ML16005A567
| ML16005A567 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 01/05/2016 |
| From: | Christine Lipa NRC/RGN-III/DRS/EB2 |
| To: | Davison K Northern States Power Co |
| References | |
| IR 2015008 | |
| Download: ML16005A567 (30) | |
See also: IR 05000306/2015008
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE RD. SUITE 210
LISLE, IL 60532-4352
January 5, 2016
Mr. Kevin Davison
Site Vice President
Prairie Island Nuclear Generating Plant
Northern States Power Company, Minnesota
1717 Wakonade Drive East
Welch, MN 55089
SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 - NRC
ANNUAL FOLLOW-UP OF SELECTED PROBLEM IDENTIFICATION AND
RESOLUTION ISSUES; INSPECTION REPORT 05000282/2015008;
05000306/2015008 AND NOTICE OF VIOLATION
Dear Mr. Davison:
On November 24, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an annual
problem identification and resolution follow-up sample at your Prairie Island Nuclear Generating
Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were
discussed on November 24, 2015, with Mr. S. Northam, Vice President of Fleet Operations, and
other members of your staff.
Based on the results of this inspection, the NRC has identified an issue that was evaluated
under the risk significance determination process as having very low safety significance
(Green). The NRC has also determined that a violation is associated with this issue. This
violation was 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).
This violation is cited in the enclosed Notice of Violation (Notice), and the circumstances
surrounding it are described in detail in the subject inspection report. The violation is being
cited in the Notice, consistent with the NRC Enforcement Policy, Section 2.3.2.a.2, because
Prairie Island Nuclear Generating Plant, Unit 2, failed to restore compliance and failed to have
objective plans to restore compliance in a reasonable time period following the NRC
identification of an associated Non-Cited Violation (NCV) on June 30, 2011. The associated
NCV was documented in Inspection Report (IR) 05000282/2011003; 05000306/2011003.
You are required to respond to this letter and should follow the instructions specified in the
enclosed Notice when preparing your response. If you have additional information that you
believe the NRC should consider, you may provide it in your response to the Notice. The NRC
review of your response to the Notice will also determine whether further enforcement action is
necessary to ensure compliance with regulatory requirements.
Based on the results of this inspection, the NRC has also identified four issues that were
evaluated under the risk significance determination process as having very low safety
significance (Green). The NRC has also determined that violations are associated with these
issues. These violations are being treated as NCVs, consistent with Section 2.3.2 of the
Enforcement Policy. These NCVs are described in the subject inspection report. Additionally,
a licensee-identified violation is listed in Section 4OA7 of this report.
K. Davison -2-
If you contest the subject or severity of any 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 III; the Director, Office of Enforcement, U.S.
Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident
Inspector at the Prairie Island Nuclear Generating Plant.
In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 III, and the NRC Resident
Inspector at Prairie Island Nuclear Generating Plant.
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy
of this letter, its enclosure, and your response (if any) will be available electronically for public
inspection in the 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/
Christine A. Lipa, Chief
Engineering Branch 2
Division of Reactor Safety
Docket Nos. 50-282, 50-306
Enclosure:
1. Notice of Violation
2. IR 05000282/2015008; 05000306/2015008
cc: Distribution via LISTSERV
NOTICE OF VIOLATION
Northern States Power Company Docket No. 50-306
Prairie Island Nuclear Generating Plant, Unit 2 License No. DPR-60
During an U.S. Nuclear Regulatory Commission (NRC) inspection conducted from
October 5 through November 24, 2015, a violation of NRC requirements was identified.
In accordance with the NRC Enforcement Policy, the violation is listed below:
Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B, Criterion XVI,
Corrective Action, states, in part, that measures shall be established to assure that
conditions adverse to quality (CAQs), such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and non-conformances, are promptly
identified and corrected.
Contrary to the above, from April 11, 2011, to at least October 22, 2015, the licensee
failed to correct a CAQ. Specifically, on April 11, 2011, the NRC identified that the
licensee was not monitoring five safety-related gas susceptible locations within the
emergency core cooling system considered to be inaccessible and the licensee
captured this CAQ in their Corrective Action Program. However, on October 22, 2015,
the inspectors identified that the licensee had not corrected this CAQ for two of these
locations and did not have objective plans to restore compliance.
This violation is associated with a Green Significance Determination Process finding.
Pursuant to the provisions of 10 CFR 2.201, Northern States Power Company, 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 III, and a copy to the NRC Resident Inspector at the
Prairie Island Nuclear Generating Plant, Units 1 and 2, within 30 days of the date of the
letter transmitting this Notice. This reply should be clearly marked as a Reply to a Notice of
Violation; VIO 05000306/2015008-01, 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.
Because your response will be made available electronically for public inspection in the NRC
Public Document Room or from 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
Enclosure 1
Notice of Violation
the information that should be protected and a redacted copy of your response that deletes
such information. If you request withholding of such material, you must specifically identify the
portions of your response that you seek to have withheld and provide in detail the bases for your
claim of withholding (e.g., explain why the disclosure of information will create an unwarranted
invasion of personal privacy or provide the information required by 10 CFR 2.390(b) to support
a request for withholding confidential commercial or financial information). If safeguards
information is necessary to provide an acceptable response, please provide the level of
protection described in 10 CFR 73.21.
In accordance with 10 CFR 19.11, you may be required to post this Notice within two working
days of receipt.
Dated this 5th day of January, 2016.
2
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-282; 50-306
Report No: 05000282/2015008; 05000306/2015008
Licensee: Northern States Power Company, Minnesota
Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2
Location: Welch, MN
Dates: October 5 - November 24, 2015
Inspector: N. Féliz Adorno, Senior Reactor Inspector
Approved by: Christine A. Lipa, Chief
Engineering Branch 2
Division of Reactor Safety
Enclosure 2
Table of Contents
SUMMARY ................................................................................................................................ 2
REPORT DETAILS .................................................................................................................... 5
1. REACTOR SAFETY 5
4OA2 Identification and Resolution of Problems (71152) 5
4OA6 Meetings 20
4OA7 Licensee-Identified Violations 20
SUPPLEMENTAL INFORMATION............................................................................................. 1
Key Points of Contact ............................................................................................................. 1
List of Items Opened, Closed and Discussed ......................................................................... 1
List of Documents Reviewed .................................................................................................. 2
List of Acronyms Used ............................................................................................................ 4
SUMMARY
Inspection Report 05000282/2015008, 05000306/2015008; 10/05/2015 - 11/24/2015; Prairie
Island Nuclear Generating Plant, Units 1 and 2; Annual Problem Identification and Resolution
Inspection.
This report covers an 8-week period of inspection by primarily one regional inspector focused on
gas accumulation management in piping. Four Green findings were identified by the inspector
and one Green finding was self-revealed. Four of these findings involved Non-Cited Violations
(NCVs) of U.S. Nuclear Regulatory Commission (NRC) requirements while one of these findings
involved a Notice of Violation of NRC requirements. The significance of inspection findings is
indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red), and determined
using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, dated
April 29, 2015. Cross-cutting aspects are determined using IMC 0310, Aspects Within the
Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are
dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015.
