entered into the corrective action program as CR 2013-14205, this violation is being
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treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement
Policy: NCV 05000285/2013013-12, Failure to Perform Adequate Operating
Experience Reviews.
(13) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, associated with the licensees failure to fully
incorporate applicable design requirements into the plant design.
Description. During reviews of the licensees design documents, the team noted that the
Fort Calhoun Final Safety Analysis Report and the Updated Safety Analysis Report both
state that the vital switchgear rooms are cooled by a ventilation system that is capable of
maintaining it below the operability requirements of the equipment under all conditions.
However, the licensee had previously determined that the installed auxiliary building
ventilation was not capable of maintaining the vital switchgear rooms temperature under
the design limits and had installed additional cooling units.
The team noted that the additional cooling units were not designated as safety-related
components, and were not capable of functioning during all design events. Therefore,
they were not capable of maintaining the room temperatures under all design
requirements.
The team informed the licensee of their concerns and the licensee initiated
CR 2013-09804 to capture this concern in the stations corrective action program.
The licensee determined that there was existing procedural guidance to open doors and
provide temporary cooling to the vital switchgear rooms if the temperatures approached
design limits or if ventilation was lost. Therefore, the licensee determined that a
nonconforming condition existed, but that a reasonable expectation of operability existed
based on the existing procedural guidance.
Analysis. The failure to fully incorporate applicable design requirements was a
performance deficiency. The performance deficiency was determined to be more than
minor, and therefore a finding, because it affected the design control attribute of the
Mitigating Systems Cornerstone, and it directly affected the cornerstone objective to
ensure availability, reliability, and capability of systems that respond to initiating events
to prevent undesirable consequences. Using Inspection Manual Chapter 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power,
dated July 1, 2012, the finding was determined to have very low safety significance
(Green) because it: (1) was not a deficiency affecting the design and qualification of a
mitigating structure, system, or component, and did not result in a loss of operability or
functionality; (2) did not represent a loss of system and/or function; (3) did not represent
an actual loss of function of at least a single train for longer than its allowed outage time,
or two separate safety systems out-of-service for longer than their Technical
Specification allowed outage time; and (4) did not represent an actual loss of function of
one or more non-Technical Specification trains of equipment designated as high safety-
significance in accordance with the licensees maintenance rule program. This finding
has a cross-cutting aspect in the area of problem identification and resolution,
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associated with the corrective action program component, because the licensee did not
thoroughly evaluate the problem, and consequently, the resolution did not identify the
extent of cause as necessary P.1(c).
Enforcement. 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part,
that measures shall be established to assure that applicable regulatory requirements
and design bases, as defined in 10 CFR 50.2 and as specified in the license application,
for those components to which this appendix applies, are correctly translated into
specifications, drawings, procedures, and instructions. Contrary to the above, from initial
construction until present, measures established by the licensee did not assure that
applicable regulatory requirements and design bases, as defined in 10 CFR 50.2 and as
specified in the license application, for those components to which this appendix applies,
were correctly translated into specifications, drawings, procedures, and instructions.
Specifically, measures established by the licensee did not assure that the vital
switchgear ventilation system was capable of maintaining the rooms temperature below
design requirements under all design requirements. This issue does not represent an
immediate safety concern because the licensee has compensatory measures in place to
maintain room temperatures, and the licensee is developing corrective actions to resolve
this issue. Because this finding was of very low safety significance (Green) and has
been entered into the corrective action program as CR 2013-9804, this violation is being
treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement
Policy: NCV 05000285/2013013-13, Failure to Incorporate Design Requirements for
Switchgear Room Cooling.
(14) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the licensees failure to take adequate
corrective action regarding non-Category I (seismic) piping in the intake structure raw
water vault.
Description. In a letter dated September 27, 1972, the Atomic Energy Commission
(AEC) requested that the licensee determine whether the failure of any non-Category I
equipment could result in flooding or release of chemicals that could jeopardize safe
shutdown of the facility. The licensee was requested by letter, dated
December 10, 1974, to determine whether the failure of any non-Category I equipment
could result in a condition, such as flooding or the release of chemicals, that might affect
the performance of safety related equipment required for safe shutdown of the facility or
to limit the consequences of an accident. The circulating water (CW) and fire protection
(FP) systems were required to be a part of this review. The licensee re-stated in a letter,
dated February 14, 1975, that failure of the circulating water system does not affect
safety related equipment. It did not appear to the team that the licensee evaluated
piping or equipment in the intake structure. Based on the information provided by the
utility, the NRC documented in an safety evaluation, dated February 18, 1978, that the
existing plant design features provided sufficient protection from flooding which could
result from the failure of non-Category I (seismic) system and are, therefore, acceptable.
NRC Inspection Report 05000285/89-50, dated February 20, 1990, documents multiple
NRC concerns regarding loss of the raw water system. Specifically, due to the
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configuration of the installation, the potential for common-mode failure of all four raw
water pumps exists due to flooding vulnerabilities in the room. Leakage in the raw water
header located inside the room or leakage from a system located above the room could
cause the room to fill with water resulting in the loss of all four pumps. These design
concerns were not previously reported to the NRC as discussed above.
A meeting was held as documented by NRC letter to OPPD dated April 9, 1990, to
discuss these specific flooding concerns. OPPD indicated they would review these
issues and identify appropriate corrective actions. Specifically, they would: (1) review
internal flooding as an external event as part of the Individual Plant Examination /
Probabilistic Risk Assessment analysis; (2) review occurrences outside the design basis
and write a procedure to cover such an event; and (3) review the critical crack criterion
and internal flood protection and address these items in the Updated Safety Analysis
Report and/or design basis documentation.
EA90-084, Raw Water Pump Room Internal Flooding, was developed using NRC
Branch Technical Position MEB 3-1 criteria. Postulated failures of piping in the raw
water pump rooms and of the Fire Protection piping above the pump rooms was
evaluated to determine the potential for common-mode failure of all four raw water
pumps. The analysis showed that for the worst-case credible water spray effects, fully
applying branch technical position criteria results in possible scenarios for common-
mode failure of all four raw water pumps from a single postulated pipe failure. The
licensee states they are not committed to Branch Technical Position MEB 3-1.
The team raised a concern to the licensee regarding failure of non-Category I piping and
potential effects on safety related equipment in the intake structure raw water vault. This
concern was documented in CR 2013-05102. The teams specific concern regarding
non-Category I circulating water piping running through the intake structure vault and the
potential effects on the safety related raw water pumps was documented in
CR 2013-10626.
The licensee contended that since EA90-084 analyzed the effects of ruptures from
various sources the condition was acceptable. The team, however, noted that the
stations current licensing basis did not allow for non-seismic interaction with safety
related equipment, other than, as documented in the safety evaluation report issued by
the NRC in 1978. Furthermore it did not appear that the licensee had reported these
potential interaction concerns when originally requested by the Atomic Energy
Commission.
Analysis. The failure to take adequate corrective action regarding non-Category I
(seismic) piping in the intake structure raw water vault is a performance deficiency. The
performance deficiency is more than minor, and therefore a finding, as it is associated
with the design control attribute of the Mitigating Systems Cornerstone and affected the
associated cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences. Using
Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process
for Findings At-Power, dated July 1, 2012, this finding was determined to have very low
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safety significance (Green) because it: (1) was not a deficiency affecting the design and
qualification of a mitigating structure, system, or component, and did not result in a loss
of operability or functionality; (2) did not represent a loss of system and/or function;
(3) did not represent an actual loss of function of at least a single train for longer than its
allowed outage time, or two separate safety systems out-of-service for longer than their
Technical Specification allowed outage time; and (4) did not represent an actual loss of
function of one or more non-Technical Specification trains of equipment designated as
high safety-significance in accordance with the licensees maintenance rule program.
The finding has a cross-cutting aspect in the area of human performance associated
with the decision-making component such that the licensee demonstrates that nuclear
safety is an overriding priority. Specifically that the licensee uses conservative
assumptions in decision making and adopts 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 Part 50, Appendix B, Criterion XVI, Corrective Action, requires,
in part, that measures shall be established to assure that conditions adverse to quality,
such as failures, malfunctions, deficiencies, deviations, defective material and
equipment, and non-conformances are promptly identified and corrected. Contrary to
the above, from February 1975, through the present, the licensee failed to promptly
identify and correct a condition adverse to quality associated with non-Category I
(seismic) piping in the intake structure raw water vault. The licensees corrective actions
for this issue involved isolating and removing the piping. Because the finding was of
very low safety significance (Green) and has been entered in the corrective action
program as CRs 2013-04782, 2013-04956, 2013-09256, 2013-10626, and 2013-22090,
this violation is being treated as an non-cited violation, consistent with Section 2.3.2 of
the NRC Enforcement policy: NCV 05000285/2013013-14, Inadequate Corrective
Action for Non-Seismic Category 1 Piping.
(15) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, associated with the
licensees failure to follow Station Procedure NOD-QP-31, Operability Determination
Process, to adequately assess and document the basis for operability when a
nonconforming condition was identified.
Description. CR 2013-13410 documents an NRC concern regarding seismic class I raw
water piping in the non-seismic service building. The licensees immediate operability
determination concluded that the raw water system was operable but nonconforming
due to being installed in a non-seismic building. The licensee determined that Abnormal
Operating Procedure - 18, Loss of Raw Water, provides guidance for the loss of raw
water and would be used to mitigate the event. Therefore, it was an analyzed event.
The licensee failed to fully assess and document the basis for operability as required by
Station Procedure NOD-QP-31. Specifically, the licensee did not determine the effect of
a ruptured 6 inch stub in the raw water system with respect to the safety function
provided by the raw water system during a design seismic event. The raw water system
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function, during a seismic event, is provided in licensee analysis EA-93-085. This EA
was not discussed in the immediate operability determination.
