ML14078A666
| ML14078A666 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 03/19/2014 |
| From: | Hay M NRC/RGN-IV/DRP |
| To: | Cortopassi L Omaha Public Power District |
| Hay M | |
| References | |
| EA-14-037 IR-14-002 | |
| Download: ML14078A666 (78) | |
See also: IR 05000285/2014002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION IV
1600 E. LAMAR BLVD.
ARLINGTON, TX 76011-4511
March 19, 2014
Lou 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 - NRC INTEGRATED INSPECTION REPORT
NUMBER 05000285/2014002 AND NOTICES OF VIOLATIONS
Dear Mr. Cortopassi:
On February 15, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at the Fort Calhoun Station. On February 25, 2014, the NRC inspectors discussed
the results of this inspection with Mr. Michael Prospero, Plant Manager, and other members of
your staff. Inspectors documented the results of this inspection in the enclosed inspection
report.
During this inspection, the NRC staff examined activities conducted under your license as they
relate to public health and safety with the Commission's rules and regulations and with the
conditions of your license. Within these areas, the inspection consisted of selected examination
of procedures and representative records, observations of activities, and interviews with
personnel.
Based on the results of the inspection, the NRC has determined a Severity Level IV violation of
NRC requirments occurred. Additionally, the NRC identified an issue that was evaluated under
the risk significance determination process as having very low safety significance (green). The
NRC also determined that a violation was associated with this issue.
These violations were evaluated in accordance with the NRC Enforcement Policy. The current
Enforcement Policy is included on the NRCs Web site at
http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.
These violations are cited in the enclosed Notice and the circumstances surrounding them are
described in detail in the subject inspection report. The violations are being cited in the Notice
because one issue was repetitive in nature and the other issue involved the failure to restore
compliance (or demonstrate objective evidence of plans to restore compliance) within a
reasonable period of time after a violation is identified.
L. Cortopassi -2-
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.
Additionally, based on the results of the inspection, the NRC identified two additional Severity
Level IV violations of NRC requirements and five findings evaluated under the risk significance
determination process as having very low safety significance. The NRC determined that
violations were associated with these issues, however, these violations are being treated as
Non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy. These
NCVs are described in the subject inspection report. If you contest the 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 U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555-0001; with copies to the Regional
Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory
Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Fort Calhoun
Station.
If you disagree with a cross-cutting aspect assignment in this report, you should provide a
response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the
Fort Calhoun Station.
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your
response (if any) will be available electronically for public inspection in the NRCs Public
Document Room or from the Publicly Available Records (PARS) component of the NRC's
Agencywide Documents 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: 50-285
License: DPR-40
Enclosure:
NRC Inspection Report 05000285/2014002
w/Attachment: Supplemental Information
cc w/ encl: Electronic Distribution
L. Cortopassi -3-
Electronic distribution by RIV:
Regional Administrator (Marc.Dapas@nrc.gov)
Deputy Regional Administrator (Steven.Reynolds@nrc.gov)
DRP Director (Kriss.Kennedy@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)
Senior Project Engineer, DRP/F (Nick.Taylor@nrc.gov)
Project Engineer, DRP/F (Chris.Smith@nrc.gov)
FCS Administrative Assistant (Janise.Schwee@nrc.gov)
RIV Public Affairs Officer (Victor.Dricks@nrc.gov)
RIV Public Affairs Officer (Lara.Uselding@nrc.gov)
NRR Project Manager (Lynnea.Wilkins@nrc.gov)
NRR Project Manager (Joseph.Sebrosky@nrc.gov)
RIV Branch Chief, DRS/TSB (Ray.Kellar@nrc.gov)
RIV RITS Coordinator (Marisa.Herrera@nrc.gov)
RIV Regional Counsel (Karla.Fuller@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
OEMail Resource
OEWEB Resource (Sue.Bogle@nrc.gov)
RIV/ETA: OEDO (Ernesto.Quinones@nrc.gov)
RIV RSLO (Bill.Maier@nrc.gov)
MC 0350 Panel Chairman (Anton.Vegel@nrc.gov)
MC 0350 Panel Vice Chairman (Louise.Lund@nrc.gov)
MC 0350 Panel Member (Michael.Balazik@nrc.gov)
MC 0350 Panel Member (Michael.Markley@nrc.gov)
R:\_Reactors\FCS\2014\FCS 2014-002-RP JCK.pdf ML14078A666
SUNSI Rev Compl. Yes No ADAMS Yes No Reviewer Initials MCH
Publicly Avail. Yes No Sensitive Yes No Sens. Type Initials MCH
SRI:DRP/F RI:DRP/F SPE:DRP/F PE:DRP/F OE C:DRP/F
JKirkland JWingebach NTaylor CSmith RBrowder MHay
/RA/ /RA/ /RA/ /RA/ /RA/ /RA/
03/18/14 03/18/14 03/13/14 03/18/14 03/19/14 03/19/14
OFFICIAL RECORD COPY
NOTICE OF VIOLATION
Omaha Public Power District Docket No: 50-285
Fort Calhoun Station License No: DPR-40
During an NRC inspection conducted on August 26, 2013 through February 15, 2014, a
violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy,
the violation is listed below:
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
nonconformances are promptly identified and corrected.
Contrary to the above, between August 12, 2008 and November 24, 2013, the licensee
failed to correct a condition adverse to quality. Specifically, actions were not taken to
correct NRC-identified runout concerns in the containment spray system until these
concerns were again raised by the NRC on July 18, 2013.
This violation is associated with a Green Significance Determination Process finding.
Pursuant to the provisions of 10 CFR 2.201, Omaha Public Power District is hereby required to
submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555-0001 with a copy to the Regional
Administrator, Region IV, and a copy to the NRC Resident Inspector at the facility that is the
subject of this Notice, 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-14-037"
and should include: (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
Because your response will be made available electronically for public inspection in the NRC
Public Document Room or from the NRCs document system (ADAMS), accessible from the
NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should not
include any personal privacy, proprietary, or safeguards information so that it can be made
available to the public without redaction. If personal privacy or proprietary information is
necessary to provide an acceptable response, then please provide a bracketed copy of your
response that identifies the information that should be protected and a redacted copy of your
response that deletes such information. If you request withholding of such material, you must
specifically identify the portions of your response that you seek to have withheld and provide in
detail the bases for your claim of withholding (e.g., explain why the disclosure of information will
create an unwarranted invasion of personal privacy or provide the information required by
10 CFR 2.390(b) to support a request for withholding confidential commercial or financial
information). If safeguards information is necessary to provide an acceptable response, please
provide the level of protection described in 10 CFR 73.21.
Dated this 19th day of March, 2014
-2-
NOTICE OF VIOLATION
Omaha Public Power District Docket No: 50-285
Fort Calhoun Station License No: DPR-40
During an NRC inspection conducted on August 26, 2013 through February 15, 2014, a
violation of NRC requirements was identified. In accordance with the NRC Enforcement Policy,
the violation is listed below:
10 CFR 50.73(a)(1), requires, in part, that the licensee submit a Licensee Event Report
(LER) for any event of the type described in this paragraph within 60 days after the
discovery of the event.
Contrary to the above, between June 14 and July 2, 2013, the licensee failed to submit a
LER for two events meeting the requirements for reporting specified in 10 CFR 50.73
within 60 days after the discovery of the event. Specifically, LERs 2013-101-0, HPSI
Pump Flow Imbalance, and 2013-017-0, Containment Spray Pump Design Documents
do not Support Operation in Runout, were submitted more than 60 days after the events
were discovered.
The NRC determined that this violation was repetive in nature as described in Paragraph
2.3.2(a)(3) of the NRC Enforcement Policy. A similar violation had been documented in
NRC Inspection Report 2013008 dated July 16, 2013 (ML13197A261). That report
included NCV 05000285/2013008-43, entitled Untimely Submittal of Licensee Event
Reports. The NCV documented nine examples of LERs that were submitted later than
required by 10 CFR 73(a)(1).
This is a Severity Level IV violation.
Pursuant to the provisions of 10 CFR 2.201, Omaha Public Power District is hereby required to
submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555-0001 with a copy to the Regional
Administrator, Region IV, and a copy to the NRC Resident Inspector at the facility that is the
subject of this Notice, 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-14-037"
and should include for each violation: (1) the reason for the violation, or, if contested, the basis
for disputing the violation or severity level, (2) the corrective steps that have been taken and the
results achieved, (3) the corrective steps that will be taken, and (4) the date when full
compliance will be achieved. Your response may reference or include previous docketed
correspondence, if the correspondence adequately addresses the required response. If an
adequate reply is not received within the time specified in this Notice, an order or a Demand for
Information may be issued as to why the license should not be modified, suspended, or
revoked, or why such other action as may be proper should not be taken. Where good cause is
shown, consideration will be given to extending the response time.
-3-
If you contest this enforcement action, you should also provide a copy of your response, with
the basis for your denial, to the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001.
Because your response will be made available electronically for public inspection in the NRC
Public Document Room or from the NRCs document system (ADAMS), and be accessible from
the NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should
not include any personal privacy, proprietary, or safeguards information so that it can be made
available to the public without redaction. If personal privacy or proprietary information is
necessary to provide an acceptable response, then please provide a bracketed copy of your
response that identifies the information that should be protected and a redacted copy of your
response that deletes such information. If you request withholding of such material, you must
specifically identify the portions of your response that you seek to have withheld and provide in
detail the bases for your claim of withholding (e.g., explain why the disclosure of information will
create an unwarranted invasion of personal privacy or provide the information required by
10 CFR 2.390(b) to support a request for withholding confidential commercial or financial
information). If safeguards information is necessary to provide an acceptable response, please
provide the level of protection described in 10 CFR 73.21.
Dated this 19th day of March, 2014
-4-
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 05000285
License: DPR-40
Report: 05000285/2014002
Licensee: Omaha Public Power District
Facility: Fort Calhoun Station
Location: 9610 Power Lane
Blair, NE 68008
Dates: January 1 through February 15, 2014
Inspectors: J. Kirkland, Senior Resident Inspector
J. Wingebach, Resident Inspector
N. Taylor, Senior Project Engineer
W. Smith, Project Engineer
W. Lyon, Senior Reactor Engineer
M. Chambers, Physical Security Inspector
A. Guzzetta, Reactor Systems Engineer
M. Farnan, Mechanical Engineer
A. Sallman, Senior Reactor Systems Engineer
Approved By: Michael Hay, Chief, Project Branch F
Division of Reactor Projects
-5-
SUMMARY
IR 05000285/2014002; 01/01/2014 - 02/15/2014; Fort Calhoun Station; integrated resident
inspection report and Confirmatory Action Letter closeout items.
The inspection activities described in this report were performed between January 1, 2014, and
February 15, 2014, by the resident inspectors at the Fort Calhoun Station, inspectors from the
NRCs Region IV office, and technical support from headquarters staff. Nine findings are
documented in this report. Seven findings were of very low safety significance (Green). All of
these findings involved violations of NRC requirements and three of these violations were
determined to be Severity Level IV violations under the traditional enforcement process. The
significance of inspection findings is indicated by their color (Green, White, Yellow, or Red),
which is determined using Inspection Manual Chapter 0609, Significance Determination
Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310,
Components Within the Cross-Cutting Areas. Violations of NRC requirements are
dispositioned in accordance with the NRCs Enforcement Policy. The NRC's program for
overseeing the safe operation of commercial nuclear power reactors is described in
NUREG 1649, Reactor Oversight Process.
Cornerstone: Mitigating Systems
Green. A non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, was
identified involving the failure to translate the High Pressure Safety Injection (HPSI) pump
design and runout characteristics to design documents such as the Updated Safety Analysis
Report or design calculations. On June 21, 2013, the licensee completed Engineering
Change 59874, which permanently installed flow-limiting orifices in the discharge line of each
pump, effectively preventing HPSI runout conditions from occurring for all plant conditions.
This finding was more than minor because it adversely impacted the design control attribute of
the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable consequences.
The inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings,
Table 3 - SDP Appendix Router. While this issue was identified during a refueling outage, the
inspectors determined that the majority of the exposure time for this violation occurred with the
reactor at power. As such, the inspectors determined the finding should be evaluated using the
SDP in accordance with IMC 0609, The Significance Determination Process (SDP) for
Findings at-Power, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The
finding required a detailed risk evaluation because the high pressure safety injection system
was inoperable for some of the large break loss of coolant accident scenarios (at reactor
pressures less than 100 psi). A Region IV senior reactor analyst performed a bounding detailed
risk evaluation. The change to the core damage frequency was 8E-8/year and, therefore,
determined to be of very low safety significance (Green). The dominant core damage
sequences included loss of coolant accidents where the high and low pressure safety injection
systems failed during recirculation. The non-degraded low pressure safety injection system
contributed to minimize the risk. The inspectors determined there was no cross-cutting aspect
associated with this finding because events related to identification of needed procedures and
-6-
specifications occurred in the 1970s and are not indicative of current performance. (Section
4OA3.2)
Green. Two examples of a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design
Control, were identified. The first example involved the failure to establish procedures or
Technical Specifications to accomplish required HPSI injection flow balancing. The second
example involved the failure to provide controls or testing to ensure that replacement parts for
HPSI injection valves were suitable for the application and were capable of supporting the
safety-related functions of the HPSI system. The licensee has since implemented Engineering
Change 59874 which included throttling of the HPSI loop injection valves. This change was
completed on August 20, 2013, restoring the original plant design and overcoming the
configuration control errors introduced on three of the eight injection valves. Post-work testing
for the completed modification included flow balance testing for the HPSI loop injection lines.
The inspectors reviewed the results of this testing and determined that the UFSAR assumptions
regarding balanced loop flows were adequately addressed by licensee corrective actions.
This finding was more than minor because it adversely impacted the design control attribute of
the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable consequences.
The inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings,
Table 3 - SDP Appendix Router. While this issue was identified during a refueling outage, the
inspectors determined that the majority of the exposure time for this violation occurred with the
reactor at power. As such, the inspectors determined the finding could be evaluated using the
SDP in accordance with IMC 0609, The SDP for Findings at-Power, Appendix A, Exhibit 2,
Mitigating Systems Screening Questions. The inspectors answered yes to the question of
Does the finding represent a loss of system and/or function? The inspectors determined the
finding required a detailed risk evaluation per IMC 0609 Paragraph 6.0, because the operability
of the high pressure safety injection system (both trains) was in question. A Region IV senior
reactor analyst performed a detailed risk evaluation and determined the flow imbalance did not
result in a loss of safety function. Since the high pressure safety injection system was capable
of meeting the functional success criteria, there was no quantifiable change to the core damage
frequency and therefore was determined to be of very low safety significance (Green). The
inspectors determined there was no cross-cutting aspect associated with this finding because
events related to identification of needed procedures and specifications occurred in the 1970s
and are not indicative of current performance. Additionally, the errant replacement of parts of
three HPSI injection valves occurred between 1993 and 2006, and are also not indicative of
current performance. (Section 4OA3.4)
SLIV and Green. A Severity Level IV non-cited violation of 10 CFR 50.59, Changes, Tests, and
Experiments, and an associated Green finding was identified involving the failure to request a
license amendment for a facility change that required a change to the Technical Specifications.
This issue is also associated with a Green finding related to the licensees failure to follow
Procedure NOD-QP-3, 10 CFR 50.59 and 10 CFR 72.48 Reviews, and Procedure FCSG-23,
10 CFR 50.59 Resource Manual, both of which require submittal of a license amendment
request prior to making a facility change that requires a change to Technical Specifications.
The licensee initiated CR 2014-01029 on January 23, 2014, to document this violation and track
corrective actions.
-7-
This performance deficiency was considered to be of more than minor safety significance
because it was associated with the procedure quality attribute of the mitigating systems
cornerstone and it adversely affected the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent undesirable
consequences. Specifically, the failure to follow station procedures for the 10 CFR 50.59
process caused the Technical Specifications to become insufficient to ensure that the limiting
conditions for operation will be met. Using Inspection Manual Chapter 0609 Appendix G,
Checklist 4, the inspectors determined that the finding did not result in the loss of any accident
mitigation capability and did not require a quantitative risk assessment. This finding was
determined to be of very low risk significance.
This performance deficiency was also determined to be subject to traditional enforcement
because it impeded the regulatory process, in that the failure to submit a license amendment
and add required surveillance testing was in violation of 10 CFR 50.59(c)(1)(i) and caused the
NRC-approved Technical Specifications to be out of alignment with the safety analysis for the
facility. This violation is associated with a finding that has been evaluated by the SDP and
communicated with an SDP color reflective of the safety impact of the deficient licensee
performance. The SDP, however, does not specifically consider the regulatory process impact.
Thus, although related to a common regulatory concern, it is necessary to address the violation
and finding using different processes to correctly reflect both the regulatory importance of the
violation and the safety significance of the associated finding. This violation was determined to
be a Severity Level IV violation, because it is consistent with the examples in Paragraph 6.1.d of
the NRC Enforcement Policy. The finding had a cross-cutting aspect in the training aspect of
the human performance cross-cutting area because the licensees staff failed to understand and
misapplied NRC generic guidance related to discovery of inadequate Technical Specifications
[H.9]. (Section 4OA3.4)
Green. A non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings was identified involving the licensees failure to complete a 10 CFR 50.59
screening that met the requirements of Procedure NOD-QP-3, 10 CFR 50.59 and 10
CFR 72.48 Reviews, Revision 37. The licensees staff subsequently re-performed the 50.59
screening on November 29, 2013, and determined that a 10 CFR 50.59 evaluation was
required. The NRC staff reviewed the 10 CFR 50.59 screening and evaluation and determined
that they had been properly performed, and that a license amendment request was not required
prior to implementation of the activity. The licensee documented this procedural violation in
CR 2014-01357 on January 29, 2014.
This performance deficiency was considered to be of more than minor safety significance
because it was associated with the design control attribute of the mitigating systems
cornerstone and it adversely affected the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent undesirable
consequences. Specifically, the failure to follow station procedures for the 10 CFR 50.59
process prevented the licensees staff from evaluating the adverse impacts of the change on the
facility. Using Inspection Manual Chapter 0609 Appendix G, Checklist 4, the inspectors
determined that the finding did not result in the loss of any accident mitigation capability and did
not require a quantitative risk assessment. This finding was determined to be of very low risk
-8-
significance. The inspectors determined that this finding had a cross-cutting aspect of
conservative bias in the human performance area, because the licensees staff ensured that the
proposed design change was safe in order to proceed rather than unsafe to stop [H.14].
(Section 4OA3.8)
Green. Several examples of a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III,
Design Control, were identified involving the failure to ensure the adequacy of the anchorage
for several raw water system and containment spray system pipe supports. Specifically the
anchorage design was non-conservative with respect to the design basis requirements. The
licensee entered these issues into the corrective action program as CR 2013-05304 and
performed an operability determination as immediate actions. Long term actions to resolve the
errors in the calculations are documented in the condition report.
The performance deficiency was determined to be more than minor because it was associated
with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone
objective of ensuring the availability, reliability, and capability of the containment spray system
and raw water system. Using Inspection Manual Chapter 0609, Attachment 4 Initial
Characterization of Findings, and Appendix A The Significance Determination Process (SDP)
for findings at-power, both dated 6/19/12, the inspectors determined the performance
deficiency affected the mitigating systems cornerstone and screened to Green because the
finding affected the design and qualification of a mitigating component but remained operable.