The NRC's program for overseeing the safe operation of commercial nuclear power reactors
is described in NUREG-1649, Reactor Oversight Process, dated February 2014.
NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green. The inspectors identified a finding of very low safety significance (Green), and
an associated cited violation of Title 10, Code of Federal Regulations (CFR), Part 50,
Appendix B, Criterion XVI, Corrective Actions, for the failure to correct a condition
adverse to quality (CAQ). Specifically, on August 1, 2011, the NRC issued an NCV for
the failure to monitor five safety-related gas susceptible locations considered to be
inaccessible, which is a CAQ. As of November 24, 2015, the licensee had not corrected
this CAQ for two of those locations and did not have plans to restore compliance. The
licensee captured this issue into their Corrective Action Program (CAP) with a proposed
corrective action to develop an alternative monitoring method for these locations when
the unit is operating.
The performance deficiency was determined to be more than minor because it was
associated with the Mitigating Systems cornerstone attribute of equipment performance,
and affected the cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. The finding screened as of very low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee was able to access and inspect these locations during the
refueling outage that was ongoing when this issue was identified and confirmed that
they were full of water during the previous operating cycle. In addition, a historical
review did not find information that challenged operability due to gas accumulation at
these locations. The inspectors determined that this finding had a cross-cutting
aspect in the area of problem identification and resolution because the licensee did
not thoroughly evaluate their discovery that the CAQ was not been corrected on
July 29, 2013. Specifically, on 2013, the licensee initiated a condition evaluation (CE)
to determine if the action plan at the time addressed the NCV associated with the CAQ.
However, the CE was closed by crediting actions that were similar to those that resulted
in the NCV and other documented observations associated with the inappropriate
resolution of the issue. [P.2] (Section 4OA2.1.c(1))
2
- Green. The inspectors identified a finding of very low safety significance (Green),
and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, for the licensees failure to manage gas accumulation at
the residual heat removal (RHR) train credited for emergency core cooling in MODE 4,
Hot Shutdown. Specifically, the RHR train credited for emergency core cooling in
MODE 4 was not verified to be full of water before its operability was required in
MODE 4 following system draining during refueling outage 1R29. The licensee
captured this issue into their CAP with a proposed corrective action to revise procedures
to explicitly require these inspections prior to transitioning into MODE 4 during startup
activities.
The performance deficiency was determined to be more than minor because it was
associated with the Mitigating Systems cornerstone attribute of equipment performance,
and affected the cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. The finding screened as of very low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee reviewed records associated with gas accumulation
management activities during 1R29 and discovered that a non-conforming void was
vented 12 - 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> after the transition to MODE 4. However, an operability review
reasonably determined that this non-conforming condition did not result in loss of
operability. The inspectors did not identify a cross-cutting aspect associated with this
finding because it was not confirmed to reflect current performance.
(Section 4OA2.1.c(2))
- Green. A finding of very low safety significance (Green), and an associated NCV of
10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
was self-revealed for the licensees failure to establish procedures to verify RHR is
operable with respect to gas accumulation following maintenance outages. Specifically,
procedures were not established to verify the system is sufficiently full of water when
RHR is secured in its standby emergency core cooling system mode of operation during
startup activities following maintenance outages. The licensee captured this issue into
their CAP. As a long term corrective action, the licensee revised procedures to require
gas accumulation inspections of the affected gas susceptible locations as part of the unit
startup activities following a maintenance outage.
The performance deficiency was determined to be more than minor because it was
associated with the Mitigating Systems cornerstone attribute of equipment performance,
and affected the cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. The finding screened as of very low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee performed a past operability review of the limiting void found at
the RHR piping after maintenance outages and reasonably concluded that the system
remained operable. The inspectors did not identify a cross-cutting aspect associated
with this finding because it was not confirmed to reflect current performance.
(Section 4OA2.1.c(3))
- Green. The inspectors identified a finding of very low safety significance (Green), and
an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for
the licensees failure to manage potential gas accumulation due to safety injection
3
isolation check valve leakage following maintenance outages. Specifically, the licensee
did not evaluate the potential to accumulate nitrogen at multiple RHR and safety
injection gas susceptible locations due to safety injection check valve unseating caused
by maintenance outages. As a result, the station did not manage this gas intrusion
mechanism. The licensee captured this issue into their CAP with a proposed corrective
action to revise procedures to verify that the safety injection check valves are seated as
part of the unit startup activities following a maintenance outage.
The performance deficiency was determined to be more than minor because it was
associated with the Mitigating Systems cornerstone attribute of equipment performance,
and affected the cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. The finding screened as of very low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee performed a past operability review of the limiting void found
at one of the affected piping locations and reasonably concluded that the associated
system remained operable. The inspectors did not identify a cross-cutting aspect
associated with this finding because it was not confirmed to reflect current performance.
(Section 4OA2.1.c(4))
- Green. The inspectors identified a finding of very low safety significance (Green) and
associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for
the licensees failure to identify a continuous gas intrusion into one train of RHR, which
was a CAQ, resulting in a continuous undetected void growth that exceeded the
applicable operability limits. The licensee did not consider applicable active gas
intrusion mechanisms when evaluating the discovery of a void at the RHR piping.
The licensee captured this issue into their CAP and stopped the continuous gas
intrusion into the affected piping location.
The performance deficiency was determined to be more than minor because it was
associated with the Mitigating Systems cornerstone attribute of equipment performance,
and affected the cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. The finding screened as of very low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee performed a past operability review of the void and reasonably
concluded that the system remained operable. The inspectors determined that this
finding had a cross cutting aspect in the area of human performance because the
licensee did not recognize and plan for the possibility of mistakes when evaluating the
gas surveillance results of February 10, 2015. Specifically, the licensee did not plan for
the possibility that the unacceptable results were indicative of a different problem than
originally determined or a combination of problems. As a result, the licensee failed to
identify the continuous gas intrusion incident. [H.12] (Section 4OA2.1.c(5))
Licensee-Identified Violations
A violation of very low safety significance (Green) that was identified by the licensee has
been reviewed by the NRC. Corrective actions taken or planned by the licensee have
been entered into the licensees CAP. This violation and CAP tracking numbers are
listed in Section 4OA7.
4
REPORT DETAILS
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
4OA2 Identification and Resolution of Problems (71152)
.1 Annual Follow-up of Selected Issues: Management of Gas Accumulation in Piping
a. Inspection Scope
During a review of items entered in the licensees Corrective Action Program (CAP), the
inspectors noted multiple corrective action documents associated with gas accumulation
issues at the residual heat removal (RHR) piping. These issues included the discovery
of unexpected complex gas accumulation issues, unplanned Limiting Condition for
Operation (LCO) entries due to gas accumulation, and gas removal challenges.