Additionally, the team determined that the licensees position that having procedures that
mitigate a loss of safety function implies that loosing that particular function has been
analyzed was not correct. Specifically, while the loss of raw water procedure includes
actions to implement in the event that all raw water is lost, this does not mean that the
loss of raw water is within the current licensing basis.
Analysis. The failure to adequately assess and document the basis for operability
regarding seismic raw water piping potentially interacting with the non-seismic service
building is a performance deficiency. The performance deficiency is more than minor,
and therefore a finding, as it is associated with the equipment performance attribute of
the Mitigating Systems Cornerstone and affected the associated cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Using Inspection Manual Chapter 0609,
Appendix A, The Significance Determination Process for Findings At-Power, dated
July 1, 2012, this finding was determined to have very low safety significance (Green)
because it: (1) was not a deficiency affecting the design and qualification of a mitigating
structure, system, or component, and did not result in a loss of operability or
functionality; (2) did not represent a loss of system and/or function; (3) did not represent
an actual loss of function of at least a single train for longer than its allowed outage time,
or two separate safety systems out-of-service for longer than their Technical
Specification allowed outage time; and (4) did not represent an actual loss of function of
one or more non-Technical Specification trains of equipment designated as high safety-
significance in accordance with the licensees maintenance rule program. This finding
has a cross-cutting aspect in the area of problem identification and resolution,
associated with the corrective action program component, because the licensee did not
thoroughly evaluate the problem such that the resolutions address causes and extent of
conditions. This includes properly classifying, prioritizing, and evaluating for operability
and report ability conditions adverse to quality P.1(c).
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and
Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings. Station Procedure NOD-QP-31, Operability Determination
Process, a procedure that is appropriate to the circumstances of evaluating the
operability of safety-related components, Step 4.3.15, required the licensee to properly
assess and document the basis for operability when a degraded or nonconforming
condition is identified. Contrary to the above, on July 8, 2013, the licensee failed to
complete activities affecting quality in accordance with prescribed procedures. The
licensee revised the operability evaluation and established a reasonable basis for
operability. Because the finding was of very low safety significance (Green) and has
been entered into the corrective action program as CRs 2013-13410 and 2013-13634,
this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of
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the NRC Enforcement Policy: NCV 05000285/2013013-15, Lack of an Adequate
Operability Evaluation for Class 1 Raw Water Piping in Non-Class 1 Service Building.
(16) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures and Drawings, involving the
licensees failure to follow procedures when evaluating the impact of the removal of the
motor for raw water Pump B on the intake cell level control during a potential site flood.
Description. The licensee performed an operability determination for Corrective
Action 018 for CR 2011-10302. The operability determination was to evaluate the
operability of plant equipment related to the classification of the intake structure river
sluice gates as non-safety Class III components during the time it would take the NRC
staff to review a license amendment request. This license amendment request would
change the method of intake cell level control during a site flood from throttling the river
sluice gates to use of the modified trash rack blowdown piping in the circulating water
system.
The team reviewed the operability evaluation, and with consultation with the staff of the
Office of Nuclear Reactor Regulation, and concluded the approach used by the licensee
was acceptable until the license amendment was approved. The team further reviewed
the operability determination for its consistency to actual plant configuration. In their
review, the team identified under Section VII, Justification of Decision, that the licensee
noted that raw water Pump AC-10C, would not be available during a flood because it
had a damaged cable jacket that would allow water intrusion into the cable. The team
recalled from a recent plant walkdown that raw water Pump AC-10B was also
unavailable at that time as it had its motor removed for refurbishment.
The team recalled from previous flooding inspections that the licensees procedures
could require two available raw water pumps for intake cell level control. With remaining
raw water Pumps AC-10A and AC-10D available, the licensee met this procedural
condition. The team noted that the procedure for flooding, Procedure AOP-01, Acts of
Nature, guided operators to run only one emergency diesel generator in an effort to
meet a design requirement to maintain a 7-day fuel oil supply on site prior to a flooding
event. Further inspection by the team revealed that raw water Pumps AC-10A and
AC-10D could not be supplied by the same emergency diesel generator and hence to
run raw water Pumps AC-10A and AC-10D, two emergency diesel generators would be
required. Had a flooding event occurred at that time, the licensee could not have
operated the plant within their design and procedures for raw water and diesel generator
operations. Operators would have had to take on-the-spot actions outside their
established procedures which would not have had the benefit of forethought to ensure
other systems design and qualifications were affected. The team did not find any
discussion of this discrepancy in the operability determination.
The team determined that this was not in accordance with Procedure NOD-QP-31,
Operability Determination Process, Revision 44, which required that a positive
determination of operability must be justified, including technical discussion of why the
concern identified does not prevent the item from fulfilling its intended safety function.
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The team considered the failure to address the design conflict in the operability
determination to be a performance deficiency.
This issue did not represent an immediate safety concern and was entered into the
licensees corrective action program as CR 2013-15270.
The team noted that in September 2013, raw water Pump AC-10B was returned to
service and the concern with the operability determination was no longer applicable.
Analysis. The failure to properly assess and document the basis for operability, when a
degraded or nonconforming condition was identified, was a performance deficiency.
This performance deficiency is more than minor, and therefore a finding, because it is
associated with the equipment performance attribute of the Mitigating Systems
Cornerstone and affected the cornerstone objective to ensure the availability, reliability,
and capability of systems that respond to initiating events to prevent undesirable
consequences. Using Inspection Manual Chapter 0609, Appendix A, The Significance
Determination Process (SDP) for Findings At-Power, dated July 1, 2012, the finding
was determined to have very low safety significance (Green) because it: (1) was not a
deficiency affecting the design and qualification of a mitigating structure, system, or
component, and did not result in a loss of operability or functionality; (2) did not
represent a loss of system and/or function; (3) did not represent an actual loss of
function of at least a single train for longer than its allowed outage time, or two separate
safety systems out-of-service for longer than their Technical Specification allowed
outage time; and (4) did not represent an actual loss of function of one or more non-
Technical Specification trains of equipment designated as high safety-significance in
accordance with the licensees maintenance rule program. This finding has a cross-
cutting aspect in the area of human performance associated with the work control
component. Specifically, the team identified that the licensee failed to adequately plan
and coordinate work activities in which interdepartmental coordination was
necessary H.3(b).
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and
Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions, procedures, or drawings, of a type appropriate to the
circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings. Contrary to the above, on June 18, 2013, the licensee failed to
complete activities affecting quality in accordance with prescribed procedures.
Specifically, the operability determination for Corrective Action 018 for CR 2011-10302
was not performed in accordance with Procedure NOD-QP-31, Operability
Determination Process, Step 4.3.15, which required, in part, that, A positive
determination of operability must be justified, includinga technical discussion of why
the concern identified does not prevent the item from fulfilling its intended safety
function(s). This should demonstrate that the item is not exceeding its design basis
specified in the reference documents. The licensee failed to evaluate the impact of
having only two diversely powered available raw water pumps during a site flood on
shutdown cooling system operability. The licensee addressed this issue by establishing
an adequate basis for operability for the condition. Because the finding was of very low
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safety significance (Green) and has been entered into the corrective action program as
CR 2013-15270, this violation is being treated as a non-cited violation consistent with
Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000285/2013013-16,
Inadequate Operability Determination Due to Failure to Consider an Unavailable Raw
Water Pump.
(17) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, associated with the licensees failure to
correctly translate the acceptance limit of intake sluice gate leakage values into
procedures. Specifically, the acceptance limit from the licensees testing was applied to
1000 feet of intake level and not to the 983 to 988 feet operating band prescribed in
Section I - Flooding, of Procedure AOP-01, Acts of Nature.
Description. The team reviewed Section I, Flood, for Abnormal Operating
Procedure AOP-01, Acts of Nature, Revision 37, regarding the method and instructions
for maintaining intake structure cell level. Abnormal Operating Procedure AOP-01
instructed operators in the Instructions or left-hand column of the procedure on how to
accomplish the licensees strategy. The team noted that, per Step 4.3.8G.2 of the
Procedure FCSG-20, Abnormal Operating Procedure and Emergency Operating
Procedure Writer's Guide, Revision 10, that the expected or most likely conditions
appear in the Instructions column. Procedure FCSG-20 further described that
Contingency Actions in the right-hand column should contain guidance for exceptional
circumstances, such as failing to meet an expected condition.
The team ascertained, from review of the right-hand or Instructions column, that the
licensees strategy to maintain intake cell level was to operate one raw water pump with
all river sluice gates closed and throttle the four intake cell flood water inlet valves
(CW-323, CW-324, CW-325, and CW-326), as necessary, to maintain cell level between
983 and 988 feet. Implicit in this strategy is that the leakage of the sluice gates would be
within the capacity of the running raw water pump (or approximately 5325 gallons per
minute) when cell level was in the 983 to 988 feet control band.
The licensee informed the team that sluice gate leakage had been monitored on
May 11, 2013. The team reviewed the data from this leakage check which was
Attachment 4 to the Operability Determination for Corrective Action 018 for
CR 2011-10302. The team observed that, in this attachment, leakage had been
measured and translated to a driving head (river level minus cell level) of 14 feet. The
14 feet value was noted on the attachment to provide additional margin in determining
the acceptability of the in-leakage. On the attachment to the operability determination,
which documented the testing, the sluice gate leakage was deemed acceptable if the
leakage was within the capacity of one raw water pump with a 14 feet driving head for
leakage. The team questioned the 14 feet value because a 14 feet driving head value
would mean that the one running raw water pump could only keep up with the maximum
acceptable sluice gate leakage at a cell level of 1000 feet during a design basis
1014 feet flood.
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The team observed that the design calculation and testing for the station for intake cell
level control was between 1000 and 1014 feet, yet the implementing procedure
instructed operators to control between 983 and 988 feet. Additionally, based on the
results of the May 11, 2013, testing which was within the 1000 feet leakage acceptance
criterion, the licensee had set up a condition where implementation of their AOP-01
procedure for intake cell level control would make the Contingency Actions in the right-
hand column part of the expected spectrum and not exceptional. This condition would
be expected because the observed sluice gate leakage when translated to the
983-988 feet operating band would be in excess of the capacity of one raw water pump.