The inspectors used the at-power SDP because the condition existed since construction and
while the plant was predominantly at power. The inspectors determined there was no cross-
cutting aspect associated with this finding because the calculations were from the 1980s and
therefore were not reflective of current performance. (Section 4OA5.1)
Green. A non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was
identified involving the failure to ensure the adequacy of the U-bolts for containment air cooler
pipe supports VAS-1 and VAS-2. Specifically the U-bolt design was non-conservative with
respect to the design basis requirements. The licensee entered these issues into the corrective
action program as CR 2013-03722. The licensee revised the calculation to support operability.
In addition, the licensee generated engineering change EC59570 to fix the degraded VAS-1 and
VAS-2 supports.
The performance deficiency was determined to be more than minor because it was associated
with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone
objective of ensuring the availability, reliability, and capability of several safety injection tank
valves. Specifically, the one-directional U-bolts for VAS-1 and VAS-2 are not designed to
withstand two-directional loading and the condensate drain piping line has the potential to
adversely impact the safety injection tank discharge isolation valves HCV-2934 and HCV-2974
during a design basis event. The licensee updated calculation FC05918 and provided an
operability evaluation to address the degraded condition. The inspectors reviewed the
information and did not find any issues. Using Inspection Manual Chapter 0609, Attachment 4
Initial Characterization of Findings, and Appendix A The Significance Determination Process
(SDP) for findings at-power, both dated June 19, 2012, the inspectors determined performance
deficiency affected the mitigating systems cornerstone and screened to Green because the
finding affected the design and qualification of a mitigating SSC but remained operable. The
-9-
inspectors used the at-power SDP because the condition existed since construction and while
the plant was predominantly at power. The inspectors determined there was no cross-cutting
aspect associated with this finding because the calculation was from the 1980s, and therefore
was not reflective of current performance. (Section 4OA5.2)
Cornerstone: Barrier Integrity
Green. A cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was
identified involving the failure to take timely corrective action for a condition adverse to quality.
Specifically, the licensee failed to restore compliance following NRC identification of the
licensees failure to correct a runout condition of the containment spray system (CS)
documented in NCV 05000285/2008003-05, in August 2008. Licensee corrective actions to
correct the issue included completion of an analysis of containment spray pump operation
during the main steam line break (MSLB) event; revision of CS design documentation; analysis
of motor performance by an electrical vendor; and completion of a temporary modification to
throttle the CS pump discharge valves to provide additional system resistance preventing pump
runout. Future corrective actions include a permanent design change to prevent CS pump
runout. The licensee initiated CR 2014-02242 on February 19, 2014, to document this failure to
restore compliance.
This finding was more than minor because it adversely impacted the Barrier Integrity
cornerstone objective to provide reasonable assurance that physical design barriers
(containment) protect the public from radionuclide releases caused by accidents or events. The
inspectors reviewed NRC IMC 0609, Attachment 4, Initial Characterization of Findings, Table 3
- SDP Appendix Router. While this issue was identified during a refueling outage, the
inspectors determined that the majority of the exposure time for this violation occurred with the
reactor at power and should be evaluated using the Significance Determination Process in
accordance with IMC 0609, The Significance Determination Process (SDP) for Findings at-
Power, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors
determined that the finding did not represent an actual open pathway in containment or
containment isolation logic, nor did the finding represent an actual reduction in the function of
containment hydrogen igniters. Based on the guidance in the Exhibit 3 checklist the inspectors
determined that the finding was of very low safety significance.
The inspectors determined that the finding had a cross-cutting aspect of avoiding complacency
in the human performance area, because the licensees staff failed to recognize latent issues
even while expecting successful outcomes [H.12]. (Section 4OA3.8)
Other Findings and Violations
SL-IV. A Severity Level IV non-cited violation of 10 CFR 50.46, Acceptance criteria for
emergency core cooling systems (ECCS) for light-water nuclear power reactors, was identified
involving the failure to submit a report within 30 days of discovery of a significant change in the
application of the ECCS model that affected the peak cladding temperature. The licensee
submitted the required 10 CFR 50.46 report late on September 20, 2013 (ML13266A108). This
report was subsequently reviewed by the NRC staff date October 2, 2013, and determined to be
- 10 -
acceptable. The NRC staff determined that while the configuration change to the HPSI system
resulted in a higher peak cladding temperature, it is within the regulatory requirements of
10 CFR 50.46(b)(1). The licensee initiated CRs-2014-00674 and 2014-01356 to address
issuance of the late report.
This performance deficiency was determined to be subject to traditional enforcement because it
impeded the regulatory process, in that the failure to submit a timely report of significant ECCS
analytical changes prevented the NRC technical staff from independently evaluating the
potential safety implications of reductions in safety injection flow into the reactor during an
accident. This violation was determined to be a Severity Level IV violation because it is
consistent with the examples in Paragraph 6.9.d of the NRC Enforcement Policy. Because this
violation is subject to traditional enforcement, no cross-cutting aspects have been assigned.
(Section 4OA3.2)
SL-IV. Two examples of a cited Severity Level IV violation of 10 CFR 50.73, Immediate
Notification Requirements for Operating Nuclear Power Reactors, were identified involving the
failure to submit a required licensee event report (LER) within 60 days following discovery of an
event requiring a report. In the first example, LER 2013-010-0 was submitted on July 2, 2013,
seventy-nine days after the flow imbalance was observed by the licensees staff. In the second
example, LER 2013-017-0 was submitted to the NRC on December 27, 2013, 62 days after the
event date on the licensees reportability evaluation and sixty-six days after a condition report
documented the reportable condition. The licensee initiated CR 2014-01358 on
January 29, 2014 to document this repetitive violation.
The violation was evaluated using Section 2.2.4 of the NRC Enforcement Policy, because the
failure to submit a required LER 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(d)(9) of the NRC Enforcement Policy, this violation was determined
to be a Severity Level IV violation. The inspetors 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 4OA3.4)
- 11 -
PLANT STATUS
The plant began the reporting period at 100% power. On January 9, 2014, the plant shutdown
in accordance with Technical Specification 2.0.1 because an intake structure river sluice gate
would not close. Following repairs, the plant reached citicality on January 12, 2014, and was
manually tripped shortly thereafter due to a control element assembly that would not move.
Following repairs the plant started up on January 13, 2014, and reached 100% power on
January 15, 2014, where it remained for the duration of the inspection period.
REPORT DETAILS
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1 Readiness to Cope with External Flooding
a. Inspection Scope
On January 8, 2014, the inspectors completed an inspection of the stations readiness to
cope with external flooding. After reviewing the licensees flooding analysis, the
inspectors chose one plant area that was susceptible to flooding:
- Intake Structure, due to failure of sluice gates
The inspectors reviewed plant design features and licensee procedures for coping with
flooding. The inspectors walked down the selected areas to inspect the design features,
including the material condition of seals, drains, and flood barriers. The inspectors
evaluated whether credited operator actions could be successfully accomplished.
These activities constituted one sample of readiness to cope with external flooding, as
defined in Inspection Procedure 71111.01.
b. Findings
No findings were identified.
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1R04 Equipment Alignment (71111.04)
.1 Partial Walkdown
a. Inspection Scope
The inspectors performed partial system walk-downs of the following risk-significant
systems:
- January 6, 2014, Auxiliary Building Ventilation
The inspectors reviewed the licensees procedures and system design information to
determine the correct lineup for the systems. They visually verified that critical portions
of the systems were correctly aligned for the existing plant configuration.
These activities constituted one partial system walk-down sample as defined in
Inspection Procedure 71111.04.
b. Findings
No findings were identified.
1R05 Fire Protection (71111.05)
.1 Quarterly Inspection
a. Inspection Scope
The inspectors evaluated the licensees fire protection program for operational status
and material condition. The inspectors focused their inspection on two plant areas
important to safety:
- January 28, 2014, Room 13, Mechanical Penetration Area, Fire Area 13
- January 28, 2014, Room 18, Component Cooling Heat Exchanger Area, Fire
Area 33
For each area, the inspectors evaluated the fire plan against defined hazards and
defense-in-depth features in the licensees fire protection program. The inspectors
evaluated control of transient combustibles and ignition sources, fire detection and
suppression systems, manual firefighting equipment and capability, passive fire
protection features, and compensatory measures for degraded conditions.
These activities constituted two quarterly inspection samples, as defined in Inspection
Procedure 71111.05.
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b. Findings
No findings were identified.
.2 Annual Inspection
a. Inspection Scope
On February 4, 2014, the inspectors completed their annual evaluation of the licensees
fire brigade performance. This evaluation included observation of one announced fire
drill. During this drill, the inspectors evaluated the capability of the fire brigade
members, the leadership ability of the brigade leader, the brigades use of turnout gear
and fire-fighting equipment, and the effectiveness of the fire brigades team operation.
The inspectors also reviewed whether the licensees fire brigade met NRC requirements
for training, dedicated size and membership, and equipment.
These activities constituted one annual inspection sample, as defined in Inspection
Procedure 71111.05.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
(71111.11)
.1 Review of Licensed Operator Requalification
a. Inspection Scope
On February 11, 2014, the inspectors observed simulator training for an operating crew.
The inspectors assessed the performance of the operators and the evaluators critique of
their performance.
These activities constitute completion of one quarterly licensed operator requalification
program sample as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
On January 22, 2014, the inspectors reviewed a risk assessment performed by the
licensee prior to to performing a maintenance run on Diesel Generator 1 and the risk
management actions taken by the licensee in response to the elevated risk.
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The inspectors verified that this risk assessment was performed timely and in
accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant
procedures. The inspectors reviewed the accuracy and completeness of the licensees
risk assessment and verified that the licensee implemented appropriate risk
management actions based on the result of the assessment.
Additionally, on February 12, 2014, the inspectors observed portions of one emergent
work activity that had the potential to affect the functional capability of mitigating
systems. This activity involved the failure of the turbine driven auxiliary feedwater pump
steam admission Valve YCV-1045.
The inspectors verified that the licensee appropriately developed and followed a work
plan for these activities. The inspectors verified that the licensee took precautions to
minimize the impact of the work activities on unaffected structures, systems, and
components (SSCs).
These activities constitute completion of two maintenance risk assessments and
emergent work control inspection samples, as defined in Inspection Procedure 71111.13
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments (71111.15)
a. Inspection Scope
The inspectors reviewed three operability determinations that the licensee performed for
degraded or nonconforming structures, systems, or components (SSCs):
- January 20, 2014, operability determination of the raw water piping, due to a leak
downstream of heat exchanger AC-1A
- February 3, 2014, operability determination of auxiliary steam to the intake
structure
- February 13, 2014, operability determination of flow control valve FCV-1369 (FW-
10 recirculation valve), due to non essential parts
The inspectors reviewed the timeliness and technical adequacy of the licensees
evaluations. Where the licensee determined the degraded SSC to be operable, the
inspectors verified that the licensees compensatory measures were appropriate to
provide reasonable assurance of operability. The inspectors verified that the licensee
had considered the effect of other degraded conditions on the operability of the
degraded SSC.
These activities constitute completion of three operability and functionality review
samples, as defined in Inspection Procedure 71111.15.
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b. Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed two post-maintenance testing activities that affected risk-
significant SSCs:
- January 30, 2014, Post-maintenance testing following the overhaul of the Diesel
Auxiliary Feedwater Pump FW-54
- January 10, 2014, Post-maintenance testing Hot Leak Check following
mechanical penetration M-45 piping swagelock replacement
The inspectors reviewed licensing- and design-basis documents for the SSCs and the
maintenance and post-maintenance test procedures. The inspectors observed the
performance of the post-maintenance tests to verify that the licensee performed the tests
in accordance with approved procedures, satisfied the established acceptance criteria,
and restored the operability of the affected SSCs.
These activities constitute completion of two post-maintenance testing inspection
samples, as defined in Inspection Procedure 71111.19.
b. Findings
No findings were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors observed five risk-significant surveillance tests and reviewed test results
to verify that these tests adequately demonstrated that the SSCs were capable of
performing their safety functions:
In-service tests:
- January 29, 2014, AC-10C Raw Water Pump Quarterly Inservice
Test, OP-ST-RW-3021
Reactor coolant system leak detection tests:
- February 4, 2014, Manual leak rate calculation
Other surveillance tests:
- 16 -
- January 23, 2014, Quarterly functional test of Power Range Safety Channels
A/B/C/D, IC-ST-RPS-0002/3/4/5
- February 12, 2014, Operability Test of instrument air valve IA-YCV-1045-C and
Close Stroke Test of YCV-1045, IC-ST-IA-3009
- February 14, 2014, Auxiliary Feedwater Pump FW-10, Steam Isolation Valve, and
Check Valve Tests, OP-ST-AFW-3011
The inspectors verified that these tests met technical specification requirements, that the
licensee performed the tests in accordance with their procedures, and that the results of
the test satisfied appropriate acceptance criteria. The inspectors verified that the
licensee restored the operability of the affected SSCs following testing.
These activities constitute completion of five surveillance testing inspection samples, as
defined in Inspection Procedure 71111.22.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
Security
4OA2 Problem Identification and Resolution (71152)
.1 Routine Review
a. Inspection Scope
Throughout the inspection period, the inspectors performed daily reviews of items
entered into the licensees corrective action program and periodically attended the
licensees condition report screening meetings. The inspectors verified that licensee
personnel were identifying problems at an appropriate threshold and entering these
problems into the corrective action program for resolution. The inspectors verified that
the licensee developed and implemented corrective actions commensurate with the
significance of the problems identified. The inspectors also reviewed the licensees
problem identification and resolution activities during the performance of the other
inspection activities documented in this report.
b. Findings
No findings were identified.
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4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)
.1 (Closed) LER 05000285/2012-013-00: Inadequate Calculation of Uncertainty Results in a
Technical Specification Violation
Technical Data Book Procedure (TDB)-III.40, Technical Specification Required SIRWT
Levels, lists the administrative requirements to maintain the Technical Specification (TS)
required Safety Injection Refueling Water Tank (SIRWT) levels. The required SIRWT level
for TS 2.3 accounts for instrument uncertainty, as described in the basis for TS 2.3.
However, the required SIRWT levels listed in TDB-III.40 for TS 2.2.7 and 2.2.8 do not
account for instrument uncertainty. Therefore, the TS described levels in TS 2.2.7 and 2.2.8
did not adequately account for SIRWT instrument level uncertainty. As a result, using the
levels described in TDB-III.40 for compliance with TS 2.2.7 and 2.2.8 was non-conservative.
The causal analysis (2011-9956) concluded that there was inadequate/incomplete
procedural guidance for developing Administrative Limits used to protect TS Limits. This
includes guidance for understanding how to evaluate and apply uncertainties when
developing TS Administrative Limits.
The licensee has revised procedures to include guidance on the development of new
Technical Specification limits and the associated administrative limits. The licensee
performed an extent of condition based on criteria in RG 1.97, Criteria for Accident
Monitoring Instrumentation for Nuclear Power Plants.
This Licensee Event Report is Closed.
.2 (Closed) Licensee Event Report 05000285/2013-003-01: Calculations Indicate the HPSI
Pumps will Operate in Run-out During a DBA
a. Inspection Scope
On January 30, 2013, the licensee identified that design basis calculations indicated that
the high pressure safety injection pumps would operate in a run out condition during
postulated accident conditions. The licensee issued Revision 0 of the LER to report that
this represented an unanalyzed condition, and that it was also an event or condition that
could have prevented the fulfillment of the safety function of the HPSI system.
The preliminary causal analysis identified that the cause of the condition was that the
station had failed to obtain vendor technical information on HPSI pump performance in a
10 CFR 50, Appendix B, quality assurance validated format. Corrective actions
identified in the LER included revising procedures to prevent HPSI operation in runout;
design changes to prevent HPSI operation in runout; and improving engineering
guidance related to review of vendor information and documentation of engineering
evaluations.
On November 27, 2013, the licensee submitted Revision 01 to the LER to update the
cause and corrective actions taken for the condition.
- 18 -
The inspectors reviewed both revisions of the LER, and identified a number of
observations and findings as described later in this report.
This Licensee Event Report is closed.
b. Review of OPPD Report 30-Day Report of a Significant Change in the Loss-of-Coolant
Accident (LOCA)/Emergency Core Cooling System (ECCS) Models Pursuant
to 10 CFR 50.46
Due to a deficiency associated with high pressure safety injection (HPSI) pump runout,
the licensee determined that a physical plant modification was required involving
installation of flow orifices to the HPSI discharge lines. The installation of these orifices
affected HPSI flow rate, which changed the emergency core cooling system (ECCS)
performance that is predicted using an evaluation model pursuant to the requirements of
The inspectors reviewed the licensees report which was submitted to the NRC staff on
September 20, 2013, (ADAMS Accession number ML13266A108), per the requirements
of 10 CFR 50.46(3)(ii). The report included evaluation of the HPSI flow reduction for
both the Large Break Loss of Coolant Accident (LBLOCA) and Small Break Loss of
Coolant Accident (SBLOCA).
For the evaluation of LBLOCA, the licensee reported that the reduction in HPSI flow had
no impact on the predicted peak cladding temperature (PCT). The PCT for LBLOCA
continues to be 1581 degrees Fahrenheit. The inspectors observed that HPSI is a
system primarily designed to mitigate the effects of small break LOCAs, and did not
identify any issues with this estimate.
The licensee estimated the effect of HPSI flow reduction on the SBLOCA analysis,
and determined that the limiting break size decreased from a 3.5 inch diameter break to
a 3.0 inch diameter break. The HPSI flow reduction also caused an increase in PCT of
309 degrees Fahrenheit. The resulting PCT for SBLOCA is 1746 degrees Fahrenheit.
The inspectors determined that the revised PCT for the SBLOCA analysis reflects that
the licensee considered, in its estimate, both the effect of the change on the predicted
PCT for the limiting break size, and the potential for a new break size to be more
limiting. The licensees estimate also indicates that the estimated PCT remains below
the 2200 °F acceptance criterion contained at 10 CFR 50.46(b)(1).
The inspectors did not identify any issues of significance related to the technical content
of the 10 CFR 50.46 report. A violation was identified regarding the timeliness of this
report, as discussed in section 4OA3.2.d.1 of this report.
c. Review of Emergency Core Cooling System Performance
A review of Emergency Core Cooling System (ECCS) design and performance was
conducted by staff from the Reactor Systems Branch (SRXB) in the Office of Nuclear
Reactor Regulation (NRR). The review included an audit of High Pressure Safety
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Injection (HPSI) pump operability, containment spray (CS) pump operability, vortex
issues, and void transport characteristics.
HPSI Pump Characteristics
A historical OPPD document was reviewed which listed developed head data for the
HPSI 2A, 2B, and 2C pumps as a function of flow rate. Recent pump vendor (Sulzer
Pumps, Inc.) analyses were reviewed which addressed expected degradation due to
wear by assuming that internal clearances may be postulated to increase by multiples of
1.5 and 2.0 applied to the nominal design clearances. Analysis results were determined
to be reasonable and the methodology appears to have been successfully applied by
Sulzer for other applications.
The original seal water cyclone separators did not have sufficient flow to provide self-
cleaning and were replaced. Recent evaluations of the replaced separators established
that the seal water system will operate acceptably.
HPSI Pump Runout Control
The licensees 2013 modification to the HPSI system acceptably limited HPSI pump flow
rate to less than 450 gpm. This was accomplished by inserting orifices in the pump
discharge pipes followed by testing that showed that the maximum flow rate occurred
with HPSI Pump 2B at 402 gpm with no flow in the mini-flow lines. Historical information
acceptably showed that open miniflow lines would increase runout flow rate by about
2 gpm, a negligible effect.