The inspectors reviewed selected gas accumulation management issues in light of the
number and complexity of the issues described above against selected performance
attributes contained in Inspection Procedure (IP) 71152-03.06. Specifically, the
inspectors reviewed corrective action documents of selected identified gas accumulation
management problems to assess completeness, accuracy, timeliness, classification,
and prioritization of the problem resolution commensurate with the associated safety
significance. In addition, the inspectors reviewed the associated operability and causal
evaluations, when applicable, to assess the licensee evaluation of non-conforming
conditions and their impact to safe plant operation. The inspectors also reviewed the
licensee consideration of extent of condition and previous occurrences of the associated
problems. In addition, the inspectors reviewed the corrective actions of selected issues
to assess problem resolution activities, including timeliness. This assessment also
included a review of associated drawings, procedures, and design reviews, and
interviews of licensee personnel. The documents reviewed are listed in the Attachment
to this report.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b. Observations
The inspectors noted the following examples of licensee CAP weaknesses when
addressing gas accumulation management issues:
- The licensee had not corrected a condition adverse to quality (CAQ), which was
previously identified, and did not have plans to restore compliance. Specifically,
on August 1, 2011, the U.S. Nuclear Regulatory Commission (NRC) issued a
Non-Cited Violation (NCV) for the failure to monitor five safety-related gas
susceptible locations considered to be inaccessible. As of November 24, 2015,
the licensee had not corrected this CAQ for two of those locations and did not
have plans to restore compliance. The details and enforcement action
associated with this issue are discussed in Section 4OA2.1.c(1) of this Inspection
Report (IR).
5
- A corrective action associated with a minor violation documented in
IR 05000282/2011003; IR 05000306/2011003, dated August 1, 2011, was
inconsistently implemented. Specifically, on 2011, the inspectors identified
a minor violation of Title 10, Code of Federal Regulations (CFR), Part 50,
Appendix B, Criterion V, Instruction, Procedures, and Drawings, for the failure
to trend the sizes of voids discovered during periodic gas monitoring activities,
which was contrary to procedure H64, Gas Accumulation Management Program
(GAMP). The licensee captured this issue in their CAP as Action Request
(AR) 1271024, and implemented corrective actions to trend void sizes. However,
during this inspection period, the inspectors noted that the licensee inconsistently
trended void sizes. Specifically, void sizes were not clearly documented to
differentiate between the as-found and as-left measurements. In addition, after
the original corrective action was implemented, the licensee implemented a new
trending tool but the data had not been completely uploaded. This inconsistent
implementation of the GAMP trending requirements was determined to be minor
during this inspection period because the data was retrievable and the inspectors
did not find an adverse unrecognized trend. The licensee capture this concern in
their CAP as AR 01496191.
- The licensee did not document the discovery of a problem in their CAP.
Specifically, during the reactor unit startup activities associated with refueling
outage 1R29, the licensee discovered a void at the RHR system that exceeded
its operability limits when this system was required to be operable. However, the
licensee did not document this CAQ in their CAP. The details and enforcement
action of the associated issue are discussed in Section 4OA2.1.c(2) of this IR.
- The licensee did not identify a CAQ. Specifically, when evaluating the discovery
of voids at the RHR piping during a surveillance, the licensee did not consider
that the affected locations were vulnerable to active gas intrusion mechanisms
(i.e., those that result in a continuous gas intrusion). As a result, the licensee
failed to identify an ongoing continuous gas intrusion into the RHR system, which
was a CAQ, and the corrective actions taken were limited to address the portion
of the problem that was not associated with the active gas intrusion incident. The
details and enforcement action of this issue are discussed in Section 4OA2.1.c(5)
of this IR, while Sections 4OA2.1.c(3) and 4OA2.1.c(4) discuss the details and
enforcement actions of other closely related issues.
c. Findings
(1) Failure to Correct an Non-Cited Violation Associated with Inadequate Gas Monitoring of
Inaccessible Residual Heat Removal Gas Susceptible Locations
Introduction: A finding of very low safety significance (Green), and an associated
cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was
identified by the inspectors for the licensees failure to correct a CAQ. Specifically, on
August 1, 2011, the NRC issued an NCV for the failure to monitor five safety-related
gas susceptible locations considered to be inaccessible, which is a CAQ. As of
November 24, 2015, the licensee had not corrected this CAQ for two of those locations
and did not have plans to restore compliance.
Description: On January 11, 2008, the NRC requested each Generic Letter
(GL) 2008-01, Managing Gas Accumulation in Emergency Core Cooling (ECCS), Decay
Heat Removal (DHR), and Containment Spray (CS) Systems, addressee to evaluate
6
the ECCS, DHR, and CS systems licensing basis, design, testing, and corrective actions
to ensure that gas accumulation was maintained less than the amount that would
challenge the operability of these systems. One of the licensees original actions to
address these requests was to establish procedure H64 to programmatically control gas
accumulation at the Generic Letter (GL) 2008-01 subject systems. Section 4.5.4.B of
procedure H64, Revision 2, stated that, Monitoring may not be practical for locations
that are inaccessible due to radiological, environmental conditions, the plant
configuration or personnel safety. It further stated that For these locations alternative
methods should be developed to monitor the potential void locations. Revision 16 of
procedure FP-G-DOC-05, Procedure Writers Guide, Section 4.12, states that, When
used in NSPM documents, use of the term should denotes an expected action. It also
stated that, Deviations from these expectations require prior management approval.
On April 11, 2011, the NRC identified that the licensee had not developed alternative
methods to monitor the potential for gas accumulation at five inaccessible susceptible
locations that require periodic monitoring (i.e., gas susceptible locations 2RH-13,
2RH-15, 2SI-45, 1SI-41, and 1RH-21). This procedure H64 deviation did not receive
prior management approval as required by procedure FP-G-DOC-05. This issue was
originally captured by the licensee in their CAP as AR 01271826, and was documented
by the inspectors as NCV 05000282/2011003-09; 05000306/2011003-09, Alternative
Methods Were Not Developed for Monitoring Inaccessible Susceptible Locations, in
IR 05000282/2011003; IR 05000306/2011003, dated August 1, 2011. This IR also
documented that the inspectors noted that AR 01271826 was not appropriate for the
issue and were concerned that this vulnerability could result in the cancelation of the
corrective action assignment related to this issue. As a result, the IR stated that the
licensee issued a different corrective action document (i.e., AR 01281682) to capture
this issue.