From this, the team concluded that the licensee had not properly translated the design of
intake cell level control into the implementing procedures. The team determined that this
failure was a performance deficiency.
Analysis. The failure to fully incorporate applicable design requirements was a
performance deficiency. This performance deficiency is more than minor, and therefore
a finding, because it is associated with the design control attribute of the Mitigating
Systems Cornerstone and affected the associated cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Using Inspection Manual Chapter 0609,
Appendix G, Shutdown Operations Significance Determination Process, Attachment 1,
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, dated May 25, 2004, the
team determined that because this finding did not increase the likelihood of a loss of
reactor coolant system inventory; did not degrade the licensees ability to terminate a
leak path or add reactor coolant system inventory, and did not degrade the licensees
ability to recover decay heat removal, this finding did not require a Phase 2 or 3 analysis
as stated in Checklist 4. Therefore, the finding is determined to have very low safety
significance (Green). This finding has a cross-cutting aspect in the area of problem
identification and resolution associated with the corrective action program component
because the licensee did not thoroughly evaluate problems such that the resolutions
address causes and extent of conditions P.1(c).
Enforcement. 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part,
that measures shall be established to assure that applicable regulatory requirements
and the design bases, as defined in 10 CFR 50.2 and as specified in the license
application, for those components to which this appendix applies, are correctly translated
into specifications, drawings, procedures, and instructions. Contrary to the above, from
May 10, 2013, to the present, measures established by the licensee did not assure that
applicable regulatory requirements and the design bases, as defined in 10 CFR 50.2 and
as specified in the license application, for those components to which this appendix
applies, were correctly translated into specifications, drawings, procedures, and
instructions. Specifically, the acceptance limit from the licensees testing was applied to
1000 feet of intake level and not to the 983 to 988 feet design operating band prescribed
in Section I - Flooding, of Procedure AOP-01, Acts of Nature. This issue did not
represent an immediate safety concern. Because the finding was of very low safety
significance (Green) and has been entered into the corrective action program as
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CR 2013-15287, this violation is being treated as a non-cited violation, consistent with
Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000285/2013013-17, Failure to
Translate Design Sluice Gate Leakage Into Operating Procedures.
(18) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensee's
failure to maintain an adequate procedure for site flooding.
Description. The team reviewed Procedure AOP-01, Acts of Nature, Revision 37,
Section I, Flood. Procedure AOP-01,Section I, Step 9.g, directed operators to
maintain intake cell level between 983 and 988 feet by adjusting the four intake cell flood
water inlet valves (CW-323, CW-324, CW-325, and/or CW-326) which were recently
installed on the trash rack blowdown piping as part of a permanent modification.
Step 9.g had a contingency action in the right hand column which contained a
typographical error that led to it being numbered as Contingency Action Step 9.h. The
team pointed out the typographical discrepancy, which was not in accordance with the
licensees abnormal operating procedure writing guidance. Step 9.h.1 detailed the
contingency action to be taken if operators were unable to maintain cell level less than
988 feet.
The team noted that the need for enacting the contingency action for being unable to
maintain cell level less than 988 feet was a plausible condition based on the most recent
measurement by the licensee of sluice gate leakage. The team noted that on
May 11, 2013, the licensee measured the sluice gate leakage to be 2277 gallons per
minute. This measurement was made with a driving head (the difference between river
level and cell level) of 3.36 feet. The team translated this leakage to the driving head for
what would be expected under design flood conditions (1014 feet river level and a
983-988 feet control band) and determined leakage would be greater than 6000 gallons
per minute. This value was greater than the capacity of one raw water pump which was
the operating configuration prescribed earlier in the flooding procedure.
Since level would be expected to exceed 988 feet due to sluice gate leakage, operators
would then close the four intake cell flood water inlet valves (CW-323, CW-324, CW-325,
and CW-326). Contingency Action 9.h.1 would then have the operators close the
isolation valves for the four intake cell flood water inlet valves (CW-327, CW-328,
CW-329, and CW-330). The team concluded that since these valves would only serve
to stop any flow through the trash rack blowdown piping and not the sluice gate leakage,
intake cell level would still not be able to be maintained less than 988 feet and
Contingency Action 9.h.2 would need to be employed.
Contingency Action 9.h.2 instructs operators to start additional raw water pumps until the
water level starts to fall if cell level is not able to be maintained less than 988 feet. The
team concluded that this was a viable strategy to lower water level, but questioned the
lack of specificity, particularly in not delineating qualitative and quantitative acceptance
criteria, in the procedure from that point on to ensure intake cell level would be
adequately maintained. The team noted that a specific level band was not called out
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and direction on how to maintain that level band was not called out (whether by starting
and securing raw water pumps or operating the intake cell flood water inlet valves).
The team, therefore, considered the procedure to be inadequate. Operators placed in
those conditions would have to make an on-the-spot decision on how to proceed without
the benefit of appropriate procedural guidance.
Analysis. The licensees failure to maintain an adequate procedure for maintaining
intake cell level during a flood was a performance deficiency. This performance
deficiency is more than minor, and therefore a finding, because it is associated with the
procedure quality attribute of the Mitigating Systems Cornerstone and affected the
associated cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences. Using
Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance
Determination Process, Attachment 1, 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, dated May 25, 2004, the finding is determined to have very low safety
significance (Green) because: (1) the finding did not increase the likelihood of a loss of
reactor coolant system inventory; (2) did not degrade the licensees ability to terminate a
leak path or add reactor coolant system inventory; and (3) did not degrade the licensees
ability to recover decay heat removal. This finding did not require a Phase 2 or 3
analysis as stated in Checklist 4. This finding has a cross-cutting aspect in the area of
problem identification and resolution associated with the corrective action program
component because the licensee did not thoroughly evaluate problems such that the
resolutions address causes and extent of conditions P.1(c).
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part, that instructions, procedures, or drawings shall include
appropriate quantitative or qualitative acceptance criteria for determining that important
activities have been satisfactorily accomplished. Contrary to the above, prior to
June 20, 2013, the licensee failed to provide instructions, procedures, or drawings which
included appropriate quantitative or qualitative acceptance criteria for determining that
important activities have been satisfactorily accomplished. Specifically, the licensee
failed to include criteria for instructing operators on how to proceed if steps taken to
maintain intake cell level less than 988 feet were unsuccessful. This issue did not
represent an immediate safety concern. Because the finding was of very low safety
significance (Green) and has been entered into the corrective action program as
CR 2013-15289, this violation is being treated as a non-cited violation, consistent with
Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000285/201313-18,
Inadequate Procedure for Intake Cell Level Control During a Flooding Event.
(19) Introduction. The team identified a Green, non-cited violation of License Condition 3.D,
Fire Protection Program, for the failure to translate Appendix R license exemptions into
the fire protection program design. Specifically, the licensee failed to translate the
exemption from 10 CFR Part 50, Appendix R Section III.G that was granted July 3, 1985,
for the intake structure Fire Area 31 into a design that met those exemptions.
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Description. The licensees fire protection program was defined in the Updated Safety
Analysis Report and NRC safety evaluation reports. Section 9.11.1 of the Updated
Safety Analysis Report describes the fire protection system design basis and states, in
part, that the design basis of the fire protection system includes commitments to
10 CFR Part 50, Appendix R, Sections III.G, III.J, and III.O. Section 9.11.4.5 of the
Updated Safety Analysis Report documented that descriptions of plant design and
construction features for the fire protection program were contained in the Fort Calhoun
Station Fire Hazards Analysis and Safe Shutdown Analysis. FHA-EA97-001, Fire
Hazards Analysis (FHA) Manual, Revision 16, Section 8.2.5 stated, in part, that a fire in
Fire Area 31, cable for raw water Pump AC-10B (EB-67, EB-7309, EA-7306, and
EB-7307) have been encased in a 2-inch thick Pyrocrete enclosure located above the
circulating water pumps. In a letter, Request for Exemptions from Various
Requirements of 10 CFR Part 50, Appendix R, Fire Protection Program for Nuclear
Facilities, dated August 30, 1983, under Section III, Fire Area 31, Part B, in Exemption
Request, the licensee states, in part, that the District request an exemption from the
requirements of Section III.G of Appendix R. Specifically, exemption is requested from
the requirements that one pump and associated cables be completely enclosed in a
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> fire barrier enclosure and that complete, area-wide fire detection and suppression
systems be provided for Fire Area 31. In Section (1), of this same section, it states in
part, The components necessary for cold shutdown in this fire area are the raw water
Pumps AC-10A, B, C, and D. Power cables EA66, EB67, EC68, and ED69 for these
pumps are located in this area. A Pyrocrete enclosure has been installed (details of
which were transmitted to the Commission with our July 9, 1979 submittal) to protect the
cables for Pumps AC-10A and AC-10B from any credible fire. The intake structure has
fire detectors but does not have automatic fire suppression, and therefore, does not
meet the requirements of having both fire detection and automatic fire suppression.
Therefore, the licensee applied for an exemption with the above described enclosure
providing protection for both raw water Pumps AC10-A and AC-10B cables.
The NRC in its July 3, 1985 letter to the licensee (NRC-85-200), which references the
August 30, 1983 letter, responded to the license exemption request. In the evaluation
under Intake Structure and Pull Boxes (Fire Area 31) it states in part, In the Intake
Structure, if a fire were to occur at the raw water pumps, it would be detected in its initial
stages by the existing fire detectors. The fire brigade would then be summoned and
would affect fire extinguishment using manual hose stations or portable fire
extinguishers. During the time delay, associated with the arrival of the fire brigade, two
of the pumps would be shielded from the effects of the fire by the concrete wall. In
addition, smoke and heat from the fire would be vented upward and away from the
pumps. Therefore, a complete 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> fire-rated barrier is not necessary to provide
reasonable assurance that at least two pumps will remain free of fire damage. Based
upon the above evaluation, the staff concludes that the existing fire protection provides
an equivalent level of safety to that achieved by compliance with Section III.G.