Orifice installation affected predicted ECCS evaluation model performance pursuant to
the requirements of 10 CFR 50.46. This was addressed by the licensee consistent with
the requirements of 10 CFR 50.46(3)(ii). The licensee reported that there was no impact
on the predicted peak cladding temperature (PCT) for the large break loss-of-coolant
accident (LBLOCA) and that PCT for the small break loss-of-coolant accident (SBLOCA)
increased by 309 °F to 1746 °F. Predicted PCTs remained below the 2200 °F
acceptance criterion contained at 10 CFR 50.46(b)(1). SRXB did not identify any issues
of significance.
Containment Spray (CS) Pump Runout Control
The CS pumps were recognized as subject to runout for two scenarios and the licensee
elected to address this issue by throttling the discharge valves to limit flow rate.
Containment aspects were found acceptable by the NRR Containment & Ventilation
Branch (SCVB) and valve characteristics were addressed by the Division of Engineering
Mechanical and Civil Engineering Branch and found acceptable. SRXBs assessment of
pump and motor issues is covered in the following paragraph.
The licensee used PROTO-FLO software to conclude that runout would be controlled
by changing flow rate from 1885 to 1500 gpm and from 3770 to 2800 gpm for the
single pump and two pump operating conditions, respectively. This was determined
to be achieved if each pump discharge valve was throttled to achieve a flow rate of
- 20 -
2515 +/- 25 gpm in a lineup where one CS pump draws from and recirculates back to the
Safety Injection Refueling Water Tank (SIRWT). 43 cases were analyzed by PROTO-
FLO plus another 10 cases to tune the code. SRXB determined that PROTO-FLO
acceptably calculated flow behavior. SRXB also determined that flow rate could be
acceptably controlled by the number of valve turns that correlated to calculated valve
opening.
SIRWT Draining, Vortex, and Void Movement Considerations
The SIRWT is a 25 ft by 100 ft rectangular tank with two ECCS 19.25 inch inside
diameter suction lines at one end. A cruciform vortex suppresser that extends into the
tank is installed in the entrance to each suction line. The SRXB inspectors performed an
exhaustive review of previous modeling of the SIRWT performance by a vendor, Fauske
& Associates. The inspectors noted that the analysis performed by Fauske &
Associates, and accepted by OPPD, contains a number of conservative as well as non-
conservative errors. The licensee documented the inspectors observations in
CRs 2013-21824 and 2013-21936. The licensee performed an immediate operability
determination which demonstrated that the cumulative impact of the errors did not
threaten the safety function of the SIRWT or the associated ECCS systems. The
inspectors reviewed this operability determination and concluded that it acceptably
addressed the inspectors concerns. The licensee also assigned several corrective
actions to update the affected analyses. Lastly, the licensee entered Action 2 from
CR 2013-21936 into the Performance Improvement Integrated Matrix (PIIM 2013-0086)
to track the licensees response to the inspectors observations prior to startup from the
next refueling outage.
Measurement of Flow Rate
The licensee documented inaccuracies in the installed HPSI flow rate instrumentation
that required installation of temporary ultrasonic flow rate meters (UFMs). The
inspectors determined that the UFMs provided accurate indication of flowrate. The
inspectors also noted that the installed instrumentation was of sufficient accuracy to
support use by operations during emergency conditions, but the inaccuracies prevented
appropriate flow indications for periodic pump testing as required by Technical
Specifications.
Water Hammer
Fauske described an experimental and analysis methodology program to assess water
hammer. The program showed that: (1) the gas void fraction for the initial stratified gas-
water configuration is essentially preserved during the water hammer event, (2) the peak
water hammer pressure is determined by the initial gas pressure and volume, the pump
shutoff head and whether the system is flushed before the test conditions are
established, (3) the peak force generated by the gas-water water hammer event is
determined by the peak pressure and the rate of rise of the water hammer
pressurization, (4) if the system piping includes a swinging check valve, the closure
induced by the water hammer event can cause subsequent forces, in both axial
directions (upstream and downstream), that are larger than the water hammer induced
- 21 -
force, and (5) the peak forces are a function of both the piping configuration and the
initial gas volume.
The licensee provided a water hammer evaluation of voids in suction piping. The
evaluation assumed that the moving gas/water column would instantaneously encounter
a rigid wall that corresponded to the HPSI suction location in an approach similar to that
provided by Fauske. There appear to be no cases where water hammer due to
compression of gas voids has caused actual pipe breaks. Therefore, SRXB judged that
water hammer is not of significant concern with respect to HPSI operation.
A violation was identified regarding the design control attributes of this inspection, as
discussed in Section 4OA3.2.d of this report.
d. Findings
i. Failure to Make Required 10 CFR 50.46 Report Within Required Time
Introduction. The inspectors identified a SLIV non-cited violation of 10 CFR 50.46,
Acceptance criteria for emergency core cooling systems for light-water nuclear
power reactors, for the licensees failure to submit a report within 30 days of
discovery of a significant change in the application of the ECCS model that affected
the peak cladding temperature.
Description. 10 CFR 50.46(a)(3)(i) states, in part, that each licensee shall estimate
the effect of any change in the application of an ECCS cooling evaluation model, to
determine if the change is significant. A change is considered significant if it results
in a calculated peak fuel cladding temperature different by more than 50° F from the
calculation of record. Paragraph (ii) requires that any significant change be reported
within 30 days to the NRC staff. 10 CFR 50.46(b)(1) provides an upper limit of
2200°F for maximum fuel element cladding temperature.
In early 2013, the licensee determined that a plant modification would be necessary
to prevent the runout of the installed high pressure safety injection (HPSI) pumps
during accident scenarios. This modification, which was installed in June 2013,
included installation of flow-restricting orifices in the discharge line of each HPSI
pump. As a result of the lower injection flows expected after the modification, the
licensee contracted an engineering firm to complete an analysis of the expected
increase in fuel temperatures that could be expected in an accident. The vendor
completed the analysis on July 26, 2013, which showed that in the most limiting
scenario, a small break loss of coolant accident, the reduced HPSI flow rates would
cause a 309° F increase in the peak cladding temperature. The licensee adopted
the vendors result in Engineering Analysis13-023, Fort Calhoun SBLOCA Analysis
with Reduced HPSI Flow (AREVA Calc. 32-9130020-001) on August 16, 2013, and
determined that the peak cladding temperature in the most limiting scenario (small
break loss of coolant accident) would be 1846°F, still well below the limit of 2200°F
specified in 10 CFR 50.46.
- 22 -
On August 1, 2013, the licensees staff initiated CR 2013-15442, documenting that
the AREVA report demonstrated the need to submit a 30 day report as required by
10 CFR 50.46(a)(ii). An action was assigned in the condition report to complete a
reportability evaluation by August 9 2013. A draft 10 CFR 50.46 report was created
by the condition report originator and provided to the Regulatory Assurance
department on August 12, 2013.
The licensees Regulatory Assurance department subsequently canceled the
reportability determination on August 27, 2013, and documented that the
10 CFR 50.46 reporting requirement did not apply. To justify this action, the
Regulatory Assurance staff provided the following quote from Nuclear Energy
Institute (NEI) Guide 07-05, 10 CFR 50.46 Reporting Guidelines, July 2008,
Section 2.2.11, Input Information:
The first category of input information is the basic engineering information that
describes a specific plant A change to input information of this type is not
considered a change to the evaluation model. Changes and error corrections in
this category are not reportable under 10 CFR 50.46.
The licensees position was that this type of change was not controlled by
10 CFR 50.46, and that any required action would be identified through compliance
with 10 CFR 50.59, Changes, Tests, and Experiments. The inspectors noted that
NEI 07-05 was not endorsed by the NRC staff, and sought guidance from the staff
responsible for reviewing 10 CFR 50.46 ECCS analysis at the Office of Nuclear
Reactor Regulation. Headquarters staff confirmed that the position described in
NEI 07-05 was not endorsed by the NRC and contradicts the requirement of
10 CFR 50.46(a)(3)(ii) which states, in part, that:
For each change toan acceptable model or in the application of such a model
that affects the temperature calculation, the holder of an operating
licenseshall report the nature of the change or error
Additionally, the inspectors noted that the NRC has endorsed NEI 96-07, Guidance
for Implementation of 10 CFR 50.59, Changes, Tests and Experiments, Revision 1.
NEI 96-07 specifically identifies that changes in anticipated fuel cladding temperature
are controlled by 10 CFR 50.46 and would not be subject to the process defined by
The inspectors noted that the licensees procedure for completing reportability
determinations contributed to this error. Procedure SO-R-1, Reportability
Determinations, Attachment 8, paragraph 3.4.2 directs the licensees staff to follow
the format provided in NEI 07-05 for preparation of 30 day written reports. While the
report format in NEI 07-05 is generally consistent with 10 CFR 50.46, NEI 07-05
contains reportability guidance that is contrary to NRC regulations. This position
was communicated to the licensee by the NRC staff on September 12, 2013, and
the licensee was informed that the required report had not been submitted within
30 days as required by 10 CFR 50.46(a)(ii).
- 23 -
The licensee submitted the required 10 CFR 50.46 report September 20, 2013
(ML13266A108). This report was subsequently reviewed by the NRC staff date
October 2, 2013, and determined to be acceptable. The NRC staff determined that
while the configuration change to the HPSI system resulted in a significantly higher
peak cladding temperature, it is within the regulatory requirements of
The licensee initiated CR-2014-00674 on January 16 2014 to document the late
report submittal. The licensee initiated CR 2014-01356 on January 29, 2014 to
document the fact that Procedure SO-R-1 refers to NEI guidance, which is not
endorsed by the NRC.
Analysis. The failure to submit a written report within 30 days of discovery of a
significant change to the ECCS peak cladding temperature analysis is contrary to the
requirements of 10 CFR 50.46(a)(ii) and is a performance deficiency. This
performance deficiency was determined to be subject to traditional enforcement
because it impeded the regulatory process, in that the failure to submit a timely
report of significant ECCS analytical changes prevented the NRC technical staff from
independently evaluating the potential safety implications of reductions in safety
injection flow into the reactor during an accident. This violation was determined to be
a Severity Level IV violation, because it is consistent with the examples in
Paragraph 6.9.d of the NRC Enforcement Policy. Because this violation is subject to
traditional enforcement, no cross-cutting aspects have been assigned.
Enforcement. 10 CFR 50.46, Acceptance criteria for emergency core cooling
systems for light-water nuclear power reactors, states, in part, that any
significant change to a limiting ECCS analysis shall be reported to the NRC
within 30 days. Contrary to this requirement, the licensee determined that a
significant change had been made on August 1, 2013, but failed to submit the
required report until September 20, 2013. This violation is being treated as an
NCV, consistent with Section 2.3.2.a of the Enforcement Policy. The violation was
entered into the licensees corrective action program as CR 2014-00674.
(NCV 05000285/2014002-01, Failure to Make Required 10 CFR 50.46 Report
Within Required Time)
ii. Failure to Translate HPSI Pump Design Requirements to Design Documents
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50,
Appendix B, Criterion III, Design Control. Specifically, the licensee failed to
translate HPSI pump design and runout characteristics to design documents such as
the Updated Safety Analysis Report or design calculations.
Description. The emergency core cooling systems (ECCS) at Fort Calhoun Station
are designed to provide safety injection flow during various loss of coolant scenarios.
One of these systems, the high pressure safety injection (HPSI) system, contains
three centrifugal pumps which are capable of injecting water at high pressures into
- 24 -
each of the four reactor coolant loops. The inspectors noted that the original pump
curves provided by the manufacturer demonstrated expected pump performance to a
maximum tested flow of 425 gpm. Pump flows beyond the tested limits are
generally considered to be runout conditions, which can lead to rapid degradation of
pump internals and overload of pump motors.
The inspectors reviewed pre-operational testing reports from 1972 that demonstrated
initial attempts to prevent runout of the HPSI pumps. Additionally, special testing
was documented in 1976 that adjusted loop injection flows to avoid runout of the
pumps. Despite the constraints of the original design, on April 29, 1977, the licensee
removed the limit switch settings from the loop injection valves in an attempt to
increase HPSI injection flow based on un-validated information from the vendor that
HPSI pump runout for short periods of time was acceptable. The licensees
emergency procedures still contained steps that directed the operators to maintain
HPSI total flow below 400 gpm by manually throttling the loop injection valves, so the
net effect of this design change was to move the flow limiting design feature from an
automatic to a manual action. In a letter dated June 30, 1977, the NRC staff notified
OPPD of the safety importance of avoiding runout conditions in HPSI and LPSI
systems, and requested that the licensee determine if throttle valves were used in
the design to perform this function.
Other operational and design changes were made in the ensuing years that reduced
margins to runout conditions. These changes included changes to emergency
operating procedures that required HPSI to run at full capacity until certain throttling
criteria were met; cross-connecting HPSI trains to pressurize a containment
penetration; and ECCS logic changes which extended length of HPSI injection phase
prior to Recirculation Actuation Signal (RAS) beyond the limit proposed by the
vendor.
On January 30, 2013, while performing analysis in support of a planned modification,
the licensees staff determined that design basis calculations indicated that the HPSI
pumps would operate in a run out condition in some design basis accident
conditions. The licensee documented this condition in CR 2013-02100, which was
screened as Significance Level 2 and assigned a low-tier apparent cause evaluation.
The low-tier apparent cause evaluation was completed on March 21, 2013, and
documented that the apparent cause was that the station failed to obtain vendor
technical information in a 10 CFR 50, Appendix B, validated format. One
contributing cause was identified in that design basis documentation for the HPSI
system was lacking. The licensee submitted LER 2013-003-0 to the NRC on
April 1, 2013, reporting the unanalyzed condition. This LER also described the
apparent cause and planned corrective actions.
On May 21, 2013, due to a documented concern of potential NRC escalated
enforcement action, CR 2013-02100 was re-categorized as Significance Level 1 and
assigned a root cause investigation. The subsequent root cause evaluation was
completed on July 4, 2013. The licensee identified that the root cause was a lack of
rigorous engineering processes that allowed reductions in margin to runout. The
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report also identified two contributing causes, in that the pump vendor had supplied
inaccurate information to the licensee, and incomplete design basis documentation.
One action to prevent recurrence was identified, as well as four new corrective
actions.
On July 11, 2013, NRC inspectors met with the licensee to discuss inspector
concerns with the root cause analysis. The inspectors shared a concern that over-
reliance on technical information from the pump vendor without adequate technical
review had prevented the licensee from recognizing this design control issue. The
licensee documented the inspectors concerns in CR 2013-14177. Following this
meeting, the licensees staff revised the root cause analysis on August 27, 2013.
This revised report identified a different root cause, in that HPSI pump impeller
design and runout characteristics identified during pre-operational testing were not
translated into FCS design and licensing basis documents. Several contributing
causes were also identified, including: limited staff understanding of HPSI pump
design; informal engineering evaluation of vendor-supplied information; failure to
internally communicate significance of identified concerns; and failure of the
corrective action program to react to adverse trend in vendor calculation
inaccuracies. This report also identified two actions to prevent recurrence and
19 corrective actions.
On August 28, 2013, NRC inspectors met again with the licensees staff to discuss
details from the July 4, 2013 version of the root cause analysis and LER 2013-003-0.
The licensee again revised the root cause analysis on September 12, 2013, adding
another contributing cause in that the licensee had failed to appropriately respond to
the NRCs June 1977 letter that specifically warned of the runout concern.
On June 21, 2013, the licensee completed Engineering Change 59874, which
permanently installed flow-limiting orifices in the discharge line of each pump,
effectively preventing HPSI pump runout conditions from occurring in any plant
condition. The inspectors reviewed this design change package, performed field
inspections of the completed modifications, and reviewed the results of the
completed post-modification testing. The inspectors also noted that the licensee had
completed a number of actions and has planned a broad range of programmatic
corrective actions to improve maintenance and knowledge of the plants design and
license basis.
On November 27, 2013, the licensee submitted Revision 1 to the LER to update the
cause and corrective actions taken for the condition.
Analysis. The inspectors determined that the licensees failure to translate HPSI
pump design and runout characteristics to design documents such as the Updated
Safety Analysis Report or design calculations was a performance deficiency. This
finding was more than minor because it adversely impacted the design control
attribute of the Mitigating Systems Cornerstone objective of ensuring the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences.
- 26 -
The inspectors reviewed IMC 0609 Attachment 4, Initial Characterization of
Findings, Table 3 - SDP Appendix Router. While this issue was identified during a
refueling outage, the inspectors determined that the majority of the exposure time for
this violation occurred with the reactor at power. As such, the inspectors determined
the finding should be evaluated using the SDP in accordance with IMC 0609, The
Significance Determination Process (SDP) for Findings at-Power, Appendix A,
Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed
risk evaluation because the high pressure safety injection system was inoperable for
some of the large break loss of coolant accident scenarios (at reactor pressures less
than 100 psi). Therefore, a Region IV senior reactor analyst performed a detailed
risk evaluation.
The analyst used the Fort Calhoun Standardized Plant Analysis Risk (SPAR) model,
Revision 8.20 with a truncation limit of E-11 to evaluate this performance deficiency.
Two Pumps Running Scenario: The licensees vendor calculated the expected
pump runout conditions. The vendor determined that runout conditions would occur
at a pump flow of 467 gallons per minute. At this flow rate, the pump discharge
pressure would be 244 psia. This particular scenario assumed two high pressure
safety injection pumps were running into two headers. The corresponding reactor
vessel pressure would be about 100 psia. Its important to note that the low pressure
safety injection system can support early injection and recirculation at this reactor
pressure. Experts from the NRCs Office of Nuclear Reactor Regulation reviewed
the calculation and found no significant errors.
For an initial risk estimate, the analyst set the failure to run basic events for the high
pressure safety injection pumps to a failure of 1.0. This included the train A and B
pumps as well as the swing Pump C. However, the analyst noted that the model
was not properly failing the pumps in some instances. Each time a high pressure
safety injection pump was included in the cutsets, the pump should have failed with a
probability of 1.0. In some instances the model failed the pump for other reasons
with a nominal failure probability (such as 3.8E-3 for being in test and maintenance).
To account for these errors, the analyst set the remaining high pressure safety
injection pump basic events (failure to start, and test and maintenance) to a failure
probability of 1.0.
Next the analyst determined that only the loss of coolant accident sequences were
affected by the performance deficiency. The analyst considered the following
definitions from the SPAR model documentation:
Small Loss of Coolant Accident - The small loss of coolant accident initiating
event is defined as a steam or liquid break in the reactor coolant system other
than a steam generator tube rupture which exceeds normal charging flow. In this
break size range, normally defined as between 3/8 in. and 2 in., normal charging
cannot maintain pressurizer level.
Medium Loss of Coolant Accident - The medium break loss of a coolant
accident initiating event is defined as a steam or liquid break that is large enough
- 27 -
to remove decay heat without using the steam generators but small enough that
RCS pressure is above the accumulator and low pressure injection system
shutoff pressure.
Large Loss of Coolant Accident - The large loss of coolant accident initiating
event is defined as a steam or liquid break that is large enough to rapidly
depressurize the reactor coolant system pressure to a point below the low
pressure injection and safety injection tank shutoff pressure. This break size is
generally defined as being greater than 5 in.
Interfacing System Loss of Coolant Accidents - Interfacing system loss-of-
coolant accidents are a class of accidents that can result in the over-
pressurization and rupture of systems that interface with the reactor coolant
system outside containment. These accidents have been a concern with regard
to public health risk due to the potential for fission product release directly to the
environment, bypassing the containment structure.