On July 29, 2013, the licensee discovered that the resolution of AR 01281682 was
effectively a repeat of the inappropriate action associated with AR 01271826 that had
been documented in the IR. Specifically, AR 01281682 was closed to no action by
crediting resolution of a third corrective action document (i.e., AR 01281652). To
resolve the inspectors concerns, the apparent cause evaluation (ACE) conducted
under AR 01281652 credited existing corrective action assignments tracked by
AR 01271826, which was the original corrective action document determined to be
inappropriate to address this concern. The licensee captured this discovery in their CAP
as AR 01391787, and initiated a CE to determine if the action plan at the time addressed
the NCV.
During this inspection period, the inspectors noted that, for Unit 2 RHR gas susceptible
locations 2RH-13 and 2RH-15, the CE was closed by crediting some actions that were
similar to the NRC observations documented in the previous IR associated with
AR 01271826, and with the licensee observations captured in AR 01391787.
Specifically, the CE determined that the closure of AR 01281682 to AR 01281652 was
appropriate because both ARs had the same severity level. However, the CE failed to
recognize that AR 01281652 credited AR 01271826, which had a lower severity level
and was the subject of previous documented concerns. In addition, the inspectors noted
that the CE was closed by crediting other actions that were similar to the actions that
resulted in the NCV. Specifically, the CE determined that the NCV was resolved by
noting that gas susceptible locations 2RH-13 and 2RH-15 were added to the quarterly
gas accumulation surveillance procedures and have been tested by recent surveillances.
7
However, the CE failed to recognize that these locations were always identified by these
procedures but, since these high points were inaccessible, some of the surveillances
were completed at the highest accessible locations and these were not adequate
monitoring locations because they would not allow the detection of voids before they
exceed the applicable design limits. This was the observation that led to the NRC
identification of the NCV in 2011.
The inspectors were concerned because, as of October 22, 2015, the licensee had
not restored compliance and did not have objective plans to restore compliance in a
reasonable time period following the NRC identification of the NCV on April 11, 2011.
The licensee captured the inspectors concerns in the CAP as AR 01498169. The
proposed corrective action to restore compliance at the time of this inspection was to
develop an alternative monitoring method for these locations when the unit is operating.
In addition, since these locations are accessible during outages and the affected unit
was in an outage when this issue was identified, the licensee confirmed that the affected
locations were full of water during the previous operating cycle.
Analysis: The inspectors determined that the failure to correct the lack of periodic gas
accumulation monitoring of inaccessible RHR gas susceptible locations, which is a CAQ,
was contrary to 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, and was
a performance deficiency. The performance deficiency was determined to be more than
minor because it was associated with the Mitigating Systems cornerstone attribute of
equipment performance, and affected the cornerstone objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Specifically, the failure to periodically monitor gas
susceptible locations 2RH-13 and 2RH-15 does not ensure the availability and reliability
of the RHR system to perform its accident mitigating function because a potential
adverse void would not be detected and managed to ensure operability.
The inspectors determined the finding could be evaluated using the Significance
Determination Process (SDP) in accordance with Inspection Manual Chapter (IMC) 0609, SDP, Attachment 0609.04, Initial Characterization of Findings, issued
on June 19, 2012. Because the finding impacted the Mitigating Systems cornerstone,
the inspectors screened the finding through IMC 0609, Appendix A, The SDP for
Findings At-Power, issued on June 19, 2012, using Exhibit 2, Mitigating Systems
Screening Questions. The finding screened as of very low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee was able to inspect these locations during the refueling outage
that was ongoing when this issue was identified and confirmed that they were full of
water during the previous operating cycle. In addition, a historical review did not find
information that challenged operability due to gas accumulation at these locations.
The inspectors determined that this finding had a cross cutting aspect in the area of
problem identification and resolution because the licensee did not thoroughly evaluate
their discovery that the CAQ was not been corrected on July 29, 2013. Specifically, the
licensee initiated a CE to determine if the action plan at the time addressed the NCV
associated with the CAQ. However, the CE was closed by crediting actions that were
similar to those that resulted in the NCV and other documented observations associated
with the inappropriate resolution of the issue. [P.2]
8
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action,
states, in part, that measures shall be established to assure that CAQs, such as failures,
malfunctions, deficiencies, deviations, defective material and equipment, and
non-conformances, are promptly identified and corrected.
Contrary to the above, from April 11, 2011, to at least October 22, 2015, the licensee
failed to correct a CAQ. Specifically, on April 11, 2011, the NRC identified that the
licensee was not monitoring five safety-related gas susceptible locations within the
ECCS considered to be inaccessible and the licensee captured this CAQ in their CAP.
However, on October 22, 2015, the inspectors identified that the licensee had not
corrected this CAQ for two of these locations and did not have objective plans to
restore compliance.
The licensee is still evaluating its planned corrective actions. However, the inspectors
determined that the continued non-compliance does not present an immediate safety
concern because the affected unit was in an outage and the licensee established
procedures to mitigate the applicable gas intrusion mechanisms during startup activities.
This violation is being cited as described in the Notice, which is enclosed with this IR.
This is consistent with the NRC Enforcement Policy, Section 2.3.2.a.2, which states,
in part, that the licensee must restore compliance within a reasonable period of time
(i.e., in a timeframe commensurate with the significance of the violation) after a violation
is identified. The NRC identified the original issue on April 11, 2011, and dispositioned it
as NCV 05000282/2011003-09; 05000306/2011003-09 in IR 05000282/2011003;
IR 05000306/2011003, dated August 1, 2011. On October 22, 2015, the inspectors
determined that the licensee failed to restore compliance within a reasonable time for
two of the five affected gas susceptible locations following the identification of this CAQ
and failed to have objective plans to restore compliance. (VIO 05000306/2015008-01,
Failure to Correct an NCV Associated with Inadequate Gas Monitoring of Inaccessible
RHR Gas Susceptible Locations)
(2) Failure to Manage Gas Accumulation at the Residual Heat Removal Train Credited for
Emergency Core Cooling in MODE 4
Introduction: The inspectors identified a finding of very low safety significance (Green),
and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, for the licensees failure to manage gas accumulation
at the RHR train credited for emergency core cooling in MODE 4, Hot Shutdown.
Specifically, the RHR train credited for emergency core cooling in MODE 4 was not
verified to be full of water before its operability was required in MODE 4 following
system draining during refueling outage 1R29.
Description: During refueling outage 1R29, which occurred during the fall of 2014,
the licensee partially drained both RHR trains for maintenance work under clearance
orders 56788 and 59050. Subsequently, the drained piping sections were filled and
vented. In addition, the licensee performed dynamic venting in an attempt to flush any
remaining void while in MODE 6, Refueling. While in MODE 5, Cold Shutdown,
some of the gas susceptible locations were inspected to verify that they were full of
water prior to entry into MODE 4 to support the emergency core cooling RHR mode of
operation. Specifically, LCO 3.5.3, ECCS - Shutdown, of the licensees Technical
Specifications (TS) required one ECCS train to be operable in MODE 4 when both
9
reactor coolant system (RCS) cold leg temperatures are greater than the safety
injection pump disable temperature specified in the Pressure and Temperature
Limits Report (PTLR).