Therefore, the licensees request for exemption for the intake structure and pull boxes is
granted.
During walk down of the intake structure and review of the cable/conduit routing
drawings associated with the intake structure, inspectors observed that there are two
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pull boxes associated with raw water Pump AC-10B that are enclosed in a pyrocrete
barrier. The pull boxes associated with AC-10B are PB-94T, which contains
cable EB67, the 4.16 kV motor lead cabling for AC-10B and PB-93T, which contains
cables EB7307, EB7309, and EB7314 low voltage control and power leads for discharge
and isolation valves associated with AC-10B. The pull boxes associated with AC-10A
are PB-91T, which contains cable EA66, the 4.16 kV motor lead cabling for AC-10A and
PB-92T. Only one pull box associated with raw water Pump AC-10A is enclosed in a
pyrocrete barrier and that is PB-92T, which contains cables EA7302, EA7306, and
EA7313 that are low voltage control and power leads for discharge and isolation valves
associated with AC-10A. Pull Box 91T, which contains cable EA66, the 4.16 kV motor
lead cabling for AC-10A is not enclosed in the pyrocrete barrier and is also not shown to
be enclosed in the fire barrier on the drawings. The drawings and the in situ equipment
conditions match but neither conforms to the license exemption conditions since the
motor lead cables associated with AC-10A are not enclosed in the pyrocrete barrier, and
therefore, are not protected as stated by OPPD in the August 30, 1983, Request for
Exemption, letter to the Commission.
Analysis. The failure to translate Appendix R license exemptions into the fire protection
program design is a performance deficiency. This performance deficiency was more
than minor, and therefore a finding, because it was associated with the protection
against external factors attribute of the Mitigating Systems Cornerstone and affected the
associated objective to ensure availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. Using Inspection
Manual Chapter 0609, Appendix F, Fire Protection Significance Determination
Process, dated September 20, 2013, Step 1.3, the team determined that the reactor
would have been able to reach and maintain cold shutdown, therefore, this finding was
determined to have very low safety significance (Green). There was no cross-cutting
aspect assigned to this finding because the original license exemption request and grant
was over 3 years ago and this issue does not reflect present licensee performance.
Enforcement. License Condition 3.D, Fire Protection Program, requires, in part, that
the licensee implement and maintain in effect all provisions of the approved Fire
Protection Program as described in the Updated Safety Analysis Report and as
approved in NRC safety evaluation reports. Section 9.11.1 of the Updated Safety
Analysis Report describes the fire protection system design basis and states, in part,
that the design basis of the fire protection systems includes commitments to
10 CFR Part 50, Appendix R, Section III.G. Contrary to the above requirement, from
July 1983 until present, the licensee failed to implement and maintain in effect all
provisions of the approved Fire Protection Program, which included the exemption that
was granted in July 1983. Specifically, the licensee failed to translate Appendix R
exemptions into a fire protection program design that met the requirements of the
exemptions granted. This issue did not represent an immediate safety concern.
Because this violation was of very low safety significance (Green) and has been entered
into the corrective action program as CR 2013-15021, this violation is being treated as a
non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy:
NCV 05000285/2013013-19, Failure to Translate Appendix R License Exemptions into
the Plants Fire Protection Program Design.
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(20) Introduction. The team identified a cited Severity Level IV violation of 10 CFR 50.9,
Complete and Accurate Information, and an associated reactor oversight process
finding (NCV 05000285/2013013-19, Failure to Translate Appendix R License
Exemptions into the Plants Fire Protection Program Design), for the licensees failure to
provide information to the Commission that was complete and accurate in all material
respects.
Description. On February 4, 2008, the licensee submitted a letter, Request for
Exemption from Requirements of 10 CFR Part 50, Appendix R, Section III.G.1.b for Fire
Area 31 at the Fort Calhoun Station, to the Commission requesting an exemption from
the requirements of 10 CFR Part 50, Appendix R, Section III.G.1.b for the intake
structure (Fire Area 31).
This exemption request was meant to address an issue with a previous Appendix R
exemption, and two non-cited violations regarding not having the procedures and
materials available in order to make repairs to cold shutdown equipment within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Specifically, NCV 05000285/2004003-03, Failure to Provide Fire Protection Features for
Components Important to Achieve and Maintain Cold Shutdown, and Example 3 of
NCV 05000285/2005008-06, Failure to Take Prompt Corrective Action for Fire
Protection Program Deficiencies, were issued to the station and while reviewing
NCV 05000285/2005008-06, the licensee determined that the facilities Safety Evaluation
Report, dated July 3, 1985, Exemption Requests for the Fort Calhoun Station, Unit
NO. 1 10 CFR PART 50, Appendix R, Fire Protection Program for Nuclear Power
Facilities Operating Prior to January 1, 1979, incorrectly referenced Section III.G.2 and
subsequently, provided exemption from 10 CFR Part 50, Appendix R, Section III.G.2, for
the cables at the intake structure building and at the auxiliary building pull boxes. The
licensee noted that the requirements of 10 CFR Part 50, Appendix R, Section III.G.2, are
for equipment necessary for hot shutdown and the raw water system is credited to
support cold shutdown functions for post-fire safe shutdown analysis. Therefore,
Section III.G.2 was not applicable to Fire Area 31, and an exemption request needed to
be submitted to request exemption from the requirements of 10 CFR Part 50,
Appendix R,Section III.G.1.b. in lieu of Section III.G.2.
The licensee subsequently requested exemption from 10 CFR Part 50, Appendix R,
Section III.G.1.b and the 72-hour requirement to provide repair procedures and materials
for cold shutdown capability for redundant cold shutdown components, noting that,
OPPD currently has an approved exemption for the cable configuration at the auxiliary
building pull boxes and at the intake structure building. However, the cables between
these locations are not specifically discussed in that exemption. Therefore, this
exemption request is to specifically address the cables in the duct bank and manhole
vaults that are routed between the pull boxes and the intake structure building.
In a teleconference on September 25, 2008, the NRC provided additional clarification to
information that was being sought in review of the request for exemption. The NRC
requested the licensee to, confirm that the pyrocrete enclosures were in place to protect
the cables for raw water Pumps AC-10A and AC-10B from fire in the intake structure
- 95 -
building. This request was based upon information that was provided by OPPD in the
August 31, 1983, letter to the Commission in OPPDs original request for exemption from
Appendix R requirements which stated that, a pyrocrete enclosure has been installed
(details of which were transmitted to the Commission with our July 9, 1979 submittal) to
protect the cables for Pumps AC-10A and AC-10B from any credible fire.
The verbal request was subsequently communicated to the licensee by email
(ML083360264) as a Request for Additional Information (RAI). Request for Additional
Information 3 stated:
Clarify and confirm that the types of combustibles have not changed and total
combustible loading in the intake structure building has not increased, and that
there is no change in active and passive fire protection features as last described
in your letter dated August 30, 1983. If there is a change in the types of
combustibles or there is an increase in combustible load or change in fire
protection features in the intake structure building, the staff requests that the
OPPD provide details and a basis for why the change remains acceptable. Also
confirm that the pyrocrete enclosure is in place to protect the cables for raw
water Pumps AC-10A and AC-10B from fire in the intake structure building.
On October 13, 2008, the licensee submitted a letter, Response to Request for
Additional Information Concerning Exemption from Requirements of 10 CFR Part 50,
Appendix R,Section III.G.1.b. for Fire Area 31 at the Fort Calhoun Station, to respond
to the request for additional information documented in ML083360264. The licensees
response to Request for Additional Information 3 stated, in part:
The pyrocrete enclosure remains in place to protect cables associated with
AC-10A and AC-10B from a fire in the intake structure. This enclosure is
inspected by a fire barrier surveillance test on an 18-month interval.
In a letter dated February 6, 2009, Fort Calhoun Station, Unit NO.1 - Exemption From
the Requirements of 10 CFR Part 50, Appendix R, Section III.G.1.b, the NRC granted
an exemption from the specific requirements of Section III. G.1.b of 10 CFR Part 50,
Appendix R, for the Fort Calhoun Station based upon its review and evaluation of the
information provided in the licensees exemption request and response to NRC staff
request for additional information questions.
While performing a walk down of the intake structure the team observed that Pull
Box 91T, which contains the 4.16 kV motor leads for Pump AC-10A, was not protected
by a pyrocrete enclosure like the 4.16 kV motor leads for Pump AC-10B. Therefore, only
raw water Pump AC-10B is protected from a fire in the intake structure.
Analysis. The failure to provide the NRC with complete and accurate information when
responding to a request for additional information was a performance deficiency. Using
Inspection Manual Chapter 0612, Appendix B, Issue Screening, Figure 1, dated
September 7, 2012, the team determined that the failure to provide complete and
accurate information was a performance deficiency that required evaluation under both
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traditional enforcement and the reactor oversight program. The performance deficiency
was determined to be more than minor because: (1) the information was considered
material to the NRCs decision making process; and (2) it affected the equipment
performance attribute of the Mitigating Systems Cornerstone with regard to availability,
reliability, and capability of the raw water pumps to perform their safety function during a
fire in the intake structure. Using Inspection Manual Chapter 0609, Appendix F, Fire
Protection Significance Determination Process, the team determined the finding to have
very low safety significance (Green) because it only affected the ability to reach and
maintain cold shutdown conditions. Under the traditional enforcement review, the team
determined that in accordance with Section 6.9.c.1 of the NRC Enforcement Policy, this
finding represented a Severity Level III violation. Specifically, the team determined that
if this information had been completely and accurately provided, it would likely have
caused the NRC to undertake a substantial further inquiry. The NRC takes the issue of
complete and accurate license submittals very seriously. For this reason, the NRC
considered citing this as a Severity Level III violation, as discussed in the Enforcement
Policy, since the NRC had approved a licensing action based on the incorrect
information. However, after consideration by NRC management, and with the approval
of the Director of the Office of Enforcement, it was determined that a Severity Level IV
cited violation was appropriate. This decision was based on the very low safety
significance (Green) of the associated reactor oversight process finding
(05000285/2013013-19). There was no cross-cutting aspect assigned to this finding
because the inaccurate information was provided over three years ago and this issue
does not reflect present licensee performance.