The analyst determined that only the large break and interfacing system loss of
coolant accidents should be quantified for this first scenario. In short, small and
medium break loss of coolant accidents would result in reactor pressure remaining
above the low pressure safety injection (195 psig) and safety injection tank
(240 psig) shutoff head conditions, especially considering that a high pressure safety
injection pump would be initially running. While it was possible to depressurize
below 195 psig as part of a normal shutdown, the residual heat removal system
would be employed for this purpose. This would aid operators in that they would
have control over decay heat removal and plant pressure. With the residual heat
removal system in operation, the high pressure safety injection system was not as
risk important.
Thus far, with the previously noted assumptions, the Delta-CDF was 2.8E-6/year.
The analyst noted that the SPAR model loss of coolant accident event tree did not
credit the low pressure safety injection system for early recirculation. If the high
pressure safety injection pumps failed during early recirculation, the event tree
transitioned directly to core damage. This was inconsistent with Emergency
Operating Procedure 20, Functional Recovery Procedure, Revision 25, in that the
procedure directed operators to inject with the low pressure safety injection system
for certain conditions (which include low pressure recirculation).
The low pressure safety injection pumps were capable of supporting recirculation
provided the reactor pressure was sufficiently low to allow pump operation. The low
pressure safety injection pumps provided a nominal discharge pressure of 175 psi.
The shutoff head for the pumps was approximately 194 psi. Since, however, the
reactor pressure of concern was 100 psi or less, the low pressure safety injection
pumps were capable of providing the recirculation function.
Given a high pressure safety injection system failure, the analyst determined that
credit for low pressure safety injection recirculation should be provided. To provide
- 28 -
credit, the analyst solved the low pressure recirculation fault tree to determine the
overall system failure probability (1.3E-3). Since the pumps automatically tripped on
a recirculation actuation signal, operators would need to manually start and align the
pumps for injection. The nominal human error probability from NUREG/CR-6883,
The SPAR-H Human Reliability Analysis Method, was 1.1E-2. The analyst added
these two values together for a total failure probability of 1.2E-2.
With this credit, the resultant Delta-CDF was:
Delta-CDF = 2.8E-6 * 1.2E-2 = 4E-8/year
This result was conservative because the analyst provided no credit for operator
recognition of runout conditions or mitigating actions to preclude pump damage.
Operators received training on runout conditions but it was unclear if adequate
indications were available in the control room.
One Pump Operating Scenario: The analyst considered a second scenario where
only one of the high pressure safety injection pumps was available for injection - the
other two pumps were unavailable because of random failures or for maintenance.
For this scenario, the analyst could not conclude that reactor pressure would be
sufficiently low to allow the low pressure safety injection system to inject. Therefore,
no credit was provided for this function.
The SPAR model specified that the failure probability for a single high pressure
safety injection pump (including unavailability for maintenance) was 5.1E-3. Since
there are two normally aligned pumps, either pump could be unavailable. The
probability that either the A or B pump was unavailable was approximately 1.2E-2. In
addition, if one pump failed or was unavailable, operators could place the swing high
pressure safety injection pump into service. The analyst considered that operators
could fail to properly perform this action. The nominal human error probability for an
operator manual action was 1.1E-2. As with the A and B pumps, the pump could
fail once placed into service, or otherwise be unavailable because of maintenance.
The total unavailability for the C pump was 1.2E-2 + 1.1E-2 = 2.3E-2. Therefore,
the total probability that only one pump would be available for injection
was 1.2E-2 * 2.3E-2 = 2.8E-4.
The analyst used the SPAR model and set the high pressure safety injection pump
common cause failure to run probability to 2.8E-4. This meant that if two pumps
were unavailable, the third pump would fail. The nominal common cause failure to
run probability was E-7.
This particular scenario was identified during plant simulator demonstrations.
Specifically, for a 3 inch pipe break, and one pump running, the inspectors identified
that it was possible for the high pressure safety injection pump to fail without first
lowering reactor pressure to less than the low pressure safety injection pump
discharge head. This correlated to the medium break loss of coolant accident in the
- 29 -
NRCs SPAR model. Therefore, the analyst solved the medium break loss of coolant
accident and the intersystem loss of coolant accident sequences.
The analyst noted that this assumption was generally inconsistent with the SPAR
model bases document, in that the medium break loss of coolant accident pressure
could drop below the accumulator shutoff pressure (about 275 psig). Plant pressure
would need to drop below this pressure to establish the runout conditions where
pump damage could occur.
The Delta-CDF was 4.2E-8/year.
Total Delta-CDF: The total Delta-CDF was:
Delta-CDF = 4E-8 + 4.2E-8 = 8.2E-8/year
The analyst determined that the finding was of very low safety significance (Green).
The dominant core damage sequences included large break loss of coolant
accidents where the high and low pressure safety injection systems both failed
during early low pressure recirculation. The low pressure safety injection system
helped to minimize the risk.
Since the change to the core damage frequency was less than E-7, the analyst was
not required to evaluate 1) external events, or 2) the effect on the large early release
frequency.
The inspectors determined there was no cross-cutting aspect associated with this
finding because events related to identification of needed procedures and
specifications occurred in the 1970s and are not indicative of current performance.
Enforcement. 10 CFR 50, Appendix B, Criterion III, Design Control states, in part,
that measures shall be established to assure that applicable regulatory
requirements and the design basis, as defined in 10 CFR 50.2, for those structures,
systems, and components to which this appendix applies are correctly translated into
specifications, drawings, procedures, and instructions. Contrary to this requirement,
from April 29, 1977 to June 21, 2013, the licensee failed to translate HPSI pump
design and runout characteristics to design documents. This violation is being
treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. The
violation was entered into the licensees corrective action program as
CR 2013-02100. (NCV 05000285/2014002-02, Failure to Translate HPSI Pump
Design Requirements to Design Documents)
.3 (Closed) LER 05000285/2013-007-01: Containment Air Cooling Units (VA-16A/B) Seismic
Criteria
CR 2013-02260 identified that a summary structural analysis (FC03901) indicated that
VA-15A/B (Containment Air Cooler/Filter) plenum was overstressed by 100 percent and that
VA-16A/B (Containment Air Cooler) plenum would have been overstressed during a design
- 30 -
basis seismic event. At the time of discovery, FC03901 indicated that VA-15A/B required
cross-bracing, which was added resulting in the equipment being operable. Since VA-16A/B
was overstressed, they were considered inoperable.
The licensee causal analysis determined that the design basis information was incomplete
at the beginning of commercial operation. A weakness in licensing basis knowledge and a
failure to internalize the importance of the design basis, resulted in the organization missing
repeated opportunities to correct the initial deficiencies and additional errors were created
over time. Also, 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. This resulted
in long-standing, reinforced, and institutionalized behaviors that resisted external and
internal efforts to change.
The NRC identified the overstressed containment air cooler issue, and documented
non-cited violation NCV 05000285/2013012-04, Failure to adequately design containment
air coolers structural bracing in Inspection Report 0500285/2013-012 (ML 13144A772).
After the inspection report was issued, the licensee performed additional analysis that
concluded the containment coolers were inoperable, but would have been able to perform
their safety function. In addition, containment air coolers VA-16A and VA-16B were modified
to add structural bracing prior to plant restart.
This Licensee Event Report is Closed.
.4 (Closed) Licensee Event Report 05000285/2013-010-01: HPSI Pump Flow Imbalance
a. Inspection Scope
On May 3, 2013, it was identified that the high pressure injection pump injection flows to
the reactor coolant system were not balanced in accordance with the Fort Calhoun
Station (FCS) Updated Safety Analysis Report Section 14.15.5.2.
The licensee submitted LER 2013-010-0 on July 2, 2013 to report a condition that could
have prevented the fulfillment of a safety function, and as a condition that caused
multiple trains of a safety system to become inoperable. The initial revision of this LER
contained very little detail and stated that a supplemental report would be made
following completion of a causal analysis. The licensee completed an apparent cause
evaluation in CR-2013-09949 on October 2, 2013, and subsequently issued Revision 1
of this LER on October 23, 2013.
The licensee determined that the cause of the event was failure to translate the plant
physical design into design documents, which allowed plant engineers to modify
important plant design aspects without understanding the potential safety impact. The
licensee implemented a design change to restore balanced flows in the HPSI injection
lines and updated design documents to reflect the importance of maintaining balanced
injection flows.
- 31 -
This Licensee Event Report is closed.
b. Findings
i. Failure to Maintain Design Control of HPSI Injection Valves
Introduction. The inspectors identified two examples of a Green non-cited violation
of 10 CFR 50, Appendix B, Criterion III, Design Control. The first example involved
the licensees failure to establish procedures or technical specifications to
accomplish required HPSI injection flow balancing. The second example involved
the failure to provide controls or testing to ensure that replacement parts for HPSI
injection valves were suitable for the application and were capable of supporting the
safety-related functions of the HPSI system.
Description. The emergency core cooling systems (ECCS) at Fort Calhoun Station
are designed to provide safety injection flow during various loss of coolant scenarios.
One of these systems, the high pressure safety injection (HPSI) system, contains
three centrifugal pumps which are capable of injecting water at high pressures into
each of the four reactor coolant loops. Each loop is provided with an injection line
from the A and B HPSI train, and as such the HPSI system provides a total of eight
injection lines into the reactor coolant system. Each injection line is provided with a
motor-operated injection valve to allow isolation or throttling of flow.
The original safety evaluation report for Fort Calhoun Station did not specifically
describe the balancing of HPSI loop injection flow rates. Injection line flow balancing
was, however, part of original plant design, and was accomplished by the use of limit
switches on each injection valve that stopped the valve travel at a pre-defined
position. The inspectors reviewed pre-operational testing reports from 1972 that
established these balanced flows. Additionally, special testing was documented in
1976 that adjusted loop injection flows to maintain this balance.
Despite the constraints of the original design, in April 1977 the licensee removed the
limit switch settings from the loop injection valves in an attempt to increase HPSI
injection flow. This had the unrecognized and undesirable effect of defeating the
original design intent of maintaining balanced loop injection flows. The licensees
emergency procedures still contained steps that directed the operators to maintain
balanced injection flows, so the net effect of this design change was to move the flow
balancing design feature from an automatic to a manual action.
In a letter dated June 30, 1977, the NRC staff notified OPPD of the safety
importance of maintaining balanced loop injection flow rates from the HPSI and LPSI
systems, and requested that the licensee determine if throttle valves were used in
the design to achieve the required flow balance. The letter further requested that if
throttle valves were used, the licensee should propose changes to technical
specifications to add a specific set of surveillance requirements that were included as
an attachment to the NRC letter.
- 32 -
The licensee provided a brief response to this letter on August 22, 1977, which
stated that throttle valves were not used to obtain the needed flow distribution from
the HPSI or LPSI systems. The licensee failed to inform the NRC that they had
originally been designed with throttled loop injection valves, but had removed this
important design feature just prior to receiving the letter from the NRC. As a result,
the surveillance requirements described in the June 30, 1977 letter were not added
to the Fort Calhoun Station Technical Specifications. The NRC staff reviewed this
correspondence against the requirements of 10 CFR 50.9, Completeness and
Accuracy of Information, and determined that due to the age of the issue no
enforcement action was appropriate (this regulation did not exist at the time of the
inaccurate communication). The inspectors noted that the licensee has documented
this inaccurate communication in CR 2013-09949.
Paragraph 14.15.5.2 of the Updated Final Safety Analysis Report (UFSAR)
describes that the analysis of record for the small-break loss of coolant accident
scenario assumes that the HPSI system flow was modeled to be evenly distributed to
the four reactor coolant system cold legs. UFSAR Paragraph 6.2.1 states that the
HPSI pump minimum flow rate is designed to provide sufficient injection capacity
assuming 25% spillage in the event that one of the four loop injection lines fails.
On April 14, 2013, the license performed a test on HPSI system to benchmark a
hydraulic flow model and determine if runout conditions were possible under Work
Order 480114. CR 2013-08300 was initiated on April 15, 2013, and included the raw
data from the testing, which also demonstrated that the injection flow was not
adequately balanced between the reactor coolant loops as described in the UFSAR.
The licensees safety analysis expected loop flows to be balanced within 10 gpm of
each other. Data collected during the test (see table below) showed differences as
high as 60 gpm between the highest and lowest loop injection flows. As a result, the
assumption in the safety analysis that HPSI could provide minimum flow with 25%
spillage was not satisfied, in that imbalanced injection flows could cause greater than
25% spillage should the line with the highest flow rate fail in an accident.
Valve Number RCS Loop Measured
Flow (gpm)
HCV-311 1B 80
HCV-314 1A 75
HCV-317 2A 135
HCV-320 2B 110
CR 2013-09949 was written on May 3, 2013, documenting a concern with the
observed flow imbalance. On June 17, 2013, the licensee calculated the flow
coefficients (Cv) for the eight HPSI injection valves as follows:
- 33 -
Valve Number RCS Loop Measured Cv
HCV-311 1B, Train B 13
HCV-312 1B, Train A 18*
HCV-314 1A, Train B 10
HCV-315 1A, Train A 18*
HCV-317 2A, Train B 22*
HCV-318 2A, Train A 11
HCV-320 2B, Train B 13
HCV-321 2B, Train A 13
- identifies those valves which did not meet design Cv < 13
The licensee discovered that two of the injection valves (HCV-312 and HCV-315)
had been replaced in May 2005 and November 2003, (respectively) with valves from
a different vendor (Flowserve) than the original valves. The licensee specification
sheets for the replacement valves called for a maximum Cv of 13 to match the
existing design. Documents produced by the licensee demonstrated that quality
control issues with the supplied valves required the valves to be returned to the
vendor for disc and seat repairs prior to installation. The post-work testing performed
after these valve replacements included stroke-time testing and motor testing. No
post-maintenance testing was performed to ensure that the as-received valves met
the flow characteristic design requirement to ensure UFSAR assumptions regarding
balanced loop injection flows was sustained. Additionally, the licensee discovered
that the disc for HCV-317 had been replaced in November 1993, with a part that had
been provided meeting the original specification. As with the other valves discussed,
no post-maintenance testing was performed to ensure that the rebuilt valve met the
flow characteristic design requirement.
Licensee Event Report (LER) 2013-010-0 was submitted to the NRC on July 2, 2013
to report that the imbalanced flow issue could have prevented the HPSI system from
performing its safety function. This LER, however, lacked any meaningful details as
the licensee had yet to complete a causal evaluation for the loss of safety function.
The licensees apparent cause evaluation was completed on July 20, 2013 as a
Tier 2 apparent cause report. The initial version of the evaluation identified that the
apparent cause of the flow imbalance problem was inadequate post-maintenance
testing following engineering changes and maintenance to the HPSI loop injection
valves. Related causal factors included failure to identify a surveillance test for flow
balancing, lack of engineering understanding of the HPSI design and licensing basis,
and lack of supervisory technical oversight. Proposed corrective actions included
development of a periodic flow balancing test, revision to post-maintenance testing
- 34 -
instructions, improved technical training and documentation, and an audit of the
vendor who supplied the incorrect valves.
The licensee has since implemented Engineering Change 59874 which includes a
number of design modifications for the HPSI system. One of the included
modifications was re-throttling of the HPSI loop injection valves. This change was
completed on August 20, 2013, restoring the original plant design and correcting the
configuration control errors introduced on three of the eight injection valves. Post-
work testing for the completed modification included flow balance testing for the
HPSI loop injection lines. The inspectors reviewed the results of this testing and
determined that the UFSAR assumptions regarding balanced loop flows are now
reflected by HPSI system performance data.
NRC inspectors began onsite inspection activities related to HPSI system issues on
August 26, 2013. Based upon questions asked by NRC inspectors regarding the
actions proposed for CR 2013-09949, the licensee initiated CR 2013-17630 on
September 13, 2013, entitled Potentially inadequate cause evaluation for an LER.
The text of this CR included the following: Given the current regulatory interest in
this issue it appears that the cause analysis for this issue should receive a more
rigorous cause analysis and station management approval.
The licensee subsequently re-performed the apparent cause evaluation for
CR 2013-09949, and documented the results on October 2, 2013. While the
underlying CR was not upgraded to a higher status, the scope of the revised
apparent cause report scope included Updated the analysis to satisfy ACA Tier 1
requirements due to potential upgrade to ACA Tier 1 per CR 2013-17630. The
updated causal analysis included use of multiple analytical tools and identified two
underlying root causes that were not described in the initial apparent cause report.
The revised report also identified that the apparent cause was more fundamental in
nature, in that the original design of the HPSI loop injection valves was not translated
into design documents, which affected the quality of many processes including post-
maintenance testing. The revised report also identified a contributing cause related
to the licensee failing to appropriately respond to the NRCs June 30, 1977 letter that
provided specific direction to licensees to carefully control the configuration of throttle
ECCS injection valves.
Analysis. The inspectors determined that the licensees failure to establish
procedures or specifications to accomplish required HPSI flow balancing or to
provide appropriate controls or testing for replacement parts was a performance
deficiency. This finding was more than minor because it adversely impacted the
design control attribute of the Mitigating Systems Cornerstone objective of ensuring
the availability, reliability, and capability of systems that respond to initiating events
to prevent undesirable consequences.
The inspectors reviewed IMC 0609 Attachment 4, Initial Characterization of
Findings, Table 3 - SDP Appendix Router. While this issue was identified during a
refueling outage, the inspectors determined that the majority of the exposure time for
- 35 -
this violation occurred with the reactor at power. As such, the inspectors determined
the finding should be evaluated using the SDP in accordance with IMC 0609, The
Significance Determination Process (SDP) for Findings at-Power, Appendix A,
Exhibit 2, Mitigating Systems Screening Questions. The inspectors answered yes
to the question of Does the finding represent a loss of system operability and/or
function? The inspectors therefore determined that the finding would require a
detailed risk evaluation per IMC 0609 Paragraph 6.0, because the operability of the
high pressure safety injection system (both trains) was in question. Therefore, a
Region IV senior reactor analyst performed a bounding detailed risk evaluation.
The analyst noted that the NRCs Standardized Plant Analysis Risk model included
system functional success criteria. The high pressure safety injection system
functional success criteria specified: delivery of water to the reactor vessel using
one high pressure safety injection pump and at least two out of four intact cold legs.
The flow imbalance specified in the functional success criteria was much worse than
the actual flow imbalance identified by the finding. Probabilistic risk assessments
focus on severe core damage whereas design basis requirements are focused on
the potential to exceed emergency core cooling system success criteria and 10 CFR
Part 100 limits, which are much more conservative. Since the high pressure safety
injection system was capable of meeting the functional success criteria, there was no
quantifiable change to the core damage frequency. The finding was not a significant
contributor to the large early release frequency.
The analyst determined that the finding was of very low safety significance (Green).
The dominant core damage sequences included loss of coolant accidents. However,
the high pressure safety injection system remained functional for its probabilistic risk
assessment function, which minimized the risk.
The inspectors determined there was no cross-cutting aspect associated with this
finding because events related to identification of needed procedures and
specifications occurred in the 1970s and are not indicative of current performance.
Additionally, the errant replacement of parts of three HPSI injection valves occurred
between 1993 and 2006, and are also not indicative of current performance.