During this inspection period, the inspectors noted that the licensee did not inspect all
of the gas susceptible locations that were potentially impacted by the draining activity
prior to crediting the Unit 1 B RHR train for emergency core cooling in MODE 4.
Specifically, the licensee completed these inspections following entry into MODE 4.
In addition, inspection of the Unit 1 B RHR train minimum flow line discovered a
29.1 cubic inch void that exceeded the 18 cubic inch operability limit established in
procedure TP 1468, Unit 1 GL-08-01 Inspections. The licensee estimated that this
discovery occurred 12 - 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> after transitioning to MODE 4. The Unit 1 A RHR
train was inoperable during this timeframe due to other planned activities.
In addition, the licensee did not capture the discovery of the 29.1 cubic inch void in
their CAP during 1R29. The likely reasons for the failure to initiate a corrective action
document were that the performers of TP 1468 did not recognize that operability of the
affected RHR train was required in MODE 4 and that the as-left condition was within
acceptable limits. As a result, the inspectors reviewed the upcoming refueling outage
schedule and noted that it specified completion of the gas accumulation inspections prior
to transitioning to MODE 4. In addition, the licensee was planning to revise procedure
H64 to explicitly require these inspections prior to MODE 4. However, the inspectors
noted that this revision was not tracked as a corrective action. As a result, the licensee
initiated AR 01496254 to track this procedure revision.
The licensee captured the failure to manage gas accumulation at the RHR train credited
for emergency core cooling in MODE 4 during 1R29 in the CAP as AR 01500190. The
immediate corrective action was to evaluate RHR operability. Specifically, the licensee
determined that the RHR was full of water based on the most recent TP 1468 results.
In addition, the licensee determined that the 29.1 cubic inch void was bounded by recent
operability evaluations of larger voids at the affected location. The proposed plan to
restore compliance at the time of this inspection credited the AR 01496254 assignment
to revise procedure H64.
Analysis: The inspectors determined that the failure to manage gas accumulation for the
RHR train credited for emergency core cooling in MODE 4 was contrary to procedure
H64 and was a performance deficiency. The performance deficiency was determined
to be more than minor because it was associated with the Mitigating Systems
cornerstone attribute of equipment performance and affected the cornerstone objective
of ensuring the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Specifically, the failure to manage gas
accumulation for the RHR train credited for emergency core cooling in MODE 4 does not
ensure the availability and reliability of the RHR system to perform its accident mitigating
function. In addition, this failure resulted in crediting an RHR train for emergency core
cooling in MODE 4 that was not verified to be full of water and that was later determined
to have a void that exceeded the associated design limits.
The inspectors determined the finding could be evaluated using the SDP in accordance
with IMC 0609, SDP, Attachment 0609.04, Initial Characterization of Findings, issued
on June 19, 2012. Because the finding occurred during shutdown operations, the
inspectors screened the finding through IMC 0609 Appendix G, Shutdown Operations
10
SDP, issued on May 9, 2014, which referred to Attachment 1 of IMC 0609, Appendix G,
Phase 1 Initial Screening and Characterization of Findings, issued on May 9, 2014.
Because the finding impacted the Mitigating Systems cornerstone, the inspectors
screened the finding through using Exhibit 3, Mitigating Systems Screening Questions,
of this attachment. The finding screened as of very low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee reviewed records associated with gas accumulation
management activities during 1R29 and discovered that a non-conforming void was
vented 12 - 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> after the transition to MODE 4. However, an operability review
reasonably determined that this non-conforming condition did not result in loss of
operability.
The inspectors did not identify a cross-cutting aspect associated with this finding
because it was not confirmed to reflect current performance. Specifically, although
this finding occurred within the last 3 years, the inspectors reviewed the schedule
for the upcoming refueling outage and noted that it specified completion of the gas
accumulation inspections prior to transitioning to MODE 4. In addition, the licensee
was planning to revise procedure H64 to explicitly require these inspections prior to
MODE 4.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, requires, in part, that activities affecting quality be prescribed by
documented procedures of a type appropriate to the circumstances and be
accomplished in accordance with these procedures.
The licensee established Revision 2 of procedure H64 as the implementing procedure
for managing gas accumulation in ECCS. Section 4.8 of procedure H64 states that,
Any system maintenance activity that will result in a reduction in fluid inventory of a fluid
system in the scope of the gas accumulation management program should be evaluated
to determine the required fill, vent and verification inspection. It also stated that, The
work processes should include provision for engineering review and evaluation of such
evolutions. Subsection 4.8.3, stated that, Engineering should either specify as part
of their review or confirm the procedure that the selected verification locations will
demonstrate that the system is sufficiently full to perform its functions. It further stated
that, This includes the specification of appropriate verification locations and methods.
The licensee established Revision 16 of procedure FP-G-DOC-05, Procedure
Writers Guide, as the implementing procedure for writing procedures to ensure that
management expectations regarding responsibilities and methods for accomplishing
these responsibilities are provided to personnel. Procedure FP-G-DOC-05,
Section 4.12, states that, When used in NSPM documents, use of the term should
denotes an expected action. It also stated that, Deviations from these expectations
require prior management approval.
Contrary to the above, on November 16, 2014, the licensee failed to follow Section 4.8
of procedure H64. Specifically, the licensee did not specify or confirm that selected
verification locations for RHR demonstrated that the system was sufficiently full of
water to perform its emergency core cooling function in MODE 4 following a system
maintenance activity that resulted in a fluid inventory reduction. In addition, this
deviation did not receive prior management approval, as required by Section 4.12
of procedure FP-G-DOC-05.
11
The licensee is still evaluating its planned corrective actions. However, the inspectors
determined that the continued non-compliance does not present an immediate safety
concern because the licensee created an action to ensure that the upcoming outage
schedule is updated to address this issue.
Because this violation was of very low safety significance and was entered into the
licensees CAP as AR 01500190 and AR 01496254, this violation is being treated as
a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000282/
2015008-02;05000306/2015008-02, Failure to Manage Gas Accumulation at the RHR
Train Credited for Emergency Core Cooling in MODE 4)
(3) Failure to Establish Procedures to Verify Residual Heat Removal is Full of Water
Following Maintenance Outages
Introduction: A finding of very low safety significance (Green), and an associated NCV
of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
was self-revealed for the licensees failure to establish procedures to verify RHR is
operable with respect to gas accumulation following maintenance outages. Specifically,
procedures were not established to verify the system is full of water when RHR is
secured in its standby ECCS mode of operation during startup activities following
maintenance outages.