Enforcement. 10 CFR Part 50.9, "Completeness and Accuracy of Information," requires,
in part, that information provided to the NRC by a licensee shall be complete and
accurate in all material aspects. Contrary to the above, the licensee responded to an
NRC request for additional information in a letter dated October 13, 2008, with
information that was not complete and accurate in all material respects. Specifically, the
licensee stated that the pyrocrete enclosure remains in place to protect the cables
associated with AC-10A and AC-10B from a fire in the intake structure when, in fact, the
motor lead cables associated with raw water Pump AC-10A are not enclosed in the
pyrocrete enclosure. This violation was entered into the corrective action program as
CR 2013-15021. VIO 05000285/2013013-20, Failure to Provide Complete and
Accurate Information to the NRC.
(21) Introduction. The team identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees
failure to document the extent of condition review for a number of root cause analyses in
accordance with corrective action program procedures. Specifically, during the course
of the inspection, the team identified four examples where the licensee did not follow
Station Procedure FCSG-24-4, Condition Report and Cause Evaluation, and as a
result did not evaluate the extent to which the actual conditions existed with other plant
processes, systems, equipment, or human performance related activities.
Description. The team identified several instances where the licensee did not follow the
corrective action program Station Procedure FCSG-24-4, Condition Report and Cause
- 97 -
Evaluations. Specifically, the team identified four root cause analyses where the
licensee did not identify other applicable plant processes, systems, equipment, or human
performance related activities where the actual condition of the problem statement could
exist. Since the extent of condition review is supposed to identify further deficiencies,
and since corrective actions shall be planned to resolve those additional deficiencies (in
accordance with Station Procedure FCSG-24-4), the licensee did not enter them into the
corrective action program to ensure timely correction.
The following is a summary of the identified performance deficiencies with the
references to the specific sections of the report where the issues are further described.
1. In RCA 2013-05570, Design and Licensing Bases Configuration Control, the
licensees extent of condition review did not provide sufficient in-depth analysis
and did not list the processes encompassed by the design and licensing bases.
The team noted that since other processes are significantly impacted by this
problem, including them as part of the review would have generated corrective
actions associated with each specific process. For instance, processes such as
operability determination, 50.59 Reviews, configuration control (tagging), design,
vendor modifications, work control, Surveillance program, preventive
maintenance process, and nondestructive examination would be impacted by the
licensees failure to maintain adequate configuration control of the structures,
systems, components or activities, in accordance with, 10 CFR Part 50,
Appendix B.
2. In RCA 2013-02857, "HELB/EEQ Not in Accordance with 10 CFR 50.59, the
same-same review, which is part of the extent of condition review, consisted of
other engineering programs at Fort Calhoun Station that are required by the
Code of Federal Regulations (CFR) to be maintained current. The team noted
that the RCA included some of the programs that were required to be maintained
per the CFR but did not include 10 CFR Part 50, Appendix B, programs such as
Nuclear Oversight, Quality Control, or commercial grade dedication programs.
Since these programs require significant engineering and technical reviews, and
are CFR required programs that needs to be maintained current, these were
programs that should have been incorporated into the extent of condition review.
3. In RCA 2013-01796, "Unanalyzed Small Bore Piping Supports RCA," the similar-
similar review, which is part of the extent of condition review, consisted of safety
and non-safety related large bore piping. The licensee stated that the reason for
concluding, that there is no extent of condition, was that large bore piping at Fort
Calhoun Station was designed by computer analysis and not the generic
nomograph and eyeball method. Additionally, the licensee stated that this
piping was verified by inspection in response to IEB 79-14. The team noted that,
based on the errors identified in previous engineering assumptions and
calculations, the issues identified in the area of design and licensing basis
maintenance and corrective action program root cause, as well as issues
documented regarding thermal and cyclical fatigue analysis on Class I and II
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piping, that large bore piping would have also been impacted in the extent of
condition review.
4. In RCA 2012-01947, Containment Integrity Issues with Electrical Penetration
Assemblies Containing Teflon, the licensee did not perform a timely extent of
condition review. Specifically, the extent of condition review associated with
containment electrical penetrations with Teflon was performed, but was delayed
due to core reload priorities.
Analysis. The failure to follow the requirements of Station Procedure FCSG-24-4, when
documenting extent of condition reviews in multiple root cause analyses, was a
performance deficiency. The performance deficiency was more than minor, and
therefore a finding, because if left uncorrected the failure to perform extent of condition
reviews could lead to a more significant safety concern. Specifically, the failure to
identify and address additional conditions adverse to quality in the extent of condition
review, has the potential to lead to a failure to recognize potentially degraded and non-
conforming equipment in a timely manner. This finding was associated with the
Mitigating Systems Cornerstone. Using Inspection Manual Chapter 0609, Appendix G,
Shutdown Operations Significance Determination Process, Checklist 4, PWR
Refueling Operation: RCS level >23 or PWR Shutdown Operation with Time to Boil > 2
hours and Inventory in the Pressurizer, dated May 25, 2004, the team determined that
the finding was of very low safety significance (Green) because the finding did not
require a quantitative risk assessment because adequate mitigating equipment remained
available. The team determined the Green finding had a cross-cutting aspect in the area
of problem identification and resolution because the licensee failed to thoroughly
evaluate problems such that the resolutions address the causes P.1(c).
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and
Drawings, requires, in part, that activities affecting quality shall be prescribed by
documented instructions, procedures, or drawings of a type appropriate to the
circumstances and shall be accomplished in accordance with these instructions,
procedures, or drawings. Contrary to the above, in three instances in 2013 and one
instance in 2012, the licensee failed to follow the corrective action program Station
Procedure FCSG-24-4, Condition Report and Cause Evaluations. Specifically, the
team identified four instances where the licensee, during the extent of condition review,
did not identify other applicable plant processes, systems, equipment, or human
performance-related activities where the actual condition of the problem statement in the
root cause analysis could exist. The licensee has entered these issues into their
corrective action program under several condition reports as described in this report.
Because this finding was determined to be of very low safety significance and has been
entered into the licensees corrective action program, this performance deficiency is
being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC
Enforcement Policy: NCV 5000285/2013013-21, Failure to Perform Adequate Extent of
Condition Reviews.
(22) Introduction. The team identified a unresolved item associated with
Calculation FC07234, Evaluation of Shutdown Cooling Mode Temperature and
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Pressure Increase on the SI System Piping and Pipe Supports. Specifically, the team is
concerned with the methods used in the calculation which utilize ASME Section III
requirements, but the plant is licensed to USAS B31.7 1968. In addition, the station is
licensed to use, Alternate Seismic Criteria Methodologies (ASCM), but additional
evaluation is required if a support or anchor is displaced more than 1/16 of an inch per
the SER issued by the NRC and Calculation FC07234 only performed an evaluation
when displacement exceeded 1/8 of an inch, per criteria established by a vendor
memorandum.
Description. The Fort Calhoun Stations original code of record for safety-related piping
is USAS B31.7, Nuclear Power Piping, 1968 Draft Edition. The licensee reclassified a
number of systems and piping in the early 1990s. In addition, because of the
reclassification of some Class I piping to Class II piping, fatigue analysis was not
performed on some safety related systems. The licensee reconciled the code of
construction for some safety related systems to newer ASME Section III code, which
requires a fatigue analysis for Class II piping, but because the plant is licensed to
USAS B31.7, no analysis was completed. The NRC issued a safety evaluation allowing
the Fort Calhoun Station to utilize alternate seismic monitoring criteria (ASCM) but
stated additional evaluation was required if a support is displaced more than 1/16 of an
inch. This safety evaluation was issued in April 1993.
The team reviewed Station Calculation FC07234, Evaluation of Shutdown Cooling
Mode Temperature and Pressure Increase on the SI System Piping and Pipe Supports,
and noted that a vendor had performed this calculation utilizing criteria that deviated
from the ASCM acceptance criteria. Specifically, the vendor used one of their internal
memoranda, dated May 1979, to accept support displacement not exceeding 1/8 of an
inch without evaluating the deviation as required by the ASCM safety evaluation. In
addition, Station Calculation FC07234 identified some piping support stress allowables
that were exceeded and needed additional vendor evaluation, but the only vendor
evaluation noted was an email, with no justification or explanation why the loading on the
SI-1A/B pumps and nozzles were acceptable. There were additional supports that
exceeded their stress allowables but no additional evaluation is noted in the calculation.
Additional information is required to determine if Station Calculation FC07234 is
adequate and fully supports operability evaluations for SI-1A/B pumps (High Head
Safety Injection) and nozzles, AC-4A/B heat exchanger (Shutdown Cooling Heat
exchangers) supply lines, high pressure safety injection and accumulator discharge
piping, and the wall penetration bellows shown on Drawing IC-189. In addition, the open
question regarding Class I and II reclassification that occurred in the 1990s needs to be
reviewed to ensure that the right classification is applied to the Class I systems and that
all of the thermal fatigue analysis, that is required, is completed.
Additional NRC inspection is necessary to determine if Station Calculation FC07234 is
adequate. The team considered this to be an unresolved item,
URI 05000285/2013013-22, Shutdown Cooling Piping and Pipe supports
Calculation Has Incorrect Acceptance Criteria for Anchor Displacement.
- 100 -
4OA6 Meetings, Including Exit
Exit Meeting Summary
On September 20, 2013, the team presented the inspection results in an on-site debrief to
Mr. Louis P. Cortopassi, Vice President and Chief Nuclear Officer, and other members of the
licensee staff. The licensee acknowledged the issues presented.