Enforcement. 10 CFR 50, Appendix B, Criterion III, Design Control states, in part,
that measures shall be established to assure that applicable regulatory
requirements and the design basis, as defined in 10 CFR 50.2, for those structures,
systems, and components to which this appendix applies are correctly translated into
specifications, drawings, procedures, and instructions and that measures be
established for the selection and review for suitability of application of materials,
parts, equipment, and processes that are essential to the safety-related functions of
the structures, systems, and components.
Contrary to this requirement, from June 30, 1977 to present, the licensee failed to
establish procedures or Technical Specifications to accomplish required HPSI
injection flow balancing. Additionally, since October 1993, the licensee has failed to
provide controls or testing to ensure that replacement parts for HPSI injection valves
were suitable for the application and were capable of supporting the safety-related
- 36 -
functions of the HPSI system. This violation is being treated as an NCV, consistent
with Section 2.3.2.a of the Enforcement Policy. The violation was entered into the
licensees corrective action program as CR 2014-02305
(NCV-05000285/2014002-03, Failure to Maintain Design Control of HPSI Injection
Valves).
ii. Failure to Request a License Amendment for Required Change to Technical
Specifications
Introduction. The inspectors identified a Severity Level IV non-cited violation of
10 CFR 50.59, Changes, Tests, and Experiments, and an associated Green
finding, for the licensees failure to request a license amendment for a facility change
that required a change to the Technical Specifications. This issue is also associated
with a Green finding related to the licensees failure to follow Procedure NOD-QP-3,
10 CFR 50.59 and 10 CFR 72.48 Reviews, and Procedure FCSG-23,
10 CFR 50.59 Resource Manual, both of which require submittal of a license
amendment request prior to making a facility change that requires a change to
Technical Specifications.
Description. The emergency core cooling systems (ECCS) at Fort Calhoun Station
are designed to provide safety injection flow during various loss of coolant scenarios.
One of these systems, the high pressure safety injection (HPSI) system, contains
three centrifugal pumps which are capable of injecting water at high pressures into
each of the four reactor coolant loops. Each loop is provided with an injection line
from the A and B HPSI train, and as such the HPSI system provides a total of eight
injection lines into the reactor coolant system. Each injection line is provided with a
motor-operated injection valve to allow isolation or throttling of flow in the injection
line.
The original safety evaluation report for Fort Calhoun Station did not specifically
describe the balancing of HPSI loop injection flow rates. Injection line flow balancing
was, however, part of original plant design, and was accomplished by the use of limit
switches on each injection valve that stopped the valve travel at a pre-defined
position. The inspectors noted that pre-operational testing reports from 1972
established these balanced flows. Additionally, special testing was documented in
1976 that adjusted loop injection flows to maintain this balance.
Despite the constraints of the original design, in April 1977 the licensee removed the
limit switch settings from the loop injection valves in an attempt to increase HPSI
injection flow. This had the unrecognized and undesirable effect of defeating the
original design intent of maintaining balanced loop injection flows. The licensees
emergency procedures still contained steps that directed the operators to maintain
balanced injection flows, so the net effect of this design change was to move the flow
balancing design feature from an automatic design feature to a manual operator
action.
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In a letter dated June 30, 1977, the NRC staff notified OPPD of the safety
importance of maintaining balanced loop injection flow rates from the HPSI and LPSI
systems, and requested that the licensee determine if throttle valves were used in
the design to achieve the required flow balance. The letter further requested that if
throttle valves were used, the licensee should propose changes to the Technical
Specifications to add a specific set of surveillance requirements that were included
as an attachment to the NRC letter.
The licensee provided a brief response to this letter on August 22, 1977, which
stated that throttle valves were not used to obtain the needed flow distribution from
the HPSI or LPSI systems. The licensee failed to inform the NRC that they had
originally been designed with throttled loop injection valves, but had removed this
important design feature just prior to receiving the letter from the NRC. As a result,
the surveillance requirements described in the June 30, 1977 letter were not added
to the Fort Calhoun Station Technical Specifications.
Paragraph 14.15.5.2 of the Updated Final Safety Analysis Report (UFSAR) currently
describes that the analysis of record for the small-break loss of coolant accident
scenario assumes that the HPSI system flow was modeled to be evenly distributed to
the four reactor coolant system cold legs. Additionally, UFSAR Paragraph 6.2.1
states that the HPSI pump minimum flow rate is designed to provide sufficient
injection capacity assuming 25% spillage in the event that one of the four loop
injection lines fails.
On April 14, 2013, the licensee performed a test on HPSI system to benchmark a
hydraulic flow model and determine if runout conditions were possible under Work
Order 480114. The data collected during this test demonstrated that the injection
flow was not adequately balanced between the reactor coolant loops as described in
the UFSAR. As a result, the assumption in the safety analysis that HPSI could
provide minimum flow with 25% spillage was not satisfied, in that imbalanced
injection flows could cause greater than 25% spillage should the line with the highest
flow rate fail in an accident. CR 2013-09949 was written on May 3, 2013, to evaluate
the flow imbalance problem. The initial version of the evaluation identified that the
apparent cause of the flow imbalance problem was inadequate post-maintenance
testing following engineering changes and maintenance to the HPSI loop injection
valves. The licensee also documented a conclusion that the request from the NRC
to initiate a Technical Specification Surveillance to periodically verify balanced flow
was not responded to properly.
On June 17, 2013, the licensee determined the flow characteristics through each
HPSI injection line. During this testing, three of the eight injection valves failed to
meet the flow characteristics expected by the licensee. The licensee subsequently
discovered that injection valves in these three lines had been modified without
controlling their configuration to ensure the flow balancing characteristics of the
design were sustained.
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The licensee has since implemented Engineering Change (EC) 59874 which
includes a number of design modifications for the HPSI system. One of the included
modifications was re-throttling of the HPSI loop injection valves. This change
restored the original plant design, and corrected the configuration control errors
introduced on three of the eight injection valves. Post-work testing for the completed
modification included flow balance testing for the HPSI loop injection lines. The
inspectors reviewed the results of this testing and determined that the UFSAR
assumptions regarding balanced loop flows are now reflected by plant performance.
While the design of the facility now supports the safety analysis, the plant Technical
Specifications no longer meet the criteria of 10 CFR 50.36. Specifically,
10 CFR 50.36(c)(3) requires that Technical Specifications include sufficient
surveillance requirements to assure that....facility operation will be within safety
limits, and that limiting conditions for operation will be met. As specified in the
NRCs letter of June 30, 1977, the use of throttle valves to ensure balanced loop
injection flow rates requires periodic surveillance testing. Current Technical
Specifications at Fort Calhoun Station do not include these surveillance tests. The
inspectors determined that the need for a Technical Specification change was
recognized by station personnel early in 2013. In a meeting with station
management on July 30, 2013, engineering staff who were leading the design
change effort documented their plans to submit a license amendment request to add
the needed surveillance requirement to the Technical Specifications prior to
completion of the modification.
On September 18, 2013, the proposed design change in EC 59874 was presented to
the Station Modification and Acceptance Review Team (SMART) for review in
preparation for approval by the Plant Review Committee. According to the minutes
of the meeting, the licensees staff initially proposed that the needed flow balancing
tests would be performed as surveillance tests in the future as required by
10 CFR 50.36(c)(3). The meeting minutes record that the decision was made by the
SMART to perform future flow balancing as a preventative maintenance task rather
than as a surveillance test. Discussions with participants in the meeting suggest that
station personnel expected that a license amendment request (LAR) would be
submitted sometime in the future to formalize the new maintenance procedure as a
surveillance test.
The final modification package for EC 59874 included a 10 CFR 50.59 applicability
determination form which was completed on October 2, 2013. This applicability
determination form required the reviewer to determine if the proposed activity
involved a change to the Technical Specifications or operating license. This question
was incorrectly answered in the negative. This response was contrary to the
licensees procedure. Procedure NOD-QP-3, 10 CFR 50.59 and 10 CFR 72.48
Reviews, Step 4.8.3 states the following; Any activity requiring prior NRC approval
or requiring a change to the Technical Specifications shall not be approved for
implementation until NRC approval has been obtained. Additionally, FCSG-23,
10 CFR 50.59 Resource Manual, step 4.2.1.H.1 states the following;
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Per 10 CFR 50.59(c)(1), proposed activities that require a change to the Technical
Specifications.must be made via the license amendment process, 10 CFR 50.90.
Contrary to the requirements of NOD-QP-3 and FCSG-23, EC 59874 was
implemented on October 9, 2013, without the licensee requesting or receiving a
Technical Specification change to add the necessary surveillance requirements for
balancing HPSI injection line flow rates.
The inspectors also noted that during the final review process for EC 59874, a plant
employee serving as the modification independent reviewer documented the
following question: Why is it acceptable to proceed with this EC without a licensing
amendment request? In response the Regulatory Assurance staff incorrectly stated
that it was acceptable to implement the change, and then treat the Technical
Specifications as inadequate. In Paragraph 3.5.1 of EC 59874, the licensee clearly
stated the intention to use the guidance of NRC Administrative Letter (AL) 98-10 to
defer the needed Technical Specification change.
NRC Administrative Letter 98-10, Dispositioning of Technical Specifications That
Are Insufficient to Assure Plant Safety, dated December 29, 1998, was issued to
reiterate to addressees the NRC staffs expectations regarding correction of facility
Technical Specifications (TS) when they are found to contain non-conservative
values or specific incorrect actions. The inspectors contacted NRC staff responsible
for this guidance and validated that AL 98-10 was never intended to allow a facility to
avoid a necessary Technical Specification change prior to implementing a plant
modification. The licensees misapplication of this NRC guidance contributed directly
to a violation of 10 CFR 50.59(c)(1).
The licensee initiated CR 2014-01029 on January 23 2014, to document this
violation and track corrective actions.
Analysis. The failure to follow station procedures which required submittal of a
license amendment request prior to implementing the design change that throttled
HPSI injection line admission valves was a performance deficiency. This
performance deficiency was considered to be of more than minor safety significance
because it was associated with the procedure quality attribute of the mitigating
systems cornerstone and it adversely affected the cornerstone objective to ensure
the availability, reliability, and capability of systems that respond to initiating events
to prevent undesirable consequences. Specifically, the failure to follow station
procedures for the 10 CFR 50.59 process caused the Technical Specifications to
become insufficient to ensure that the limiting conditions for operation will be met.
Using Inspection Manual Chapter 0609 Appendix G, Checklist 4, the inspectors
determined that the finding did not result in the loss of any accident mitigation
capability and did not require a quantitative risk assessment. This finding was
determined to be of very low risk significance (Green).
This performance deficiency was also determined to be subject to traditional
enforcement because it impeded the regulatory process, in that the failure to submit
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a license amendment and add required surveillance testing was in violation of
10 CFR 50.59(c)(1)(i) and caused the Technical Specifications to be deficient with
respect to balanced HPSI injection flows assumed in the facility safety analysis.
This violation is associated with a finding that has been evaluated by the SDP and
communicated with an SDP color reflective of the safety impact of the deficient
licensee performance. The SDP, however, does not specifically consider the
regulatory process impact. Thus, although related to a common regulatory concern,
it is necessary to address the violation and finding using different processes to
correctly reflect both the regulatory importance of the violation and the safety
significance of the associated finding. This violation was determined to be a Severity
Level IV violation, because it is consistent with the examples in Paragraph 6.1.d of
The finding had a cross-cutting aspect in the training aspect of the human
performance cross-cutting area because the licensees staff failed to understand and
misapplied NRC generic guidance related to discovery of insufficient technical
specifications (H.9).
Enforcement. 10 CFR 50.59, Changes, Tests, and Experiments states in section
(c)(1), in part, that a licensee may make changes in the facility as described in the
final safety analysis report (as updated)without obtaining a license amendment
pursuant to paragraph 50.90 only if: (i) A change to the technical specifications
incorporated in the license is not required Contrary to this requirement, on
October 9, 2013, the licensee made a change to the facility as described in the final
safety analysis report without obtaining a license amendment pursuant to paragraph
50.90 when a change to the technical specifications incorporated in the license was
required. Specifically, the licensee completed a design change that throttled the
HPSI branch line injection valves and invoked a new required surveillance test
without obtaining a license amendment to add the surveillance requirement to
technical specifications. Because this finding was of very low safety significance
(Green), the associated violation was screened as Severity Level IV, and the
violation was entered into the licensees corrective action program as CR 2014-
01029, this violation is being treated as an NCV, consistent with Section 2.3.2.a of
the Enforcement Policy. (NCV 05000285/2014002-04, Failure to Request a License
Amendment for Required Change to Technical Specifications).
iii. Untimely Submittal of Required Licensee Event Reports
Introduction. The inspectors identified two examples of a cited Severity Level IV
violation of 10 CFR 50.73, Immediate Notification Requirements for Operating
Nuclear Power Reactors, for the licensees failure to submit a required licensee
event report within 60 days following discovery of an event requiring a report.
Description.
Example 1:
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Paragraph 14.15.5.2 of the Updated Final Safety Analysis Report (UFSAR)
describes that the analysis of record for the small-break loss of coolant accident
scenario assumes that the HPSI system flow was modeled to be evenly distributed to
the four reactor coolant system cold legs. UFSAR Paragraph 6.2.1 states that the
HPSI pump minimum flow rate is designed to provide sufficient injection capacity
assuming 25% spillage in the event that one of the four loop injection lines fails.
On April 14, 2013, the licensee performed a test on HPSI system to benchmark a
hydraulic flow model and determine if runout conditions were possible under Work
Order 480114. The data collected during this test suggested a possible vibration
concern with the 2B HPSI pump. CR 2013-08300 was initiated on April 15, 2013 to
document the vibration concern. Included with the CR was the raw data from the
troubleshooting, which also demonstrated that the injection flow was not adequately
balanced between the reactor coolant loops as described in the UFSAR. The
licensee sent this data to an off-site vendor for review and analysis.
On May 3, 2013, the licensees staff initiated CR 2013-09949 to document the results
of the evaluation of the April 14 test data. This CR documented the conclusion that
the HPSI injection flows measured on April 14, 2013, were imbalanced, and that as a
result, the assumption in the safety analysis that HPSI could provide minimum flow
with 25% spillage was not satisfied.
An action was assigned from CR 2013-09949 to complete a reportability evaluation
for the condition. This reportability evaluation was assigned on May 17, 2013, and
given a due date of May 24, 2013. The due date for this action was subsequently
extended five times by the licensees staff prior to completion of the reportability
evaluation on June 14, 2013, sixty-one days after the data was observed on
April 14, 2013. Throughout this process, the event date listed was the date that
CR 2013-09949 documented the results of the evaluation of the data, rather than the
date the data was observed by the licensees staff. Additionally, the inspectors noted
that contrary to Procedure SO-R-1, Reportability Determinations, the reportability
evaluation was not reviewed by the Plant Review Committee. After being informed
of this process error, the licensee initiated CR 2014-00958. The inspectors
determined that this process error was of minor safety significance and did not
represent a finding.
The license submitted LER 2013-010-0 on July 2, 2013, sixty days after the initiation
of the CR on May 3, 2013, but seventy-nine days after the flow imbalance was
observed by the licensees staff. The licensee submitted an LER supplement on
October 23, 2013, as LER 2013-010-1.
The inspectors reviewed the LER to determine if it had been submitted with the time
required by 10 CFR50.73. Section 50.73(a)(1), requires, in part, that the licensee
submit a LER for any event of the type described in this paragraph within 60 days
after the discovery of the event. The inspectors noted that the licensees internal
procedure SO-R-1, Reportability Determinations, Revision 31 states in
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Paragraph 4.1.1 that Reportabilities shall be made based on the discovery date for
the event rather than the date when an evaluation of the event is completed in
accordance with NUREG 1022.
The inspectors reviewed the guidance of NUREG 1022, Event Report Guidelines:
10 CFR 50.72 and 50.73, Revision 3, and determined that the language in the
licensees procedure is generally consistent with that of NUREG 1022, Section 2.5,
Time Limits for Reporting. The inspectors noted that the NUREG 1022 guidance
also recognizes that some conditions require evaluation to determine if a reportable
condition exists. In these cases, the NUREG guidance explains that the evaluation
should proceed on a time scale commensurate with the safety significance of the
issue, and that when operability of the affected equipment is in doubt, appropriate
actions such as reporting should be commenced. The inspectors reviewed the
operability determination attached to CR 2013-08300 on April 15, 2013, (which
included the flow imbalance data) and noted that the licensee completed the
associated operability evaluation on same day the CR was written (April 15, 2013).
This operability evaluation documented that the HPSI system was already inoperable
due to the unrelated HPSI runout condition. Additionally, the flow imbalance
condition represented a loss of safety function for the HPSI system, a condition that
would normally require action to place the station in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
and cold shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The inspectors determined that the eighteen day
delay between recording of the flow imbalance data in CR 2013-08300 and the
event date in the licensees reportability evaluation was not appropriate, and was
inconsistent with Procedure SO-R-1 and NUREG 1022. Based upon an event date
of April 15 2013, the LER should have been submitted no later than June 14, 2013,
as required by 10 CFR 50.73(a)(1).
Example 2:
On July 25, 2013, while responding to questions by NRC inspectors regarding runout
susceptibility of the containment spray pumps, the licensee discovered that
anticipated operating conditions during accident scenarios may exceed analyzed
limits for the pumps. The licensee documented this concern in CR 2013-15047.
Specifically, design basis calculations and vendor information for the containment
spray system did not describe acceptable pump operations at flows greater than
3000 gpm, which would exist in some accident scenarios. Additionally, no analysis
had been performed for a potential pump/motor coupling failure, which would require
the remaining containment spray pump to provide flow through both containment
spray headers.
On July 26, 2013, the licensee documented in the immediate operability
determination for CR 2013-15047 that no reportable condition existed due to
reportability evaluations written for CRs 2007-01530, 2007-02241, and 2008-01683.
CR 2013-19722 was written on October 22, 2013, which documented that new pump
curve for containment spray pumps revealed that anticipated motor loads would be
significantly above the horsepower rating for the motor. The containment spray
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pump motors are rated for a nominal 300 BHP, and can be acceptably operated at
115 percent of this nominal motor load (i.e. up to a service factor of 1.15). Prior to
this evaluation, the design basis assumed that maximum containment spray pump
flow would be 3200 gpm, resulting in a motor load of 344 BHP and a service factor of
1.15. The new pump curve documented in CR 2013-19722 demonstrated that actual
motor load at 3200 gpm would be 365 BHP, for an unacceptable service factor
of 1.22. The motor vendor determined that under this load, the motors would be
expected to fail within approximately 10 minutes.
Based on questions from the NRC resident inspectors, the licensee initiated
CR 2013-19930 on October 25, 2013 to document the need to reconsider
reportability for the condition identified in CR 2013-15047. A reportability evaluation
was subsequently assigned as an Action Item 005 to CR 2013-15047 on October 26,
and completed on October 31,2013. This evaluation determined that the issues
described required reporting in accordance with 10 CFR 50.73. Licensee Event
Report 2013-017-0 was submitted to the NRC on December 27, 2013. This report
was submitted 57 days after the completion date of the reportability evaluation, but
62 days after the event date of October 26, 2013 on the reportability evaluation.
The inspectors also noted that the report was sent 66 days after CR 2013-19722
documented the potential overload condition.