Description: On December 10, 2014, the licensee began a Unit 1 maintenance outage
associated with a reactor coolant pump (RCP) seal replacement. During this
maintenance outage, the licensee operated RHR in its shutdown cooling mode of
operation, which circulates RCS water through the RHR system. This water had
dissolved nitrogen. On December 24, 2014, the licensee secured shutdown cooling and
aligned both RHR trains for the ECCS mode of operation. This maintenance outage
concluded on December 26, 2014. The licensee did not perform gas accumulation
inspections of the RHR piping to verify it was full of water before declaring it operable for
its ECCS mode of operation. TS LCO 3.5.3 required one ECCS train to be operable in
MODE 4 when both RCS cold leg temperatures are greater than the safety injection
pump disable temperature specified in the PTLR. In addition, TS LCO 3.5.2, ECCS -
Operating, requires two ECCS trains to be operable in MODEs 1, 2, and 3.
On January 26, 2015, the licensee began a second Unit 1 maintenance outage
associated with another RCP seal replacement. Again, the Unit 1 B RHR train was
operated in its shutdown cooling mode circulating nitrogen-rich water throughout its
piping system. On February 9, 2015, the licensee secured shutdown cooling, aligned
the Unit 1 B RHR train for the ECCS mode of operation, and transitioned to MODE 4
and 3. Again, the licensee did not perform gas accumulation inspections of the RHR
piping to verify it was full of water before declaring it operable for its ECCS mode of
operation.
On February 9, 2015, the licensee also began quarterly gas accumulation inspections
using procedure TP 1468. This periodic inspection began after transitioning to MODE 3
and was not part of the unit startup readiness activities following the maintenance
outage. On February 10, 2015, the licensee discovered voids at RHR gas susceptible
locations 1RH-12 and 1RH-11. The 1RH-12 void size was 350 cubic inches, which
exceeded the TP 1468 operability limit of 22.85 cubic inches. The 1RH-11 void size was
62.21 cubic inches, which exceeded the TP 1468 operability limit of 11.62 cubic inches.
The licensee declared both RHR trains inoperable while in MODE 1. The licensee
12
reduced the void sizes below the operability limits by venting these locations later that
day. Location 1RH-12 is downstream of ECCS injection valve MV-32065 at the Unit 1
B RHR train. Location 1RH-11 is a similar location at the Unit 1 A RHR train
downstream of ECCS injection valve MV-32064. These locations are isolated from
the shutdown cooling configuration by these valves, which are open during the ECCS
alignment.
The licensee captured the discovery of these voids in their CAP as AR 01465572 and
performed an ACE. One of the apparent causes was changes in nitrogen solubility.
Specifically, the RHR system introduced water with dissolved nitrogen during shutdown
cooling operations during the maintenance outages and a portion of this nitrogen came
out of solution due to system depressurization when secured for ECCS mode of
operation. The affected locations were system high points and were not verified to
be full of water before exiting the maintenance outages because the procedures
established to perform this verification were not applicable following maintenance
outages. The other apparent cause associated with this problem is discussed further in
Section 4OA2.1.c(5) of this IR. Because the time that the void exceeded the applicable
operability limit remained undetermined during this inspection period, the inspectors
were unable to verify if the licensee appropriately changed MODE during reactor unit
startup activities.
Procedure H64, Section 4.9, Gas Monitoring, stated that, The monitoring plan must
be developed to ensure the system meets the design limit and must ensure the system
is capable of performing its design function throughout the next monitoring interval.
It further stated that, The monitoring frequency for each location requiring periodic
monitoring should be documented in station procedures. It also stated that this
frequency should consider Probability of gas intrusion due to normal plant maneuvers
and equipment manipulation. However, the monitoring frequency for the affected
locations did not consider the system configuration and operational changes
experienced during maintenance outages that can lead to gas accumulation beyond
the system design and operability limits.
The licensees long term corrective actions included a revision of procedures
1/2C1.2-M4, Unit 1/2 Startup to MODE 4, to require gas accumulation inspections of
the affected gas susceptible locations as part of the unit startup activities following a
maintenance outage. In addition, the licensee performed a past operability evaluation
and reasonably determined that the RHR trains remained operable.
Analysis: The inspectors determined that failure to establish procedures to verify RHR is
operable with respect to gas accumulation following maintenance outages was contrary
to 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,
and was a performance deficiency. The performance deficiency was determined to be
more than minor because it was associated with the Mitigating Systems cornerstone
attribute of equipment performance and affected the cornerstone objective of ensuring
the availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences. Specifically, the failure to have procedures to
verify RHR is full of water following maintenance outages creates the potential for an
unacceptable void to go undetected affecting the availability and capability of this system
to perform the mitigating function.
13
The inspectors determined the finding could be evaluated using the SDP in accordance
with IMC 0609, SDP, Attachment 0609.04, Initial Characterization of Findings.
Because the finding impacted the Mitigating Systems cornerstone, the inspectors
screened the finding through IMC 0609, Appendix A, The SDP for Findings At-Power,
using Exhibit 2, Mitigating Systems Screening Questions. The finding screened as of
very low safety significance (Green) because it did not result in the loss of operability
or functionality of mitigating systems. Specifically, the licensee performed a past
operability review of the void found at 1RH-12 and reasonably concluded that the
system remained operable. The consequence of this void bounded all of the RHR
voids known during this inspection period for the last year.
The inspectors did not identify a cross-cutting aspect associated with this finding
because it was not confirmed to reflect current performance due to the age of the
performance deficiency. Specifically, the procedures associated with gas accumulation
management were developed as part of the GL 2008-01 effort which was completed
more than 3 years ago.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, requires, in part, that activities affecting quality be prescribed by
documented procedures of a type appropriate to the circumstances and be
accomplished in accordance with these procedures.
Contrary to the above, as of August 4, 2015, the licensee failed to have procedures
for verifying that RHR was operable as part of the unit startup activities following a
maintenance outage. Specifically, this system experience configuration and operational
changes during maintenance outages that can lead to gas accumulation beyond the
system design and operability limits. However, the procedures failed to verify that the
RHR was sufficiently full of water after RHR was aligned in its standby ECCS mode of
operation during startup activities following maintenance outages.
The licensee is still evaluating its planned corrective actions. However, the inspectors
determined that the continued non-compliance does not present an immediate safety
concern because the licensee vented the nitrogen that accumulated at locations 1RH-11
and 1RH-12.
Because this violation was of very low safety significance and was entered into the
licensees CAP as AR 014465572, this violation is being treated as a NCV, consistent
with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000282/2015008-03;
05000306/2015008-03, Failure to Establish Procedures to Verify RHR is Full of Water
Following Maintenance Outages)
(4) Failure to Manage Potential Gas Accumulation Due to Safety Injection Isolation Check
Valve Leakage Following Maintenance Outages
Introduction: The inspectors identified a finding of very low safety significance (Green),
and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control,
for the licensees failure to manage potential gas accumulation due to safety injection
isolation check valve leakage following maintenance outages. Specifically, the
GL 2008-01 design reviews did not evaluate the potential to accumulate nitrogen at
multiple RHR and safety injection gas susceptible locations due to safety injection check
valve unseating caused by maintenance outages. As a result, the station did not
manage this gas intrusion mechanism.