On February 18, 2014, the team presented the inspection results by conference call to
Mr. Terrance Simpkin, Manager, Site Regulatory Assurance, and other members of the licensee
staff. The licensee acknowledged the issues presented.
The team acknowledged that some of materials examined during the inspection were
considered proprietary and controlled accordingly.
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SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
J. Adams, Principle Engineer Design Engineering (Retired Supplemental Worker)
D. Bakalar, Manager, Site Security
W. Beck, Exelon, Quad Cities RAM
J. Bonsum, EPM
B. Cable, Nuclear Safety Culture Coordinator
C. Cameron, Supervisor Regulatory Compliance
J. Cate, Supervisor, Nuclear Engineering
L. Cortopassi, Site Vice President
D. Digiacinto, Senior Nuclear Design Engineer Electrical/I&C
M. Doghman, VP Energy Delivery
K. Erdman, Supervisor, Engineering Programs
M. Ferm, Manager, Site Performance Improvement
M. Frans, Manager, Engineering Programs
R. Gaston, Licensing Manager
M. Greeno, NRC Inspection Readiness Team Contractor
R. Hall, GNJ Recovery Director
W. Hansher, Supervisor, Nuclear Licensing
R. Haug, Senior Consultant
M. Hirschfeld, Senior Organization Development Consultant
K. Ihnen, Manager, Manager, Site Nuclear Oversight
R. Hugenroth, Supervisor, Nuclear Assessments
J. James, Manager, Outage
R. King, Director, Site Maintenance
K. Kingston, Chemistry Manager/Nuclear Safety Culture Advocate
J. Kuzela, Control Room Supervisor
J. Lindsey, Training Director
T. Maine, Manager, Radiation Protection
T. Masne, RPM
E. Matzke, Senior Licensing Engineer
J. McManis, Manager, Projects
S. Miller, Manager, Design Engineering
V. Naschansy, Director, Site Engineering
B. Obermeyer, Manager, CAP
P. ONeil, Senior Consultant, NWI Consulting, Inc.
T. Orth, Director, Site Work Management
A. Pallas, Manager, Shift Operations
M. Prospero, Division Manager, Plant Operations
J. Rainey, Human Resources Business Partner
B. Rash, Recovery Lead
K. Root, Regulatory
-1- Attachment 1
R. Short, Manager, Recovery
T. Simpkin, Manager, Site Regulatory Assurance
M. Smith, Manager, Operations
S. Swanson, Operations Director
K. Wells, Nuclear Design Engineer Design Electrical/I&C
J. Wiegand, Manager, Operations Support
G. Wilhelmsen, Exelon Nuclear Partners
J. Zagata, Reliability Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000285/2013013-20 NOV Failure to Provide Complete and Accurate Information to the
NRC (Section 4OA4)05000285/2013013-22 URI Shutdown Cooling Piping and Pipe Supports Calculation Has
Incorrect Acceptance Criteria for Anchor Displacement
(Section 4OA4)
Opened and Closed
05000285/2013013-01 NCV Failure to Complete all Testing for a Condition Adverse to
Quality (Section 4OA4)05000285/2013013-02 NCV Failure to Furnish Evidence of an Activity Affecting
Quality(Section 4OA4)05000285/2013013-03 NCV Failure to Evaluate Changes to Ensure They Did Not Require
Prior Approval (Section 4OA4)05000285/2013013-04 NCV Failure to Submit Licensee Event Report (Section 4OA4)05000285/2013013-05 NCV Inadequate Corrective Actions to Prevent Repetition of a
Significant Condition Adverse to Quality, a White MSPI SSFF
Degrading Trend (Section 4OA4)05000285/2013013-06 NCV Failure to Control Deviations From the Design Basis
Requirements for Structural Calculations Related to the
Reactor Coolant System (Section 4OA4)05000285/2013013-07 NCV Programmatic Failure to Evaluate Safety Impact of Degraded
Conditions During Use of Interim Operability Criteria
(Section 4OA4)05000285/2013013-08 NCV Failure to Correct Overstressed Components (Section 4OA4)05000285/2013013-09 NCV Non-conservative Criteria in Operability Procedure
(Section 4OA4)05000285/2013013-10 NCV Failure to Follow Operability Procedure (Section 4OA4)
-2-
Opened and Closed
05000285/2013013-11 NCV Failure to Evaluate the Effects of Modifying the Turbine Driven
Auxiliary Feedwater Pump (Section 4OA4)05000285/2013013-12 NCV Failure to Perform Adequate Operating Experience
Reviews(Section 4OA4)05000285/2013013-13 NCV Failure to Incorporate Design Requirements for Switchgear
Room Cooling (Section 4OA4)05000285/2013013-14 NCV Inadequate Corrective Action for Non-Seismic Category 1
Piping (Section 4OA4)05000285/2013013-15 NCV Lack of an Adequate Operability Evaluation for Class 1 Raw
Water Piping in Non-Class 1 Service Building (Section 4OA4)05000285/2013013-16 NCV Inadequate Operability Determination Due to Failure to
Consider an Unavailable Raw Water Pump (Section 4OA4)05000285/2013013-17 NCV Failure to Translate Design Sluice Gate Leakage Into
Operating Procedure (Section 4OA4)05000285/2013013-18 NCV Inadequate Procedure for Intake Cell Level Control During a
Flooding Event (Section 4OA4)05000285/2013013-19 NCV Failure to Translate Appendix R license Exemptions into the
Plants Fire Protection Program Design (Section 4OA4)05000285/2013013-21 NCV Failure to Perform Adequate Extent of Condition Reviews
(Section 4OA4)
Closed
05000285-2012-002-00 LER Inadequate Qualifications for Containment Penetrations
Renders Containment Inoperable
05000285-2012-006-00 LER Operation of Component Cooling Pumps Outside of the
Manufacturers Recommendation
05000285-2012010-01 LER Fire Causes a Circuit Breaker to Open Outside Design
Assumptions
05000285-2012-016-00 LER Unanalyzed Charging System Socket Welds to the Reactor
Coolant System
05000285-2012-018-00 LER Containment Air Cooling Units Operated Outside of Technical
Specification during Cycle 26
05000285-2013-006-00 LER Low Pressure Safety Injection and Containment Spray Pumps
Mechanical Seals05000285/2012010-01 VIO Failure to Ensure that the 480 Vac Electrical Power
Distribution System Design Requirements were Implemented
and Maintained
-3-
Closed
05000285-2012-002-00 LER Inadequate Qualifications for Containment Penetrations
Renders Containment Inoperable
05000285-2012-006-00 LER Operation of Component Cooling Pumps Outside of the
Manufacturers Recommendation
05000285/2012007-02 VIO Failure to Maintain Command and Control Function During
Fire Fighting Activities in the Protected Area
05000285/2012004-04 VIO Failure to Ensure Breaker Coordination of 480 VAC Electrical
Power Distribution System Was Maintained
LIST OF DOCUMENTS REVIEWED
Section 4OA4: IMC 0350 Inspection Activities (92702)
PROCEDURES
NUMBER TITLE REVISION / DATE
NOD-QP-28 Safety Enhancement Program
PED-QP-13 Design Basis Document Control
PB-1 Writers Guide for Plant Level Design Basis
Documents
SG-1 Writers Guide for System Design Basis Documents
QAM-12 Quality Assurance Audit Scheduling
SO-G-21 Modification Control
PAP Procedure Administration Program
NPM-1.00 Nuclear Safety 5
NPM 2.04 Establishing and Maintaining a Safety Conscious 4
Working Environment
NPM 2.04 Establishing and Maintaining a Safety Conscious 5
Working Environment
FCSG-62 Site Nuclear Safety Culture Process 5
TBD-EPIP-OSC-1A Recognition Category A, Abnormal Rad 2
Levels/Radiological Effluent
EPIP-EOF-6 Dose Assessment 46
PBD-19 Electrical Equipment Qualification Program 4
PED-QP-15 Electrical Equipment Qualification Program 12
-4-
PROCEDURES
NUMBER TITLE REVISION / DATE
00314218-01 Flow Path Verification of Auxiliary Feedwater December 11, 2009
System
IC-CP-01-1368 Calibration of Auxiliary Feedwater Pump FW-6 13
Flow Loop F-1368
IC-CP-01-1369 Calibration of Auxiliary Feedwater Pump FW-10 10
Flow Loop F-1369
OP-ST-AFW-3009 Auxiliary Feedwater Pump FW-6 Steam Isolation 21
Valve, and Check Valve Tests
OP-ST-AFW-3011 Auxiliary Feedwater Pump FW-10 Steam Isolation 14
Valve, and Check Valve Tests
AOP-30 Emergency Fill of Emergency Feedwater Storage 11
Tank
MGT-12-10 Safety Conscious Work Environment Training September 2012
Slides
MGT-12-12 Safety Conscious Work Environment Training Fall 2012
Slides
SE-ST-FW-3002 Feedwater Check Valves FW-161 and FW-162 12a
Reverse Flow Test
SO-M-101 Maintenance Work Control 96