Enforcement Policy Discussion:
The inspectors determined that this violation was repetitive in nature, as described in
the NRC Enforcement Policy. Paragraph 2.3.2(a)(3) of the NRC Enforcement Policy
provides that one of the criteria that must be met for a violation to be screened as a
non-cited violation is that the violation must not be repetitive, or if repetitive must
not have been identified by the NRC. Repetitive, with regard to this aspect of the
Enforcement Policy, is defined as follows:
A violation is considered repetitive if it could reasonably be expected to have
been prevented by the licensees corrective action for a previous violation. In
addition, a violation is considered repetitive if a previous licensee finding
occurred within the past 2 years of the inspection at issue, or the period between
the last two inspections, whichever is longer.
The inspectors noted that a similar violation had been documented in NRC
Inspection Report 2013008 dated July 16, 2013 (ML13197A261). That report
included NCV 05000285/2013008-43, entitled Untimely Submittal of Licensee Event
Reports. The NCV documented nine examples of LERs that were submitted later
than required by 10 CFR 73(a)(1). The NCV also documented that the late reports
were caused by a backlog of significant technical issues as well as a fundamental
misunderstanding about what constituted the time of discovery. Corrective actions to
address knowledge gaps involving the reportability process were initiated under
Condition Report CR 2012-03796, completed in July 2012. The inspection report
documented that following completion of these corrective actions, LERs submitted
- 44 -
after August 2012 were generally timely and met the 60 day requirement specified in
The inspectors reviewed the completion status of the licensees corrective actions for
NCV 05000285/2013008-43 as documented in CR 2012-03796. All but one of the
assigned corrective actions was completed prior to submittal of untimely
LER 2013-010-0 and LER 2013-017-0. The one remaining item was classified as a
long term corrective action assigned an original due date of August 31, 2012. The
scope of this action was to revise Procedure SO-R-1 to more closely align with the
Exelon fleet model. The due date for this remaining action has since been extended
nine times and is currently scheduled for completion in February 2014. The most
recent due date extension emphasized that the pending changes are enhancements
to the procedure... and Shift Managers have demonstrated the ability to perform
reportability determinations. The inspectors also noted that Procedure SO-R-1 has
been revised seven times since CR 2013-03796 was initiated on May 8, 2012, yet
the action in CAP has not been recorded as completed and errant reportability
evaluations continue to occur.
Given that most of the licensees corrective actions for NCV 05000285/2013008-43
were completed prior to the performance of the reportability evaluation for
CR 2013-09949 or CR 2013-15047, and that less than two years have transpired
since the violation was documented, the inspectors determined that this violation
meets the enforcement policy definition of a repetitive violation.
The licensee initiated CR 2014-01358 on January 29, 2014 to document this
repetitive violation.
Analysis. The inspectors determined that the failure to submit a required LER 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 LER 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(d)(9) of the NRC Enforcement Policy, this violation was determined to be
a Severity Level IV 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 of the Code of Federal Regulations, Section 50.73(a)(1),
requires, in part, that the licensee submit a LER for any event of the type described
in this paragraph within 60 days after the discovery of the event. Contrary to the
above, between June 14 and July 2, 2013, the licensee failed to submit a LER for an
event meeting the requirements for reporting specified in 10 CFR 50.73. This
violation is not being treated as a new violation. Instead, it is considered as a related
violation to the non-cited violation issued in July 2013, which dealt with nine
examples of a failure to submit timely LERs. This violation is being treated as a cited
violation, consistent with Section 2.3.2(a)(3) of the NRC Enforcement Policy:
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VIO 05000285/2014002-05, Untimely Submittal of Required Licensee Event
Reports. (EA-14-037)
.5 (Closed) Licensee Event Report 05000285/2013-015-00: Unqualified Coating used as a
Water Tight Barrier in Rooms 81 and 82
On September 13, 2013, it was identified that the floor coatings in Rooms 81 and 82 may
not maintain its integrity during a high energy line break environment allowing water to
migrate into the rooms below which contain the diesel generators and safety related
switchgear. This was reported on September 23, 2013, under 10 CFR 50.72(b)(3)(ii)(8),
Unanalyzed Condition (Event Notification 49378). Fort Calhoun Station was shutdown in
MODE 5 when the condition was identified and entered into the station's corrective action
program as Condition Report 2013-17605.
Engineering is reviewing this condition and the evaluation performed in 2009 for a previous
condition. The completed results of this review will be used to update this report.
This Licensee Event Report is closed. Revision 1 of this Licensee Event Report was
submitted on February 14, 2014.
.6 (Open) Licensee Event Report 05000285/2013-015-01: Unqualified Coating used as a
Water Tight Barrier in Rooms 81 and 82
On September 23, 2013, it was identified that the floor structure in Rooms 81 and 82 may
not maintain its integrity during a high energy line break environment allowing water to
migrate into the rooms below that houses the diesel generators and safety related
switchgear. This was reported on September 23, 2013, under 10 CFR 50.72(b)(3)(ii)(B),
Unanalyzed Condition (Event Notification 49378). Fort Calhoun Station was shutdown in
MODE 5 when the condition was identified and entered into the station's corrective action
program as Condition Report 2013-18103.
A cause evaluation was completed and determined that corrective actions in CR 2009-0687
root cause analysis (RCA) did not resolve water intrusion into Auxiliary Building rooms
containing safety related equipment due to lack of technical rigor and flawed decision
making.
The floor in Room 82 was recoated. The seismic gap between containment and the
auxiliary building was sealed. All penetrations that had openings below 2 feet above the
floor were coated and the area around the impingement plate was sealed. Cracks in the
ceilings of the switchgear and upper electrical penetration rooms were repaired.
.7 (Open) Licensee Event Report 05000285/2013-016-00: Reporting of Additional High Energy
Line Break Concerns
On October 18, 2013, as part of an extent of condition for LERs 2012-017 and 2013-011,
Fort Calhoun Station (FCS) personnel identified a potential additional high energy line break
(HELB) concern with the piping associated with the letdown heat exchanger (LDHX).
- 46 -
Subsequently on November 5, 11, 16, and 20, additional HELB impacts were also identified.
These impacts involved increased loads on supports in the piping subsystem MS-4099
(main steam supply to FW-10), high energy line cracking (HELC) related to auxiliary steam
in various rooms in the power block, the assumptions made regarding diesel generator
operability during a HELB, and the quality of the steam to FW-10, the steam-driven auxiliary
feedwater pump.
It was previously determined and reported that FCS did not fully implement and/or maintain
the Electrical Equipment Qualification (EEQ) program to meet the requirements of
10 CFR 50.49. As a consequence, the equipment included in the EEQ program, the
systems included in the High Energy Line Break (HELB) Analysis and the environmental
conditions used by the EEQ program have not been maintained current or in an auditable
manner. In addition to the corrective actions (CA) to resolve the EEQ/HELB program issues
previously reported, additional CAs are being pursued to address the individual conditions
listed above.
.8 (Closed) Licensee Event Report 05000285/2013-017-00: Containment Spray Pump Design
Documents do not Support Operation in Runout
a. Inspection Scope
On July 25, 2013, in response to a question from the NRC, the licensee identified that
the containment spray pumps could experience runout conditions in some accident
scenarios, and that design basis documents for the system did not support operability.
Specifically, in the event that one of the two installed containment spray pumps
experienced a pump/motor coupling failure, the remaining pump would have attempt to
provide flow to both containment spray headers and would have failed due to motor
overload.
The licensee issued the LER 2013-017-0 on December 17, 2013 to report a condition
not allowed by Technical Specifications, that could have prevented the fulfillment of a
safety function, and as a condition that caused multiple trains of a safety system to
become inoperable. As a corrective action, the licensee implemented a temporary
modification that throttled a valve at the discharge of each containment spray pump to
prevent runout conditions from occurring. The licensee described plans to complete a
permanent modification in the future to prevent runout.
The required reduction in containment spray flow rates required further analysis by the
licensee to determine if the current Main Steam Line Break (MSLB) analysis in USAR
Table 14.16-3 is still bounding. The NRC technical staff reviewed the results of the
licensees evaluation of the impact of the modification on containment peak pressure
and temperature, and determined that the licensees MSLB accident containment
analysis was acceptable, and that the reduction in the containment spray system
flowrates did not require a license amendment.
- 47 -
In addition to the findings described below, the inspectors determined that this LER was
not submitted within the time required by 10 CFR 50.73(a)(1). The enforcement aspects
of this issue are discussed in Section 4OA3.4 of this report.
This Licensee Event Report is closed.
b. Findings
i. Failure to Restore Compliance for Containment Spray Runout Conditions
Introduction. The inspectors identified a cited Green violation of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Action, for the licensees failure to take timely
corrective action for a condition adverse to quality. Specifically, the inspectors noted
that the licensee failed to restore compliance following NRC identification of the
licensees failure to correct runout conditions in the containment spray system
documented as NCV 05000285/2008003-05 in August 2008.
Description. The containment spray system at Fort Calhoun Station consists of two
safety-related centrifugal pumps which are designed to provide flow through either of
two spray headers in containment to lower the peak containment pressure during the
first twenty minutes of a main steam line break accident. Open cross-connect valves
between the discharge piping on each pump allow each pump to supply flow to both
headers. This configuration challenges the operability of the pumps in that a failure
of one of the pumps could cause the remaining pump to provide flow through both
spray headers and result in runout of the remaining pump and eventual pump failure
due to high vibrations or motor overload. This design vulnerability was identified by
the licensee as early as 1990, and interlocks were added to prevent both spray
header isolation valves from opening unless both containment spray pump motors
were running.
During an inspection performed under Inspection Procedure 95002, Supplemental
Inspection for One Degraded Cornerstone or Any Three White Inputs in a Strategic
Performance Area, on March 17, 2008, NRC inspectors identified an operability
concern with the response of the containment spray system. Specifically, the
inspectors identified a potential vulnerability in that a mechanical failure of a
containment spray pump (such as a pump shaft shear or a stuck discharge check
valve) could result in the runout failure of the remaining pump. These two scenarios
of concern were documented by the licensee in CR 2008-1666 and CR 2008-1683
respectively. Given the similarity of the pump shaft shear and failed check valve
scenarios, the licensee consolidated many of the needed corrective actions and
tracked them under CR 2008-1683.
In response to CR 2008-1666 and CR 2008-1683, station operators completed an
operability evaluation on March 19, 2008. This operability evaluation contained the
following discussion of the scenarios of concern:
The two events that credit Containment Spray are a Loss of Coolant Accident
(LOCA) and a Main Steam Line break (MSLB).During a MSLB the containment
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heat removal capability of the CS system is provided in addition to the heat
removal capability of the containment Coolers.therefore the LOCA response
will be the one mainly addressed.
The licensee completed Safety Analysis for Operability (SAO) 2008-02 on
March 22, 2008 to define the conditions which must exist to assure operability until
final corrective action were taken. These steps included updating plant procedures
and the UFSAR to define operator actions to recognize pump shaft shear and check
valve failures; adding procedural requirements to ensure all containment fan coolers
remained operable until the start of the 2008 refueling outage; and completion of
Engineering Change 30663, GSI 191 Implementation, during the 2008 refueling
outage, after which SAO 2008-002 could be closed. The inspectors noted that the
purpose of EC 30663 was to provide the engineering justification for retaining the
existing containment sump strainer design. A necessary input to this EC was
completion of EC 40070, which eliminated the containment spray function for a
LOCA.
On May 5, 2008, the licensee completed an apparent cause evaluation for this
condition. The cause was determined to be less than adequate evaluation of the
single failure impact of CS system subcomponents on the containment spray
system. Several actions were identified to correct the condition, including closure of
SAO 2008-02; conducting training for engineering staff on identification of single
failures; and training for staff on procedure changes. Several additional actions were
identified to prevent recurrence including procedure revisions to clarify plant
modification procedural controls and clarify single failure criteria.
On May 28, 2008, the Plant Review Committee approved closure of SAO 2008-002
following completion of EC 30663. In the supporting memorandum to the Plant
Review Committee, the licensees staff wrote that After implementation of this EC,
the CS Pumps are no longer credited for a LOCA event. The inspectors noted,
however, that completion of EC 30663 did nothing to resolve the vulnerability of the
pump failure in the other design basis event for which containment spray was
credited (MSLB). Finally, the inspectors noted that on January 15, 2010, the
licensee documented that all actions necessary to address NCV 2008003-05 had
been completed, and on January 19, 2010, CR 2008-1683 was closed.
On July 18, 2013, NRC inspectors again inquired about the runout susceptibility of
the containment spray pumps. In response to these questions by the inspectors, the
licensee discovered that anticipated operating conditions during a MSLB scenario
may exceed analyzed limits for the pumps. The licensee documented this concern in
CR 2013-15047 on July 25, 2013. Specifically, design basis calculations and vendor
information for the containment spray system did not describe acceptable pump
operations at flows greater than 3000 gpm, which would exist within the first twenty
minutes of a main steam line break scenario. Additionally, no analysis had been
performed for a potential pump/motor coupling failure, which would require a single
containment spray pump to provide flow through both containment spray headers.
After subsequent analysis of the MSLB scenario by the motor vendor, the licensee
initiated CR 2013-19722 on October 22, 2013, which described that the acceptance
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review of a new pump curve for the containment spray pumps identified the motor
horsepower required was beyond the service factor of 1.15. A subsequent
reportability evaluation further documented that Additional evaluations performed by
an electric motor vendor to determine if the CS Pump motor can support operation in
a runout condition determined that the motor may fail after approximately 10 minutes
of operation. On December 27, 2013, the licensee reported this condition in
Licensee Event Report 2013-017-0 as a condition which was prohibited by the
plants Technical Specifications and as a condition that could have prevented the
fulfillment of the safety function of containment spray system.
Corrective actions taken for CR 2013-15047 included completion of an analysis of
containment spray pump operation in an MSLB event; revision of CS design
documentation; analysis of motor performance by electrical vendor; and completion
of a temporary modification which throttles the CS pump discharge valves to provide
additional system resistance and prevent runout. The action to change the system
resistance was completed on November 24, 2013, which put the station back into
compliance by correcting the condition adverse to quality originally identified by NRC
in NCV 2008003-05. Future corrective actions will include a permanent design
change to prevent CS pump runout.
Inspectors determined that this violation demonstrated that the licensee had failed to
restore compliance within a reasonable period of time after the previous violation
was identified, as described in Paragraph 2.3.2(a)(2) of the NRC Enforcement Policy.
Specifically, the inspectors noted that NCV 05000285/2008003-05, entitled
Inadequate Corrective Actions for a Containment Spray Design Deficiency,
described that the licensee had initiated CR 2008-01683 to document the violation.
The inspectors reviewed the disposition of CR 2008-01683, and determined that
neither the actions taken to correct the violation, nor the actions taken to prevent
recurrence were sufficient to resolve the performance deficiency. At the time that the
concern was again raised by NRC inspectors on July 18, 2013, CR 2008-01683 and
all of its associated corrective actions were already completed and closed.
During an extent of condition review for a runout concern in the HPSI system, the
licensee identified that design basis calculations FC07077 and FC07078 predicted
flowrates beyond the manufacturers pump curve. Action 2013-02100-008 was
assigned on April 17, 2013 to validate and document the CS pumps can operate
successfully and meet design requirements in their extended flow region The
language of the action item presumed a successful outcome, and on May 17, 2013
the action item was closed based upon previous vendor correspondence (i.e. no new
analysis was conducted), and the licensee documented that the CS pumps are
acceptable as is. No additional actions are required. This action and the
inadequate response represent a recent opportunity to identify and correct this
condition prior to NRCs actions in the matter.
The licensee initiated CR 2014-02242 on February 19, 2014 to document this failure
to restore compliance.
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Analysis. The inspectors determined that the licensees failure to correct a condition
adverse to quality was a performance deficiency. This finding was more than minor
because it adversely impacted the SSC and barrier performance attribute of the
Barrier Integrity cornerstone objective to provide reasonable assurance that physical
design barriers (containment) protect the public from radionuclide releases caused
by accidents or events.
The inspectors reviewed IMC 0609 Attachment 4, Initial Characterization of
Findings, Table 3 - SDP Appendix Router. While this issue was identified during a
refueling outage, the inspectors determined that the majority of the exposure time for
this violation occurred with the reactor at power. As such, the inspectors determined
the finding should be evaluated using the SDP in accordance with IMC 0609, The
Significance Determination Process (SDP) for Findings at-Power, Appendix A,
Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that
the finding did not represent an actual open pathway in containment or containment
isolation logic, nor did the finding represent an actual reduction in the function of
containment hydrogen igniters. Based on the guidance in the Exhibit 3 checklist the
inspectors determined that the finding was of very low safety significance.
The inspectors determined that finding had a cross-cutting aspect of avoiding
complacency in the human performance area, because the licensees staff failed to
recognize latent issues even while expecting successful outcomes (H.12).
Enforcement. Title 10 CFR 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 nonconformances are promptly identified and
corrected. Contrary to the above, between August 12, 2008 and
November 24, 2013, the licensee failed to take adequate corrective action to assure
that a condition adverse to quality was corrected. Specifically, actions were not
taken to correct NRC-identified runout concerns in the containment spray system
until these concerns were again raised by the NRC on July 18, 2013. This violation
is not being treated as a new violation. Instead, it is considered as a continuation of
the non-cited violation issued in August 2008, which identified the licensees failure
to take corrective actions for runout concerns in the containment spray system. This
violation is being treated as a cited violation, consistent with Section 2.3.2(a)(2) of
the NRC Enforcement Policy: VIO 05000285/2014002-06, Failure to Restore
Compliance for Containment Spray Runout Conditions. (EA-14-037)
ii. Inadequate 10 CFR 50.59 Screening for Containment Spray Design Change
Introduction. The inspectors identified a Green non-cited violation of 10 CFR 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings for the licensees
failure to complete a 10 CFR 50.59 screening that met the requirements of
NOD-QP-3, 10 CFR 50.59 and 10 CFR 72.48 Reviews, Revision 37.
Description. 10 CFR 50.59, Changes, Tests, and Experiments, contains
requirements for the process by which licensees may make changes to their
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facilities and procedures as described in the safety analysis report, without prior
NRC approval, under certain conditions. Through the issuance of Regulatory
Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and
Experiments, the NRC endorsed industry-developed guidance for compliance with
10 CFR 50.59. This industry guidance, documented in NEI 96-07, Guidelines for
10 CFR 50.59 Evaluations, Revision 1, provides methods that are acceptable to the
NRC staff for complying with the provisions of the rule.
Section 4.2 of NEI 96-07 describes the process used to screen plant changes to
determine if further evaluation is required. This process involves answering a
number of screening questions. If any of these questions is answered in the
affirmative, the NEI guidance requires that the change be subjected to a evaluation
to determine if NRC review and approval is required prior to making the change.
The inspectors noted that the licensees guidance on implementation of the
10 CFR 50.59 rule is contained within two documents: NOD-QP-3, 10 CFR 50.59
and 10 CFR 72.48 Reviews, Revision 37, and FCSG-23, 10 CFR 50.59 Resource
Manual, Revision 8. Step 4.4.1.A of NOD-QP-3 requires plant personnel to
complete the screening activity using Form FC-154A and the guidance within
FCSG-23. Step 4.4.1.C requires the performer to provide written justification for
each of five questions to demonstrate that the overall conclusion is that an evaluation
is not required.
The inspectors reviewed the completed 10 CFR 50.59 screening that was performed
for Engineering Change (EC) 62416 on November 14, 2013. This EC was
implemented to change the normal position for the containment spray pump
discharge isolation valve from full open to throttled. This new position was required
to prevent the runout of the containment spray pumps in certain accident conditions,
and involved using the normally-open gate valve to throttle flow rates of up to
3000 gpm during accident conditions. During these operating conditions, the new
position of the gate valve would be approximately 80 percent closed, exposing the
valve to high differential pressures and creating a number of potentially unanalyzed
degradation mechanisms in the downstream piping, including vibration, flow erosion,
and debris blockage.