14
Description: On January 11, 2008, the NRC requested each GL 2008-01 addressee
to evaluate the ECCS, DHR, and CS systems licensing basis, design, testing, and
corrective actions to ensure that gas accumulation was maintained less than the amount
that would challenge the operability of these systems. One of the licensees original
actions to address these requests was to perform design reviews to identify gas
susceptible locations and their applicable gas intrusion mechanisms to manage gas
accumulation at these locations.
On February 24, 2011, the licensee identified that these design reviews were not
documented. Specifically, the licensee did not have quality records documenting
the evaluation of gas susceptible locations that determined which locations required
periodic monitoring. The licensee captured this issue in their CAP as AR 01272406.
This issue was documented as a licensee-identified NCV of 10 CFR Part 50,
Appendix B, Criterion XVII, Quality Assurance Records, in NRC IR 05000282/2011003;
IR 05000306/2011003, dated August 1, 2011. The licensee credited AR 01281652 to
resolve the concern captured in AR 01272406 and, ultimately, AR 01281652 credited a
corrective action assignment under AR 01271580 to resolve this concern. As a result,
on June 9, 2011, the licensee completed their evaluation and documentation of, in part,
specific gas intrusion mechanisms for each identified gas susceptible location.
One of the gas intrusion mechanisms evaluated by the licensee was the introduction of
nitrogen-rich water to the ECCS due to RCS leakage past the safety injection isolation
check valves and subsequent out-gassing due to the reduction of temperature and
pressure at the ECCS piping. This evaluation was consistent with the requirements of
GAMP procedure H64, Section 4.5.4. Specifically, it stated that, The station should
develop a process to evaluate all identified local high points, system high points and
other potential void locations to determine if gas accumulation could occur. It further
stated that. The potential sources of gas intrusion developed as a result of Section 4.1
of this document should be evaluated for applicability to identified high point locations.
Section 4.1 identified a number of gas intrusion mechanisms that included Leakage
form the RCS, Out-gassing of dissolved gas when gas saturated liquid passes from
piping at high pressure into piping at lower pressure, and Leakage through valves,
including leakage through a series of nominally closed valves. Because Section 4.1
of procedure H64 also stated that Potential void locations require further evaluation to
determine what level of monitoring is required, the licensee determined that the safety
injection isolation check valves required verification to ensure their disc were properly
seated following refueling outages to mitigate the possibility for leakage that could
introduce gas into the ECCS piping. As a result, the licensee only verified that these
check valves were seated following refueling outages.
However, during this inspection period, the inspectors noted that this evaluation failed
to consider the possibility of safety injection isolation check valve leakage due to disc
unseating following maintenance outages. As a result, the licensee was not managing
the potential to unseat these valves following maintenance outages which had the
potential to adversely affect gas susceptible locations 1RH-10, 1RH-11, 1RH-12,
1RH-29, 2RH-14, 2RH-17, 1SI-48, 1SI-49, 2SI-40, and 2SI-41 of the RHR and safety
injection systems. In addition, the failure to manage gas accumulation due to potential
safety injection isolation check valve leakage following maintenance outages contributed
to the introduction of a nitrogen void in location 1RH-12 of the Unit 1 B RHR train that
exceed the applicable operability limits. Specifically, this void, which was discovered on
February 10, 2015, was the result of two gas intrusion mechanisms and leakage through
15
the safety injection isolation check valves was one of the associated causes. The
details of this active gas intrusion incident and another licensee deficient performance
associated with this incident are discussed in Section 4OA2.1.c(5) of this IR. The
other cause and associated licensee deficient performance associated with the void
discovered on February 10, 2015, are discussed in Section 4OA2.1.c(3) of this IR.
The licensee captured the inspectors concerns in their CAP as AR01465572. As an
immediate corrective action, the licensee vented the nitrogen that accumulated at
location 1-RH-12. Additionally, the licensee seated the associated check valves,
performed an extent of condition, completed an ACE, and evaluated 1-RH-12 for past
operability. The licensee was in the process of implementing long term corrective
actions that included revising procedures H64 and 1/2C1.2-M4 to verify that the safety
injection check valves are seated as part of the unit startup activities following
maintenance outages.
Analysis: The inspectors determined that the failure to manage potential gas
accumulation due to safety injection check valve leakage following maintenance outages
was contrary to procedure H64 and was a performance deficiency. The performance
deficiency was determined to be more than minor because it was associated with the
Mitigating Systems cornerstone attribute of equipment performance, and affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. Specifically,
the failure to manage active gas intrusion mechanisms at RHR and safety injection
susceptible locations does not ensure the availability of these systems to perform their
mitigating functions. In addition, this failure resulted in the accumulation of gas at the
Unit 1 B train of RHR challenging its operability.
The inspectors determined the finding could be evaluated using the SDP in accordance
with IMC 0609, SDP, Attachment 0609.04, Initial Characterization of Findings.
Because the finding impacted the Mitigating Systems cornerstone, the inspectors
screened the finding through IMC 0609 Appendix A, The SDP for Findings At-Power,
using Exhibit 2, Mitigating Systems Screening Questions. The finding screened as of
very low safety significance (Green) because it did not result in the loss of operability
or functionality of mitigating systems. Specifically, the licensee performed a past
operability review of the void found at 1RH-12 and reasonably concluded that the
system remained operable. The consequence of this void bounded all of the voids
known at the affected locations during this inspection period for the last year.
The inspectors did not identify a cross-cutting aspect associated with this finding
because it was not confirmed to reflect current performance due to the age of the
performance deficiency. Specifically, the GL 2008-01 design reviews were completed
more than 3 years ago.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires,
in part, that the licensee 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 the above, on June 9, 2011, the licensee failed to verify the adequacy of the
RHR and safety injection design. Specifically, the design reviews failed to evaluate the
potential to accumulate nitrogen at multiple RHR and safety injection gas susceptible
16
locations (i.e., 1RH-10, 1RH-11, 1RH-12, 1RH-29, 2RH-14, 2RH-17, 1SI-48, 1SI-49,
2SI-40, and 2SI-41) due to safety injection check valve unseating caused by
maintenance outages.
The licensee is still evaluating its planned corrective actions. However, the inspectors
determined that the continued non-compliance does not present an immediate safety
concern because the licensee vented the nitrogen that accumulated at location 1-RH-12
and seated the associated check valves.