SO-O-25 Temporary Modification Control 81
NOD-QP-19 Cause Analysis Program 43
EM-PM-EX-1200 Inspection and Maintenance of Model AKD-5 Low 17
Voltage Switchgear
EM-PM-EX-1201 Inspection and Maintenance of Model AKD-5 Low 0
Voltage Switchgear 1B4A
EM-PM-EX-0201 NLI Masterpact NW Circuit Breaker Inspection 20
EM-RR-EX-0203 Receipt Inspection of 480-Volt Square D/NLI 0
Masterpact Type NW/NT Breakers/Cradles
EM-CP-05-1B4A-1 Calibration of Component Cooling Water Pump 14
AC-3B Circuit Breaker
EM-PM-EX-0205 NLI Masterpact NT Circuit Inspection 1
EM-CP-05-1B4A-2 Calibration Procedure R10
-5-
PROCEDURES
NUMBER TITLE REVISION / DATE
EM-CP-05-1B4A-3 Calibration Procedure Calibration of the Auxiliary R10
Building MCC-4A2 Feeder Breaker
EM-CP-05-1B4A-4 Calibration Procedure Calibration of Condenser R13
Vacuum Pump FW-8B Circuit Breaker
EM-CP-05-1B4A-5 Calibration Procedure Calibration of Screen Wash R11
Pump CW-3B Circuit Breaker
EM-CP-05-1B4A-6 Calibration Procedure Calibration of the Security R9
Building Panel MS Feeder Breaker Located in
Cubicle 1B4A-6
EM-CP-05-1B4A Calibration of the Main Circuit Breaker Located in 14
Cubicle 1B4A
EM-CP-05-BT- Calibration of 480 VAC Tie Breaker Located in 12
1B4A Cubicle BT-1B4A
ERPG-EAG-01 Engineering Recovery Process Guide - 0
Engineering Assurance Group
PED-GEI-2 Preparation of Procurement Specifications 16
PED-GEI-3 Preparation of Modifications 87
PED-GEI-7 Specification of Post Modification Test Criteria 15
PED-GEI-28 Preparation of Construction Work Orders 28
PED-GEI-29 Preparation of Facility Changes 55
PED-GEI-35 Preparation of Minor Configuration Changes 66
PED-GEI-52 Preparation of Field Design Change Requests 13
PED-GEI-60 Preparation of Substitute Replacement Items 45
PED-EWP-9 Testing of Control Circuits 0
FCSG-24-2 Evidence Quarantining 2
FCSG-24-5 Cause Evaluation Manual 5
FCSG-24-4 Condition Report and Cause Evaluation 3
FCSG-24-4 Condition Report and Cause Evaluation 5
NOD-QP-19 Cause Analysis Program 43
EM-ST-EE-0005 Capacity Discharge Test for Station Battery No. 1 23,25
(EE-8A)
-6-
PROCEDURES
NUMBER TITLE REVISION / DATE
FCSG-24-1 Condition Report Initiation 3
FCSG-24-3 Condition Report Screening 6a
FCSG-24-4 Condition Report and Cause Evaluation 6a
FCSG-24-5 Cause Evaluation Manual 5
SO-R-2 Condition Reporting and Corrective action 53b
FCSG-65-7 Program Restart Readiness 1
FCSG-65-8 Department Restart Readiness 2
NOD-QP-3 10 CFR 50.59 and 10 CFR 72.48 Reviews 35
NOD-QP-31.5 Degraded and Non-Conforming Evaluation 0
NOD-QP-38 Employee Concerns 9
NOD-QP-38 Employee Concerns 10
NOD-QP-X Resolution of Differing Opinions 0
OI-AFW-4 Operating Instruction Auxiliary Feedwater Startup 78
and System Operation
OP-ST-CCW-3002 AC-3A Component Cooling Water Pump Inservice 22
Test
OP-ST-AFW-0004 Surveillance Test Auxiliary Feedwater Pump FW- 31
10 Operability Test
PED-GEI-3 Preparation of Modifications 91
SE-ST-CCW-3002 CCW Pump Baseline Curve Procedure 10
SO-G-21 Modification Control 96
SO-R-1 Reportability Evaluation Checklist 20
SO-G-23 Surveillance Test Program 59
ENGINEERING ANALYSIS
NUMBER TITLE REVISION
EA-FC-06-032 Environmental Parameters for Electrical Equipment 0
Qualification
EA-FC-10-020 Electrical Equipment Qualification Radiation Dose 0
Reconstitution Analysis
-7-
ENGINEERING ANALYSIS
NUMBER TITLE REVISION
EA-11-037 Summary of Design Basis Reconstitution for High Energy 0
Line Break (HELB) Outside of Containment in Response
to CR 2007-3407
EA-FC-08-023 Vortexing in Safety-Related Tanks 14
EA-12-024 Determination of Design Temperature for Elastomers in
Valves HCV-107A and HCV-1108A
ACASR 2012- Apparent Cause Evaluation-potential Elastomer Failure 1
08621 During a design Basis Accident for Valves HCV-238,
HCV-239, and HCV-240
EA-FC-12-005 Harsh-mild Environment Threshold Criteria 0
EA-FC-12-0125 Electrical Penetration Feedthrough Classification and 0
Qualification of Non-EEQ Penetration Feedthroughs
CONDITION REPORTS
NUMBER
2005-04735 2005-04735-003 2005-04735-014 2006-06036 2007-02622
2007-03407 2007-02554 2008-04611 2009-02197 2009-04327
2009-05356 2009-06233 2009-00905 2009-05912 2009-04579
2009-05780 2009-02308 2009-04569 2009-01611 2009-12442
2009-05270 2009-05439 2009-05541 2009-05170 2009-04860
2009-06371 2009-06424 2009-05269 2009-04552 2009-06234
2010-04492 2010-03723 2010-00199 2010-01704 2010-01403
2010-04668 2010-00813 2011-08951 2011-00451 2011-08238
2011-05777 2011-07654 2011-00334 2011-06910 2011-07306
2011-01719 2011-02860 2011-06344 2011-07816 2011-09924
2011-02400 2011-08019 2011-09384 2011-09855 2011-01941
2011-06621 2011-05414 2011-02069 2012-08129 2012-08131
2012-04900 2012-03057 2012-03701 2012-04484 2012-04681
2012-10935 2012-05926 2012-06246 2012-06514 2012-10625
2012-13416 2012-10941 2012-10953 2012-12175 2012-14747
2012-13417 2012-02539 2012-13418 2012-13334 2012-13419
2012-08133 2012-11806 2012-13420 2012-13421 2012-13243
2012-03967 2012-11816 2012-12067 2012-02580 2012-11805
2012-11804 2012-11941 2012-11986 2012-04452 2012-07902
-8-
CONDITION REPORTS
NUMBER
2012-11982 2012-04169 2012-04280 2012-04444 2012-04467
2012-04490 2012-04536 2012-04602 2012-04903 2012-03986-019
2012-04262 2012-04262-021 2012-04662 2012-04262-022 2012-04262-023
2012-18336 2012-04262-055 2012-04262-058 2012-18336-001 2012-03986
2012-12443 2012-08123 2012-18338 2012-04899 2012-12378
2012-17353 2012-08129 2012-08124 2012-00451 2012-09494
2012-09112 2012-17354 2012-17355 2012-04594 2012-08137
2012-12044 2012-07112 2012-08642 2012-09111 2012-08123
2012-12430 2012-12305 2012-11986 2012-11987 2012-11994
2012-17352 2012-11982 2012-04662 2012-17362 2012-17353
2012-17572 2012-18336 2012-17361 2012-12460 2012-12547
2012-08142 2012-05580 2012-18338 2012-03254 2012-03974
2012-01541 2012-01910 2012-02723 2012-05134 2012-05509
2012-04132 2012-04516 2012-04850 2012-06452 2012-008621
2012-05569 2012-05846 2012-01640 2012-13620 2012-13694
2012-08684 2012-13299 2012-13306 2012-14517 2012-14736
2012-13919 2012-14045 2012-14464 2012-15218 2012-15440
2012-14800 2012-15116 2012-15215 2012-15690 2012-15696
2012-15441 2012-15666 2012-15687 2012-15747 2012-15750
2012-15697 2012-15703 2012-15721 2012-15805 2012-15844
2012-15755 2012-15758 2012-15770 2012-16038 2012-16145
2012-16023 2012-16025 2012-16030 2012-8851 2012-20806
2012-16171 2012-15399 2012-15750 2012-02534 2012-02881
2012-02026 2012-02115 2012-02498 2012-03805 2012-08521
2012-02947 2012-03397 2012-03796 2012-08737 2012-09179
2012-08522 2012-08526 2012-08528 2012-10477 2012-11874
2012-09196 2012-09494 2012-10206 2012-14958 2012-15721
2012-16900 2012-17447 2012-17717 2012-18345 2012-18347
2012-18675 2012-18793 2012-19477 2012-19769 2012-20128
2013-03056 2013-04037 2013-04034 2013-00730 2013-02202
2013-04167 2013-04286 2013-04223 2013-04032 2013-04033
2013-01396 2013-02278 2013-02557 2013-04504 2013-05026
2013-02710 2013-04141 2013-04442 2013-02611 2013-04680
2013-04806 2013-05018 2013-05026 2013-04547 2013-06267
-9-
CONDITION REPORTS
NUMBER
2013-05515 2013-05569 2013-05693 2013-05276 2013-05668*
2013-10507 2013-04937 2013-05663* 2013-05018 2013-05497*
2013-04934* 2013-04518* 2013-00907 2013-05674 2013-04377*
2013-01186 2013-00195 2013-03529 2013-01073 2013-01143
2013-03866 2013-01187 2013-03943 2013-03639 2013-03798
2013-04163 2013-03928 2013-04288 2013-04001 2013-04126
2013-04635 2013-04186 2013-05191 2013-04416 2013-04627
2013-05501 2013-04748 2013-05630 2013-05205 2013-05230
2013-00187 2013-03242 2012-08130 2013-05570 2013-05026
2013-12498 2012-08675 2013-12498 2013-14475 2010-1375
2010-0813 2012-08134 2013-14466 2009-2306 2013-14458
2009-3437 2010-5140 2013-02944 2013-02953 2013-14390
2013-02948 2013-02980 2013-03024 2013-11497 2012-01947
2013-14596 2013-04746 2012-08137 2013-15119 2012-08134
2013-02260 2011-9702 2013-14095 2013-13181 2013-14398
2013-14401 2013-04509 2011-10213 2012-01503 2012-00739
2012-05855 2013-04032 2012-01351 2012-00108 2012-01217