The inspectors noted that the completed FC-154A screening form answered no to
all five screening questions. The inspectors developed a concern with the licensees
response to Question 1, which asks the screener to answer the following question:
1. Does the proposed activity involve a change to an SSC that adversely affects
a UFSAR described design function?
The inspectors determined that this response was in error, in that the proposed
change adversely affected the UFSAR described design function of the containment
spray system, due to the possible adverse effects of throttling the gate valves on
the system valves and piping. The inspectors determined that in answering
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no to this question, the licensee failed to properly implement Step 4.4.1.C of
Procedure NOD-QP-3. After sharing this concern with the licensee, the licensee
initiated CR 2013-22007 documenting the procedural error. CR 2013-22007
recorded that the initial FC-154A screen had incorrectly determined that a
10 CFR 50.59 evaluation was not required. The licensees staff subsequently re-
performed the FC-154A screening form on November 29, 2013, and determined that
a 10 CFR 50.59 evaluation was required. The NRC staff reviewed the resulting
10 CFR 50.59 screening and evaluation and determined that they had been properly
performed, and that a license amendment request was not required prior to
implementation of the activity.
The licensee documented this procedural violation in CR 2014-01357 on
January 29, 2014.
Analysis. The failure to follow station procedures which required completion of an
accurate 10 CFR 50.59 screening of a design change was a performance deficiency.
This performance deficiency was considered to be of more than minor safety
significance because it was associated with the design control attribute of the
mitigating systems cornerstone and it adversely affected the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Specifically, the failure to follow
station procedures for the 10 CFR 50.59 process prevented the licensees staff from
evaluating the adverse impacts of the change on the facility. Using Inspection
Manual Chapter 0609 Appendix G, Checklist 4, the inspectors determined that the
finding did not result in the loss of any accident mitigation capability and did not
require a quantitative risk assessment. This finding was determined to be of very low
risk significance (Green).
The inspectors determined that this finding had a cross-cutting aspect of
conservative bias in the human performance area, because the licensees staff
ensure that the proposed design change was safe in order to proceed rather than
unsafe to stop (H.14).
Enforcement. Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings states, in part, that activities affecting quality shall be prescribed by
documented procedures and accomplished in accordance with these procedures.
The licensee established Procedure NOD-QP-3, as the implementing procedure for
10 CFR 50.59 Reviews, an acivity affecting quality. Contrary to this requirement,
between November 13 and November 29, 2013, the licensee failed to accomplish an
activity affecting quality in accordance with the procedure. Specifically, the licensee
completed a 10 CFR 50.59 screening that did not meet the requirements of NOD-
QP-3, 10 CFR 50.59 and 10 CFR 72.48 Reviews, Revision 37. This violation is
being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy.
The violation was entered into the licensees corrective action program as
CR 2014-01357. (NCV 05000285/2014002-07, Inadequate 10 CFR 50.59
Screening for Containment Spray Design Change)
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.9 Open) Licensee Event Report 05000285/2013-019-00: Non-Seismic Circulating Water Pipe
Could Disable Raw Water Pumps
On December 2, 2013, NRC inspectors questioned the validity of an operability
determination performed by the station on a non-safety grade pipe in the Raw Water pump
vaults. The concern was determined to be valid and on December 3, 2013 at 0038 CST, an
operability evaluation for Condition Report (CR) 2013-22090 confirmed operability of the RW
pumps with interim actions to prevent circulating water flow from the affected 12 inch pipe
into the raw water vault during a seismic event. Interim compensatory actions to maintain
operability of the raw water pumps are to secure the screen wash system and establish a
clearance.
A cause analysis is in progress and an update to this LER will be provided with additional
information.
A design change was completed to eliminate the adverse interaction noted above.
These activities constitute completion of five event follow-up samples, as defined in Inspection
Procedure 71153.
4OA4 IMC 0350 Inspection Activities (92702)
Inspectors continued implementing IMC 0350 inspection activities, which included follow-up of
the restart checklist items contained in the Confirmatory Action Letter (CAL) issued
February 26, 2013 (EA-13-020, ML 13057A287). The purpose of these inspection activities was
to assess the licensees performance and progress in addressing its implementation and
effectiveness of FCSs Integrated Performance Improvement Plan (IPIP), significant
performance issues, weaknesses in programs and processes, and flood restoration activities.
Inspectors used the criteria described in baseline and supplemental inspection procedures,
various programmatic NRC inspection procedures, and IMC 0350 to assess the licensees
performance and progress in implementing its performance improvement initiatives. Inspectors
performed on-site and in-office activities, which are described in more detail in the following
sections of this report. This section documents inspection activities that occurred prior to
closure of the CAL on December 17, 2013. Specific documents reviewed during this inspection
are listed in the attachment.
The following inspection scope, assessments, observations, and findings are documented by
CAL restart checklist item number.
.3 Adequacy of Significant Programs and Processes
Section 3 of the Restart Checklist addresses major programs and processes in place at
FCS. Section 3 reviews also include an assessment of how the licensee addressed the
NRC Inspection Procedure 95003 key attributes as described in Section 6.
.b Equipment Design Qualifications
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This item of the Restart Checklist verifies that plant components are maintained within
their licensing and design basis. Additionally, this item provides monitoring of the
capability of the selected components and operator actions to perform their functions.
As plants age, modifications may alter or disable important design features making the
design bases difficult to determine or obsolete. The plant risk assessment model
assumes the capability of safety systems and components to perform their intended
safety function successfully.
(1) Safety-Related Parts Program
i. Inspection Scope
The team reviewed the licensees assessment of issues related to the safety-
related parts program at FCS. The team assessed the licensees equipment
design quality classifications review for inconsistent quality classifications.
Additionally, the team assessed the licensees review of the use of non-safety-
related parts in safety-related applications. Specifically, the team assessed the
RCA for CR 2012-05615, for which the problem statement was:
FCS did not maintain compliance in all cases to the Updated Safety Analysis
Report, Appendix A, Section 4.0, Design Control, such that non-safety graded
parts would not be installed in safety grade applications. This would result in
failure to comply with the FCS design basis. Design basis compliance is not
assured.
The team also assessed the adequacy of the extent of condition, extent of
causes, and corrective actions (CL Items 3.b.1.1; 3.b.1.2; 3.b.1.3).
The teams assessment of this RCA was based on the evaluation criteria from
Section 02.02 of NRC Inspection Procedure 95001, which aligned with this item.
The inspection objectives were to:
- Provide assurance that the apparent 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 apparent
and contributing causes and to preclude repetition
ii. Observations and Findings
Determine that the problem was evaluated using a systematic methodology to
identify the root and contributing causes.
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The team determined that the licensee evaluated this problem using a systematic
methodology to identify the root and contributing causes. Specifically,
RCA 2012-05615 employed the use of event and causal factor charting, barrier
analysis, common factor analysis, and the why staircase. The licensee identified
the following as the root cause for why FCS has allowed non-safety-related parts
to be installed in safety grade applications:
RC-1: Inadequate procedural guidance and an ineffective training/mentoring
process have resulted in an ineffective work planning and review process
with the potential for non-CQE parts being installed where CQE parts are
required.
(CQE stands for critical quality element and is synonymous with safety-
related).
The licensees RCA also identified the following contributing causes (CC):
CC-1: A lack of adequate reference documents and resources/tools for
planners, engineers, and maintenance personnel to reference exists.
CC-2: Ownership of important resources (Bill of Materials, CQE List, Asset
Suite) is not known by Station personnel.
CC-3: Overconfidence in Station personnel abilities to accomplish work has
resulted in inadequate use of human performance tools and a rationalization
that current expectations, standards, and performance are sufficient for
Station needs.
CC-4: Station personnel were willing to work around Station procedures
using tribal knowledge (experience) to complete tasks which resulted in a
procedure use and adherence issue.
CC-5: The CAP has not fully assessed and effectively resolved identified
CQE issues.
CC-6: A station personnel knowledge gap exists for the CQE classification
boundaries and dedication requirements.
The team determined that these root and contributing causes reasonably explain
why the safety-related parts program at FCS failed to maintain design control
such that non-safety graded parts have been installed in safety grade
applications. However, the team identified that the RCA appeared to be
incomplete because it did not address the licensees ability to properly classify
structures, systems, and components as safety-related. NRCs Manual
Chapter 0350 Panel FCS Restart Checklist Basis Document, Item 3.b.1, Safety-
Related Parts Program, specifically identified that the NRC will assess the
licensees equipment design quality classifications review for inconsistent quality
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classifications. The licensee performed an operability evaluation regarding
piping code of record concerns and plans to review their CQE documentation
during their design basis reconstitution.
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 RCA was conducted to a level of detail
commensurate with the significance of the problem. Specifically, as discussed
above, the licensee conducted this evaluation not only by using event and causal
factor charting, barrier analysis, and the why-staircase, but also by conducting
interviews, reviewing documents, and attending meetings. The licensees RCA
techniques were generally thorough and identified the root and contributing
causes of deficiencies in the safety-related parts program relative to work
planning and work control.
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 evaluations of both internal and
industry operating experience. The team determined that the licensees
evaluations of industry operating experience provided sufficient detail such that
general conclusions could be established regarding any similarities.
Determine that the root cause evaluation addressed the extent of condition and
the extent of cause of the problem.
The team reviewed the licensees RCA as it relates to extent of condition and
extent of cause.
For extent of condition, the licensee evaluated the extent to which the actual
condition exists with other plant processes, equipment, or human performance.
The licensees analysis used the same-same, same-similar, similar-same, and
similar-similar evaluation method. The licensee concluded that the extent of
condition does exist relative to other processes, procedures, or commitments
where nonconformity with established requirements could result in a non-
compliance with the FCS design basis. The licensee also found that an extent of
condition may exist for nuclear safety culture which has not been fully addressed
by causal analysis but can affect the stations commitment to written agreements
related to the FCS design basis. The licensee initiated CR 2012-17437 to
address this extent of condition issue.
The team noted that the licensee did not specifically document where the actual
condition of non-safety-related components may exist in safety-related
equipment as part of the extent of condition. This was determined to be a
documentation oversight since, through interviews, the team found that the
licensee had a comprehensive plan to address this element of extent of condition
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established under Action Item 29 of CR 2011-09459 and CA-13 of
CR 2012-05615. That plan reviewed safety-related WOs for the past two cycles
to identify where non-safety parts were inappropriately used in safety-related
applications. The team found that these corrective actions would reasonably
address any current issues where non-safety-related components were used in
safety-related applications. The team determined that while the licensees
strategy to address extent of condition was technically sound, the failure of the
RCA to address weaknesses in the ability to classify safety-related components
could result in a less than adequate extent of condition review.
For extent of cause, the licensee reviewed the root causes of an identified
problem to determine where they may have impacted other plant processes,
equipment, or human performance. The licensees analysis determined that an
extent of cause does exist related to the adequacy of non-accredited training
programs. The licensee initiated CR 2012-18335 to address the issues identified
with non-accredited training.
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. Specifically, the licensee documented their consideration of the
IMC 0310 cross-cutting aspects in Attachment 11 of RCA 2012-05615. The
licensee identified several cross-cutting aspects in the area of human
performance, problem identification and resolution, and other components were
applicable to issues related to deficiencies in identifying degraded/nonconforming
conditions and operability evaluations. The final evaluation concluded that only a
small number of the safety culture attributes were not to be applicable to
RCA 2012-05615.
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. The team found that the corrective actions addressed the
root and contributing causes for why the licensee has allowed non-safety graded
parts to be installed in safety grade applications. The team noted that the
corrective actions focused primarily on work planning procedure changes and
development and implementation of training for work planners. The team also
found that Corrective Action 13 of CR 2012-05615 which implemented a review
of the past two cycles of safety-related work order adequately addressed the
extent of condition relative to where non-safety parts may have been
inappropriately used in safety-related applications. The team did note that the
licensees corrective action plan did not include any actions to address
weaknesses in the stations ability to classify structures, systems, and
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components. The team determined that the licensees corrective actions would
only be effective once weaknesses in the ability to classify safety-related
components are corrected.
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. The team found that corrective actions to
prevent recurrence had been scheduled or implemented which included
procedures changes and implementation of necessary training for work planners.
Additionally, corrective actions to address the contributing causes had been
scheduled. The team determined that that licensees schedule for implementing
corrective actions appeared to be commensurate with the significance of the
issues they are addressing.
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 quantitative or qualitative measures of success have
been developed for determining the effectiveness of the corrective actions to
prevent recurrence. The licensee established, in part, effectiveness reviews
consisting of independent self-assessments to determine if the necessary
guidance for planners to resolve CQE issues was incorporated into FCS
procedures. Additionally, the licensee identified interim and final effectiveness
reviews consisting of independent self-assessments to review condition reports
and WOs for CQE related issues. The review provided specific performance
measure to verify the frequency of CQE related issues is reduced. The team
determined that the licensees effectiveness criteria did meet the criteria
established in Procedure FCSG 24-7, Effectiveness Review of Corrective
Actions to Prevent Recurrence (CAPRs), Revision 1, in that the effectiveness
review specified specific success criteria.
iii. Assessment Results
The team concluded that for Root Cause Analysis 2012-05615: the root and
contributing causes of risk-significant issues were understood; the extent-of-
condition and extent-of-cause of risk-significant issues were identified; and, the
licensee's corrective actions for risk-significant performance issues were, or will
be, sufficient to address the root and contributing causes.
Restart Checklist items 3.b.1.1, 3.b.1.2, and 3.b.1.3 are closed.
.e Operability Process
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Improper evaluations of degraded and/or non-conforming conditions may result in
continued operation with a structure, system, or component that is not capable of
performing its design function.
(1) Inspection Scope
The team reviewed the licensees assessment of the Fundamental Performance
Deficiency (FPD) associated with Processes to Meet Regulatory Requirements
specifically related to the Operability Determination process. Specifically, the team
assessed the RCA for CR 2012-09494 Revision 1, which identified the following
programmatic and cultural deficiencies:
- Deficiencies in the accurate identification of current licensing basis
degraded/nonconforming conditions
- Operability determinations/functionality assessments are not sufficiently
rigorous
- Discrepant conditions are not always resolved in a timely manner
commensurate with the safety significance of the condition
- Cause analysis and extent of condition are not consistently rigorous to
identify the underlying cause of the equipments deficient condition and the
broadness impact of the condition
- The characteristics necessary for equipment to be fully qualified are not well
understood or applied
The team also assessed the adequacy of the extent of condition, extent of causes,
and corrective actions. (Restart Checklist Basis Document Items 3.e.1; 3.e.2; 3.e.3)
The teams assessment of this FPD was based on the evaluation criteria from
Section 02.02 of NRC Inspection Procedure 95001 which align 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
(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 root and contributing causes. Specifically,
RCA 2012- 09494 employed the use of barrier analysis to identify applicable causal
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factors. The licensee further refined the results of the barrier analysis by use of a
Five Whys analysis to determine the root causes. The licensee then evaluated the
cause statements against cause testing established in FCS procedures to confirm
the root and contributing causes.
The licensee identified the following as root causes for the FPD:
RC-1: Leadership has not provided adequate governance and oversight for key
regulatory required programs and activities.
RC-2: Processes to perform, and support performance of, Degraded/Non-
Conforming Condition identification and Operability Determinations are not
adequate to ensure consistently accurate and timely determinations.
CC-1: The Operating Experience Program permitted a superficial review of NRC
Regulatory Issue Summary (RIS) 2005-20 Revision 1.
CC-2: Operations leadership did not recognize the risk associated with failing to
keep pace with the industry standard for an Operations led organization.
CC-3: Knowledge and skills to perform, and support performance of,
Degraded/Non-Conforming Condition identification and Operability
Determinations are not adequate to ensure consistently accurate and timely
determinations.
CC-4: Tools used to perform, and support performance of, Degraded/Non-
Conforming Condition identification and Operability Determinations are not
adequate to ensure consistently accurate and timely determinations.
Determine that the root cause evaluation was conducted to a level of detail
commensurate with the significance of the problem.
The licensees RCA employed various techniques to analyze the events. In general,
the quality of analysis was sound and identified several failed barriers in the process
for identification of degraded/nonconforming conditions and operability
determinations.
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 evaluations of both internal and industry
operating experience. The licensees evaluations of industry operating experience
provided sufficient detail such that general conclusions could be established
regarding any similarities.
Determine that the root cause evaluation addressed the extent of condition and the
extent of cause of the problem.
- 61 -
The team reviewed the RCA as it relates to extent of condition and extent of cause.
For extent of condition, the licensees evaluation determined that an extent of
condition for deficiencies in identifying degraded/nonconforming conditions and
performance of operability determinations does exist at FCS. Consequently, the
licensee concluded that other regulatory-required programs, such as, the operability
determination process were not effectively implemented at FCS but the condition
was known as documented in CR 2012-08137, Regulatory Processes and
Infrastructure. The team generally agreed that the licensee had identified similar
processes, such as those documented in CR 2012-08137, which were not being
effectively implemented at FCS.
For extent of cause, the licensee identified extent of cause concerns involving
inadequacies in reinforcing high standards and accountability which was determined
to cross all department and work process boundaries. The licensee addressed the
extent of cause through the organizational ineffectiveness RCA performed under
CR 2012-03986. The licensee determined that corrective actions taken to address
the organizational ineffectiveness extent of cause fully address the extent of cause
for CR 2012-09494. The team found that the corrective actions generally addressed
the extent of cause related to root cause 1 and 2.
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. Specifically,
the licensee documented their consideration of the IMC 0310 cross-cutting aspects
in Attachment 5 of RCA 2012-09494. The licensee identified H.1 Decision Making -
Licensee decisions demonstrate that nuclear safety is an overriding priority and O.1
Accountability - Management defines the line of authority and responsibility for
nuclear safety as the most applicable safety culture components.
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. In general, the corrective actions identified for the root and
contributing causes appear to be adequate to resolve the identified causes.
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 assigned corrective actions. Most of the corrective actions have been
completed.
- 62 -
Determine that quantitative or qualitative measures of success have been developed
for determining the effectiveness of the corrective actions to prevent recurrence.
The effectiveness review plan documented is problematic. Specifically, the licensee
has not established adequate quantitative or qualitative acceptance criteria
measures to assess the effectiveness of each corrective action to prevent recurrence
and the corrective actions to prevent recurrence collectively to prevent recurrence of
the root causes as required by FCSG-24-5, Cause Evaluation Manual. Specifically,
the current effectiveness review plan would allow inadequate operability calls to not
fail the effectiveness review as long as those calls were only on non-safety
significant equipment. In this instance the licensee defines safety significant
equipment as that which would put the station into a Technical Specification action
statement or change the Equipment out of service Risk color. In addition the
inspectors are not aware of a licensee mechanism to track this required information.
These observations were discussed with the licensee.
(3) Assessment Results
The team concluded that for Root Cause Analysis 2012-9494: the root and
contributing causes of risk-significant issues were understood; the extent-of-
condition and extent-of-cause of risk-significant issues were identified; and, the
licensee's corrective actions for risk-significant performance issues were, or will
be, sufficient to address the root and contributing causes.
Restart Checklist Items 3.e.1, 3.e.2, and 3.e.3 are closed.