2013-16954 2013-05518 2011-10213 2011-9856 2012-01803
2013-14474 2013-04574 2011-9811 2012-00174 2012-01921
2011-9917 2011-5414 2011-10024 2011-9425 2011-8868
2011-10296 2011-10344 2012-00160 2011-8333 2012-10217
2012-10218 2011-9566 2012-01922 2013-14201 2011-8238
2012-01271 2012-01765 2012-01760 2012-00030 2011-6621
2012-01768 2013-00563 2011-10260 2012-01017 2011-5569
2012-18641
WORK ORDERS
NUMBER
0056822-01 0097154-01 0097241-01 00125729-01 00335376-01
00314285-01 00338706-01 00314218-01 00357868-01 00370608
0370376-01 00437003-01 443770-01 450313-01 450346-01
- 10 -
WORK ORDERS
NUMBER
450348-01 450350-01 450351-01 450352-01 450353-01
450355-01 450357-01 472447-01 CWO 181503 CWO 329995-
39
CWO 419854-01 CWO 421870-01 CWO 421871-01
ACTION REQUESTS
NUMBER
2770 9290 9359 10237 13509
14047 14052 14053 14078 14097
14133 31024 36796 42918 51966
51959 53806
MR-FC
NUMBER
97-007
EC
NUMBER
41455 53257 33464 34435 48714
FCSG
NUMBER
38 24 24-1 24-10 24-12
24-2 24-4 24-5 24-6 24-6.1
24-7 24-8 24-8.1 24-9 62
TREND CODES
NUMBER
- 11 -
CALCULATIONS
NUMBER
08081 07078 07076 06969 06148
06642 07536 05302 05374 06282
08179 08169
DRAWINGS
NUMBER
11405-M-121 FO-4446 FO-1005 EM-1368/1369 00357868-01
80055 11405-M-253 11405-M-252 11405-M-253 EM-1039
11405-E-98 GHDR11405-S-2 A-748, Sheet 1
LERS
NUMBER
2011-005 2011-007 2012-007 2012-008 2012-009
2012-010 2012-011 2012-012 2012-013 2012-014
2012-015 1988-019 2011-010-01 2011-010 2012-018
2012-002
RCAS
NUMBER
2011-5414
MISCELLANEOUS
NUMBER TITLE REVISION / DATE
10 CFR 50.59 Evaluation of Manual Operator
Action to open valve FW-1360
SDBD-AC-CCW- CCW Design Basis Document
100
TDB260.0020 Instruction Manual for Installation, Operation And
Maintenance of MSB, MSC, MSD, MSE Horizontal,
Multi-Stage Pumps
NPM-100 Nuclear Safety
- 12 -
MISCELLANEOUS
NUMBER TITLE REVISION / DATE
MGT0302 Safety Culture
MGT12-10 Safety Conscious Work Environment
NPM-2.04
Final Closure Book for Resource Management
FC06148 Auxiliary Feedwater Storage Tank Required
Capacity
FC05007 Usable Capacity of Emergency Feedwater Storage
Tank FW-19
FC06537
TS-FC-87-231B Memo October 30, 1987
EM-PM-EX-1200
PG-PDS-1
AA/SA-PDS-3
ECP-PDS-3
SPD-PDS-7
FPD Safety Conscious Work Environment
Organizational Effectiveness Recovery Index
RIS 2005-18 Effective Processes for Problem Identification and
Resolution
Operations Memo 2007-01
SEP-10 Safety Enhancement Program
SEP-21 Safety Enhancement Program
SEP-65 Safety Enhancement Program
Final Closure Book for the FPD associated with
Nuclear Safety Culture
Corporate Nuclear Oversight (GOSP) Committee September 18, 2012
Charter
ECP-03 IACDP Problem Development Sheet
- 13 -
MISCELLANEOUS
NUMBER TITLE REVISION / DATE
FCS-95003-IACPD- IACPD - FCS Performance Goals Assessment
03 Performance Area
FCS-95003-IACPD- IACPD - FCS Audits and Assessments
08 Assessment Performance Area
FCS-95003-IACPD- IACPD - FCS Significant Performance Deficiencies
02 Assessment Performance Area
Policy 3.06 Corporate Governance, Oversight, Support, and July 27, 2012
Perform (GOSP) Model of Fort Calhoun Station
RA 2013-0454 Governance & Oversight Self-Assessment
Mapping Leadership Skills/Attributes to Nuclear February 2013
Safety Culture Results
95003 Collective Evaluation Final Report
FCS Nuclear Safety Culture Monitoring Panel First
Quarter 2012 Report
FCS Nuclear Safety Culture Monitoring Panel
Fourth Quarter 2012 Report
FCS Nuclear Safety Culture Senior Leadership
Team Third Quarter 2012 Report
MGT 12-10 Safety Conscious Work Environment September 2012
USAR Appendix G Responses to 70 Criteria 22
MR-FC-79-190C Post-Accident Main Steam High Range Radiation 0
Monitor RM-064, Final Design Package
Reg. Guide 1.97 Criteria for Accident Monitoring Instrumentation for 4
Nuclear Power Plants
NRC Bulletin 88-04 Loop Accuracy for AFW Pump FW-6 Flow Channel April 27, 1994
Loop F-1368, Response to CAR 94-044
NUREG-1482 Guidelines for Testing at Nuclear Power Plants 1
PED-SYE-94-0297 Revised Accuracy for FM-1368-2 on IC-CP-01- May 26, 1994
1368, Reference Memo PED-SYE-94-0297
Nuenergy, Support of CDBI Self-Assessment Activities 0
Attachment 9, Final
LIC-80-0083 Response to Bulletin 80-10, Contamination of July 3, 1980
Nonradioactive Systems
- 14 -
MISCELLANEOUS
NUMBER TITLE REVISION / DATE
NRC-83-0015 NRC Resident Inspection January 20, 1983
NRC-83-0092 NRC Resident Inspection March 25, 1983
NRC-83-0185 NRC Resident Inspection June 14, 1983
LIC-84-065 Application for Amendment of Operating License March 7, 1984
LIC-84-209 Amendment 81 to Facility Operating License July 12, 1984
LIC-85-009 Environmental Qualification of Safety-Related January 10, 1985
Electrical Equipment
LIC-88-929 Updated Response To Bulletin 88-04 November 4, 1988
LIC-12-0142 Licensee Event Report LER 2012-017 0
USAR-Appendix M Postulated High Energy Line Repture Outside the 10
Containment
USAR-9.4 Auxiliary Feedwater System
USAR-Appendix M Postulated High Energy Line Rupture Outside 12
Containment
USAR-14.14 Steam Generator Tube Rupture Accident 15
NRC Bulletin 80-10 Contamination of Nonradioactive System and May 6, 1980
Resulting Potential Unmonitored, Uncontrolled
Release of Radioactivity to Environment
NRC-04-024 Safety Evaluation for the Fourth 10-Year Interval March 1, 2004
Inservice Inspection Program Plan, Fort Calhoun
ASME OM Code Code For Operation And Maintenance Of Nuclear
1988 Power Plants
NCV Failure to Correct Repeated Tripping of the August 12, 2010
05000285/2010006- Turbine-Driven Auxiliary Feedwater Pump FW-10
01
NCV Failure to Verify That the Turbine-Driven Auxiliary August 12, 2010
05000285/2010006- Feedwater Pump exhaust Backpressure Trip Lever
02 was Fully Latched
NCV Failure to Vent Control Oil Following Maintenance August 12, 2010
05000285/2010006- Results in Failure of the Turbine-Driven Auxiliary
03 Feedwater Pump to Start
RCA 2013-0813 Root Cause Analysis Steam Driven Auxiliary April 23, 2010
Feedwater Pump (FW-10) Tripped Off
- 15 -
MISCELLANEOUS
NUMBER TITLE REVISION / DATE
PLDBD-ME-11 Internal Missiles and High Energy Line Break 15
EC48714 Installation of FW-10 Manual Trip Latch Clamp FW- 0
64-C
NCR 449 Non Conformance Report
NCR 410 Nonconformance Report Project # 093-15901
Recovery Issue Meeting Minutes for 1.c Closure December 17, 2012
Book and February 8,
2013
FCS 95003 Project RSSPA Key Attribute Review Final Report October 15, 2012
for EDS & HPSI,
ERPG- Engineering Recovery Process Guide - Degraded 4
DNC/OPEVAL-01 Nonconforming Conditions and Operability
Evaluations
OPPD-E-12-002 Project Study Report - Study to Ensure Acceptable 0
Diesel Generator Performance During Non-DBA
Loss of Offsite Power Scenarios
SE-PM-EX-1600 Preventive Maintenance Infrared Thermographic July 29, 2010
Surveys
Safety Conscious Work Environment at Fort 1
Calhoun Station Rout Cause
Fort Calhoun Station Nuclear Safety Culture Focus January 2013
Groups, Summary of Findings
Fort Calhoun Station Nuclear Two Cs Meetings, January 2013
Summary of Findings
Fort Calhoun Safety Culture Composite Index December 2012
Fort Calhoun Station Independent Safety Culture May 2012
Assessment, Conger & Elsea, Inc.
Weekly Leadership Alignment Meeting Slides February 4, 2013
Weekly Leadership Alignment Meeting Slides February 11, 2013
Fort Calhoun Safety Culture Composite Index January 2013
Safety Conscious Work Environment Fundamental July 2012
Performance Deficiency Analysis
- 16 -
MISCELLANEOUS
NUMBER TITLE REVISION / DATE
Corporate Governance, Oversight, Support and
Perform Model of Fort Calhoun Station
Leadership/Organizational Effectiveness CR 2012- July 2012
08130 and Nuclear Safety Culture CR 2012-08129
Fundamental Performance Deficiency Analysis
Corrective Action Program CR 2012-08124 July 2012
Fundamental Performance Deficiency Analysis
Security Self Assessment Report August 2012
SDBD-FW-AFW- System Design Bases Document Auxiliary 44
117 Feedwater
STM Auxiliary Feedwater System Training Manual 37
- 17 -