4OA5 Other Activities
On April 11, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed a reactive
inspection in accordance with NRC Inspection Procedure 93812, Special Inspection, at your
Fort Calhoun Station. This special inspection was conducted to gather information associated
with the improper design specifications associated with the raw water pump anchor bolts.
Inspection Report 05000285/2013-012, issued on May 24, 2013 (ML13144A772) documents the
results of this inspection. Documented in this report are two apparent violations (AV) that were
issued pending further evaluation by the licensee. The purpose of this section is document
closure of these two AVs.
.1 (Closed) Apparent Violation 05000285/2013012-08: Failure to Adequately Design
Anchorage for Containment Spray and Raw Water System Pipe Supports
a. Inspection Scope
The inspection report documented an apparent violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, for the failure to ensure the adequacy of the anchorage for
several raw water system and containment spray system pipe supports. Specifically the
anchorage design was non-conservative with respect to the design basis requirements.
This issue was and apparent violation because the final safety significance was to be
- 63 -
determined pending additional analysis of the as-found configuration of the anchorage
and associated pipe supports by the licensee.
b. Findings
Failure to Adequately Design Anchorage for Containment Spray and Raw Water System
Pipe Supports
Introduction. The inspection team identified several examples of a Green, non-cited
violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to
ensure the adequacy of the anchorage for several raw water system and containment
spray system pipe supports. Specifically the anchorage design was non-conservative
with respect to the design basis requirements.
Description. During a previous inspection, the NRC reviewed multiple calculations for
pipe supports on the raw water and containment spray systems and found that the
calculations had several errors related to the design requirements for anchorage. The
NRC issued an apparent violation AV 05000285/2013012-08, Failure to adequately
design anchorage for containment spray and raw water system pipe supports in NRC
Inspection Report 05000285/2013-012 (ML 13144A772).
The licensee performed an operability determination for the affected calculations and
found that the anchorage for the raw water and containment spray piping supports were
operable. The NRC reviewed the evaluations and concluded that reasonable assurance
of operability existed for the affected components.
Analysis. The inspectors determined that the failure to ensure adequacy of the
anchorage of the aforementioned Containment Spray Pipe Supports and Raw Water
Pipe Supports was not in accordance with design basis requirements and was a
performance deficiency. The performance deficiency was determined to be more than
minor because it required calculations to be re-performed to prove the system was
operable, and it was associated with the Mitigating Systems cornerstone attribute of
design control and affected the cornerstone objective of ensuring the availability,
reliability, and capability of the containment spray system and raw water system.
Using Inspection Manual Chapter 0609, Attachment 4 Initial Characterization of
Findings, and Appendix A The Significance Determination Process (SDP) for findings
at-power, both dated 6/19/12, the inspectors determined the performance deficiency
affected the mitigating systems cornerstone and screened to Green because the finding
affected the design and qualification of a mitigating SSC but remained operable. The
inspectors used the at-power SDP because the condition existed since construction and
while the plant was predominantly at power.
The inspectors determined there was no cross-cutting aspect associated with this finding
because the calculations were from the 1980s and therefore were not reflective of
current performance.
- 64 -
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control states, in
part, that the design control measures shall provide for verifying or checking the
adequacy of design, such as by the performance of design reviews, by the use of
alternate or simplified calculational methods, or by the performance of a suitable testing
program. Contrary to this requirement the inspectors identified that calculations
FC00607, FC01785, FC01786, FC01791, FC01864, FC01691, FC01902, FC02409,
FC02412, FC04228, FC02433, FC02436, and FC02425 for the raw water and
containment spray systems failed to ensure adequacy of the design. Specifically, these
anchorage calculations did not conform to applicable design requirements from
approximately 1980 until June 2013.
The licensee entered these issues into the corrective action program as CR 2013-05304
and performed an operability determination as immediate actions. Long term actions to
resolve the errors in the calculations are also implemented by the referenced CR. This
violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement
Policy. (NCV 05000285/2014002-08, Failure to Adequately Design Anchorage for
Containment Spray and Raw Water System Pipe Supports).
.2 (Closed) Apparent Violation 05000285/2013012-09: Failure to Adequately Implement
Design Requirements for Containment Air Cooler Pipe Supports
a. Inspection Scope
The inspection report documented an apparent violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, for the failure to ensure the adequacy of the U-bolts for
Containment Air Cooler pipe supports VAS-1 and VAS-2. This issue was an apparent
violation because the final safety significance was to be determined pending additional
analysis of the as-found configuration of the condensate drain line and associated pipe
supports by the licensee.
b. Findings
Failure to Adequately Implement Design Requirements for Containment Air Cooler Pipe
Supports
Introduction. The NRC identified a Green, non-cited violation of 10 CFR Part 50,
Appendix B, Criterion III, Design Control, for the failure to ensure the adequacy of the
U-bolts for containment air cooler pipe supports VAS-1 and VAS-2. Specifically the U-
bolt design was non-conservative with respect to the design basis requirements.
Description. During a previous inspection, the NRC reviewed calculations for VAS-1 and
VAS-2 pipe supports on the containment air cooling systems and found that the
calculations had an error in the design requirements for U-bolts. Specifically, calculation
FC05918 for the VAS-1 and VAS-2 U-bolts did not consider two-directional applied
loading, it only considered tensile loads. The NRC issued an apparent violation
AV 05000285/2013012-09, Failure to adequately implement design requirements for
containment air cooler pipe supports in NRC Inspection Report 0500285/2013-012
(ML 13144A772).
- 65 -
Analysis. The inspectors determined that the failure to ensure adequacy of the U-bolts
for containment air cooler pipe supports VAS-1 and VAS-2 in accordance with design
basis requirements was a performance deficiency.
The performance deficiency was determined to be more than minor because it required
calculations to be re-performed to prove the system was operable, and it was associated
with the Mitigating Systems cornerstone attribute of design control and affected the
cornerstone objective of ensuring the availability, reliability, and capability of several
safety injection tank valves. Specifically, the one-directional U-bolts for VAS-1 and VAS-
2 are not designed to withstand two-directional loading and the condensate drain piping
line has the potential to adversely impact the safety injection tank discharge isolation
valves HCV-2984 and HCV-2794 during a design basis event.
The licensee updated calculation FC05918 and provided an operability evaluation to
address the degraded condition. The inspectors reviewed the information and found the
analysis adequately supported the operability of the affected equipment.
Using Inspection Manual Chapter 0609, Attachment 4 Initial Characterization of
Findings, and Appendix A, The Significance Determination Process (SDP) for findings
at-power, both dated 6/19/12, the inspectors determined performance deficiency
affected the mitigating systems cornerstone and screened to Green because the finding
affected the design and qualification of a mitigating SSC but remained operable. The
inspectors used the at-power SDP because the condition existed since construction and
while the plant was predominantly at power.
The inspectors determined there was no cross-cutting aspect associated with this finding
because the calculation was from the 1980s, therefore was not reflective of current
performance.
Enforcement. Title 10 CFR Part 50, Appendix B, Criterion III, Design Control states, in
part, that the design control measures shall provide for verifying or checking the
adequacy of design, such as by the performance of design reviews, by the use of
alternate or simplified calculation methods, or by the performance of a suitable testing
program.
Contrary to this requirement, the inspectors identified that calculation FC05918, from
1992 until May 2013, failed to ensure adequacy of the design. Specifically, the
calculation did not conform to the U-bolt requirements by applying two-directional
loading to a U-bolt restraint that is qualified for only one-directional loading. The
licensee revised the calculation to support operability. In addition, the licensee
generated engineering change EC59570 to fix the degraded VAS-1 and VAS-2
supports. The licensee entered these issues into the corrective action program
as CR 2013-03722. This violation is being treated as an NCV, consistent with
Section 2.3.2.a of the Enforcement Policy. (NCV 05000285/2014002-09, Failure to
Adequately Implement Design Requirements for Containment Air Cooler Pipe
Supports).
- 66 -
4OA6 Meetings, Including Exit
Exit Meeting Summary
On February 25, 2014, the inspectors presented the inspection results to Mr. M. Prospero, Plant
Manager, and other members of the licensee staff. The licensee acknowledged the issues
presented. The licensee confirmed that any proprietary information reviewed by the inspectors
had been returned or destroyed.
- 67 -
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
S. Anderson, Manager, Design Engineering
D. Bakalar, Manager, Security
J. Bousum, Manager, Emergency Planning and Administration
C. Cameron, Supervisor Regulatory Compliance
L. Cortopassi, Site Vice President
M. Ferm, Manager, System Engineering
K. Ihnen, Manager, Site Nuclear Oversight
T. Lindsey, Director, Training
E. Matzke, Senior Licensing Engineer, Regulatory Assurance
J. McManus, Manager, Engineering Programs
B. Obermeyer, Manager, Corrective Action Program
M. Prospero, Plant Manager
T. Orth, Director, Site Work Management
S. Shea, Supervisor, Operations Training
T. Simpkin, Manager, Site Regulatory Assurance
S. Swanson, Director, Operations
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Untimely Submittal of Required Licensee Event Reports05000285/2014002-05 VIO
(Section 4OA3.4)
Unqualified Coating used as a Water Tight Barrier in Rooms 81
05000285/2013-015-01 LER
and 82 (Section 4OA3.6)
Reporting of Additional High Energy Line Break Concerns
05000285/2013-016-00 LER
(Section 4OA3.7)
Failure to Restore Compliance for Containment Spray Runout
Conditions (Section 4OA3.8)
Non-Seismic Circulating Water Pipe Could Disable Raw Water
05000285/2013-019-00 LER
Pumps (Section 4OA3.9)
Closed
Inadequate Calculation of Uncertainty Results a Technical
05000285/2012-013-00 LER
Specification Violation (Section 4OA3.1)
Calculations Indicate the HPSI Pumps will Operate in Run-out
05000285/2013-003-01 LER
During a DBA (Section 4OA3.2)
Containment Air Cooling Units (VA-16A/B) Seismic Criteria
05000285/2013-007-01 LER
(Section 4OA3.3)
A-1 Attachment
Closed
05000285/2013-010-01 LER HPSI Pump Flow Imbalance (Section 4OA3.4)
Unqualified Coating used as a Water Tight Barrier in Rooms 81
05000285/2013-015-00 LER
and 82 Section 4OA3.5)
Containment Spray Pump Design Documents do not Support
05000285/2013-017-00 LER
Operation in Runout (Section 4OA3.8)
Failure to Adequately Design Anchorage for Containment Spray
and Raw Water System Pipe Supports (Section 4OA5.1)
Failure to Adequately Implement Design Requirements for
Containment Air Cooler Pipe Supports (Section 4OA5.2)
Opened and Closed
Failure to Make Required 10 CFR 50.46 Report Within
Required Time (Section 4OA3.2)
Failure to Translate HPSI Pump Design Requirements to
Design Documents (Section 4OA3.2)
Failure to Maintain Design Control of HPSI Injection Valve
(Section 4OA3.4)
Failure to Request a License Amendment for Required Change
to Technical Specifications (Section 4OA3.4)
Inadequate 10 CFR 50.59 Screening for Containment Spray
Design Change (Section 4OA3.8)
Failure to Adequately Design Anchorage for Containment Spray
and Raw Water System Pipe Supports (Section 4OA5.1)
Failure to Adequately Implement Design Requirements for
Containment Air Cooler Pipe Supports (Section 4OA5.2)
LIST OF DOCUMENTS REVIEWED
Section 1R04: Equipment Alignment
Procedures
Number Title Revision
FCS Technical Specifications
FC06747 SI Pump Room (Roon 21 & 22) Heat-up During Pump 6
Operation
USAR 9.10 Auxiliary Systems - Heating, Ventilating and Air 32
Conditioning System
A-2
Condition Reports (CRs)
2013-21373 2013-23302 2014-00211 2014-00203 2014-00373
Section 1RO5: Fire Protection
Procedures
Number Title Revision
OP-MW- Fire Protection System Impairment Control 7
201-0007
SO-G-102 Fire Protection Program Plan 17
SO-G-103 Fire Protection Operability Criteria and Surveillance Requirements 27
SO-G-28 Station Fire Plan 86
SO-G-91 Control and Transportation of Combustible Materials 30
Miscellaneous Documents
Number Title Revision
EA-FC-97-001 Fire hazards Analysis Manual 17
FC05814 UFHA Combustible Loading Calculation 11
USAR 9.11 Updated Safety Analysis Report, Fire Protection Systems 24
Section 1R06: Flood Protection Measures
Procedures
Number Title Revision
SO-G-124 Flood Barrier Impairment R4a
Condition Reports (CRs)
2014-00329
Section 1R11: Licensed Operator Requalification Program and Licensed Operator
Performance
Procedures
Number Title Revision
AOP-17 Loss of Instrument Air 15
A-3
Procedures
Number Title Revision
AOP-20 Loss of Bearing Water Cooling 5
AOP-30 Emergency Fill of Emergency Feedwater Storage Tank 12a
AOP-36 Loss of Spent Fuel Pool Cooling 10
EOP-00 Standard Post Trip Actions 31
EOP-01 Reactor Trip Recovery 14a
Miscellaneous Documents
Number Title Date
Simulator Fidelity Issues January 17, 2014
Simulator Walkdown Cycle 14-1 January 18, 2014
Simulator Loss of SFPC, Loss of Bearing Water and Emergency Fill of January 2, 2014
Scenario Guide the EFWST
82103e
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
Number Title Revision
FCSG-19 Performing Risk Assessments 17
SO-M-100 Conduct of Maintenance 57b
SO-M-101 Maintenance Work Control 103
Section 1R15: Operability Determinations and Functionality Assessments
Procedures
Number Title Revision
FC-1137 Acceptance fro Operability (OPSAC) 21
OP-FC-108-115 Operability Determinations 0a
OP-FC-108-115-1001 Operability Evaluation Asset Suite Engineering Change 0
Desktop Guide
OP-FC-108-115-1002 Supplemental Consideration for On-Shift Immediate 0
A-4
Procedures
Number Title Revision
OP-FC-108-115-1003 Operability Determination Oversight and Monitoring 0
Calculations
Number Title Revision
FC08167 Acceptable Minimum Wall Thickness for Raw Water Piping 0
Downstream of Component Cooling Water Heat Exchanger
AC-1D
Miscellaneous Documents
Number Title Date
N-513-3 Cases of ASME Boiler and Pressure Vessel Code, January 26, 2009
Evaluation Criteria for Temporary Acceptance of Flaws in
Moderate Energy Class 2 or 3 Piping
Condition Reports (CRs)
2012-15755 2011-5244 2014-01963 2013-22937 2013-23166
Section 1R19: Post-Maintenance Testing
Procedures
Number Title Revision
EM-PM-EX-1000 480 Volt Motor Inspection 24
FC05571 HCV-2504A Leakage Rate compared to allowable limits 0
IC-CP-01-1112 Calibration of Auxiliary Feedwater Pump FW-54 Suction 3
Flow Loop F-1112
IC-CP-01-1117 Auxiliary Feedwater Pump FW-54 Discharge Flow 3
Indication
MM-PM-AFW-0002 Diesel Engine FW-56 Fluid Maintenance 8
MM-PM-AFW-0005 Diesel Engine FW-56 Maintenance 7
OP-PM-AFW-0004 Third Auxiliary Feedwater Pump Operability Verification 39
PBD-5 Containment Leak Rate 18
QC-ST-SL-3001 Primary Sample System RCS Sample Lines Pressure 6
Test
A-5
Condition Reports (CR)
2014-00522
Work Orders (WO)
506373 424138 472519 476594 476967
480835 437931 481784 481785 490755
Section 1R22: Surveillance Testing
Procedures
Number Title Revision
IC-ST-IA-3009 Operability Test of IA-YCV-1045-C and Close Stroke Test of 24
YCV-1045
OP-ST-AFW- Auxiliary Feedwater Pump FW-10, Steam Isolation Valve, 20
3011 and Check Valve Tests
OP-ST-RC-3001 Reactor Coolant System (RCS) Leak Rate Test 36
OP-ST-RW-3021 AC-10C Raw Water Pump Quarterly Inservice Test 39
Drawings
Number Title Revision
11405-M-253 Steam Generator and Blowdown Flow Diagram P&ID 98
Condition Reports (CR)
2012-15755 2014-01943 2014-01970 2014-01969
Work Orders (WO)
492131 491025
Section 4OA2: Problem Identification and Resolution (71152)
Procedures
Number Title Revision
FCSG-24-1 Condition Report Initiation 6
FCSG-24-3 Condition Report Screening 12a
FCSG-24-4 Condition Report and Cause Evaluation 8a
A-6
Section 4OA2: Problem Identification and Resolution (71152)
Procedures
Number Title Revision
FCSG-24-6 Corrective Action Implementation and Condition Report 12a
Closure
SO-R-2 Condition Reporting and Corrective Action 53b
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
Procedures
Number Title Revision
NOD-QP-3 10 CFR 50.59 and 10 CFR 72.48 Reviews 37
FCSG-23 10 CFR 50.59 Resource Manual 8
SO-R-1 Reportability Determinations 26 - 32
Condition Reports (CR)
2013-09949 2008-1666 2013-08300 2013-22007 2012-03796
2013-10910 2008-1683 2013-19722 2014-01029 2012-03796
2013-12508 2013-15047 2013-16417 2013-17630 2013-09949
2014-00958 2014-01358 2013-15442 2013-16241 2014-00674
2013-02100 2013-14177 2014-01629 2012-09494 2012-08137
2012-03986 2012-05615 2012-17437 2011-09459 2012-18.335
2012-05615 2011-09956
Other Documents
Number Title Revision /
Date
DEN Memorandum, 90% SMART Meeting Held on September 19,
Wednesday September 18, 2013 for EC 59874.HPSI Pump 2013
Runout Orifice Plates for SI-2A, SI-2B and SI-2C Revision
1,
EA 13-023 Fort Calhoun SBLOCA Analysis with Reduced HPSI Flow August 16, 2013
(AREVA Calc. 32-9130020-001)
A-7
Other Documents
Number Title Revision /
Date
EA 13-028 Fort Calhoun Safety Analysis Evaluation with Reduced August 16, 2013
HPSI Flow (AREVA Calc. 51-9130106-002)
EC 30663 GSI-191 Implementation 0
EC 59874 HPSI Pump Runout Orifice Plates for SI-2A, SI-2B and SI- July 30, 2013
2C, Rev 1 Kickoff Meeting
EC 59874 HPSI Pump Runout Orifice Plates for SI-2A, SI-2B and SI- 0,1
2C
EC 62416 Temporary Modification - Throttle Discharge Valves HCV- 1,2
2958, HCV-2968, and HCV-2978
FC 07470 Minimum Pump Performance Curve for HPSI Pump 0
FC-68C Applicability Determination, HPSI Pump Runout, SI-2A, SI- October 2, 2013
2B and SI-2C Part 3 of 3 (HPSI Loop Flow Balancing)
LER 2013-010-0 HPSI Pump Flow Imbalance July 2, 2013
LER 2013-010-1 HPSI Pump Flow Imbalance October 23, 2013
LIC 13-0133 30-Day Report of a Significant Change in the Loss-of- September 20, 2013
Coolant Accident (LOCA)/Emergency Core Cooling System
(ECCS) Models Pursuant to 10 CFR 50.46
LIC 77-0090 OPPD Letter to NRC August 22, 1977
NEI 0705 10 CFR 50.46 Reporting Guidelines July 2008
NRC 77-0060 NRC Letter to OPPD June 30, 1977
Section 4OA5: Other Activities
Condition Reports (CR)
2013-3722 2013-5304
A-8