Because this violation was of very low safety significance and was entered into the
licensees CAP as AR 014465572, this violation is being treated as a NCV, consistent
with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000282/2015008-04;
05000306/2015008-04, Failure to Manage Potential Gas Accumulation Due to Safety
Injection Isolation Check Valve Leakage Following Maintenance Outages)
(5) Failure to Identify a Continuous Gas Intrusion into Residual Heat Removal
Introduction: The inspectors identified a finding of very low safety significance (Green),
and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective
Action, for the licensees failure to identify a continuous gas intrusion into RHR gas
susceptible location 1-RH-12, which was a CAQ, resulting in a continuous undetected
void growth that exceeded the applicable operability limits. Specifically, the licensee did
not consider applicable active gas intrusion mechanisms when evaluating the discovery
of a void at the RHR piping.
Description: On December 10, 2014, the licensee began a Unit 1 maintenance outage
associated with an RCP seal replacement. As part of the startup activities, the licensee
transitioned to MODE 4 and 3 on December 24 and 25, 2014, respectively. The TS
LCO 3.5.3 required one ECCS train to be operable in MODE 4 when both RCS cold leg
temperatures are greater than the safety injection pump disable temperature specified
in the PTLR. In addition, TS LCO 3.5.2 requires two ECCS trains to be operable in
MODES 1, 2, and 3. The licensee did not verify that the safety injection isolation check
valves were seated as part of the startup activities.
On January 26, 2015, the licensee began a second Unit 1 maintenance outage
associated with another RCP seal replacement. On February 9, 2015, the licensee
transitioned to MODEs 4 and 3. Again, the licensee did not verify that the safety
injection isolation check valves were seated as part of the startup activities.
On February 9, 2015, the licensee also began quarterly gas accumulation inspections
using procedure TP 1468 after transitioning to MODE 3 and were not part of the unit
startup readiness activities following the maintenance outage. On February 10, 2015,
the licensee discovered voids at RHR gas susceptible locations 1RH-12 and 1RH-11.
The 1RH-12 void size was 350 cubic inches, which exceeded the TP 1468 operability
limit of 22.85 cubic inches. The 1RH-11 void size was 62.21 cubic inches, which
exceeded the TP 1468 operability limit of 11.62 cubic inches. The licensee captured the
discovery of these voids in their CAP as AR 01465572 and declared both RHR trains
inoperable while in MODE 1. The licensee declared the system operable later that day
because the void sizes were reduced below their operability limits via venting.
17
However, the inspectors noted that these actions did not consider the known locations
susceptibility to active gas intrusion mechanisms. Specifically, Section 4.9.2 of GAMP
procedure H64 stated that, When an actual gas intrusion event has occurred or there
exists an increased possibility that gas intrusion may occur in a given location or system
the condition should be documented in the corrective action program. It also stated
that, The corrective actions should include additional monitoring. It explained that
Additional monitoring or increased monitoring frequencies should be established when
potential problems are observed, until the root cause of gas accumulation can be
identified and corrected. In addition, it stated that, A monitoring plan with specific
locations, techniques, and frequency should be employed to verify that any gas
accumulation resulting from the active gas intrusion mechanisms remains less than
the volume that challenges the ability of the system to perform its design function(s).
The inspectors were concerned because the affected gas susceptible locations were
vulnerable to active gas intrusion mechanisms and the licensee did not established an
increased monitoring frequency until the root cause of the gas accumulation was found
to verify the sytem remained capable of performing its safety function. Specifically, the
inspectors noted that location 1RH-12 is at the Unit 1 B RHR train downstream of
ECCS injection valve MV-32065 and upstream of the safety injection isolation check
valves SI-9-5 and SI-9-3. Location 1RH-11 is at a similar location at the Unit 1 A train
between MV-32064 and check valves SI-9-6 and SI-9-4. These check valves are in
series and isolate the ECCS from the RCS. In MODE 1, the RCS operates at a
significantly greater pressure and temperature than the ECCS. Thus, leakage of RCS
nitrogen rich water to ECCS may lead to nitrogen out-gassing or steam formation in the
ECCS piping. In addition, the inspectors considered other system interfaces as potential
gas sources.
As a result of the inspectors concerns, the licensee performed an additional inspection
on February 18, 2015. The associated 1RH-11 inspection results did not show evidence
of an active gas intrusion mechanism. However, the inspection discovered a void of
113.8 cubic inches at the 1RH-12 location confirming the existence of a continuous gas
intrusion incident due to an active gas intrusion mechanism. Consequently, the licensee
implemented venting at a periodicity that was based on growth rates. In addition, the
licensee declared the Unit 1 B train inoperable and decided to not declare it operable
until the continuous gas intrusion incident was under control. Following further
prompting from the inspectors, the licensee took chemistry samples of the vented gas
and measured pipe temperatures. The gas was 94 percent nitrogen. In addition, the
1RH-12 piping temperature was warmer than the similar location at the opposite RHR
train and had a temperature profile that was warmer in the vicinity of the check valves.
Thus, the licensee concluded that the check valves were leaking RCS water into location
1RH-12 causing nitrogen to come out of solution due to the lower system pressure.
On February 21, 2015, the licensee vented the piping porting in between the check
valves to properly seat their discs. On February 22, 2015, the licensee declared the
Unit 1 B RHR train operable after confirming that the 1RH-12 void size was below
operability limits and stable.
While the licensee corrected the discovery of a non-conforming void at 1RH-12, which
is a CAQ, on February 10, 2015, the licensee failed to identify the continuous gas
intrusion into this location, which was a second CAQ. The licensee captured the
additional concerns associated with the failed identification of the continuous gas
intrusion into 1RH-12 in their CAP as AR01465572 along with the other concerns
related with the voids discovered on February 10, 2015. These other concerns are
18
discussed in detailed in Sections 4OA2.1.c(3) and 4OA2.1.c(4) of this IR. In addition,
the licensee performed a past operability evaluation and reasonably determined that the
Analysis: The inspectors determined that the failure to identify a continuous gas
intrusion into 1-RH-12, a CAQ, was contrary to 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action, and was a performance deficiency. The performance
deficiency was determined to be more than minor because it was associated with the
Mitigating Systems cornerstone attribute of equipment performance and affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. Specifically, the
failure to identify a continuous gas intrusion at the Unit 1 B RHR piping resulted in a
void reintroduction of a size that exceeded the applicable operability limits.
The inspectors determined the finding could be evaluated using the SDP in accordance
with IMC 0609, SDP, Attachment 0609.04, Initial Characterization of Findings.
Because the finding impacted the Mitigating Systems cornerstone, the inspectors
screened the finding through IMC 0609 Appendix A, The SDP for Findings At-Power,
using Exhibit 2, Mitigating Systems Screening Questions. The finding screened as
of very low safety significance (Green) because it did not result in the loss of operability
or functionality of mitigating systems. Specifically, the licensee performed a past
operability review of the void found at 1RH-12 and reasonably concluded that the
system remained operable.
The inspectors determined that this finding had a cross-cutting aspect in the area of
human performance because the licensee did not recognize and plan for the possibility
of mistakes when evaluating the gas surveillance results of February 10, 2015.
Specifically, the licensee did not plan for the possibility that the unacceptable results
were indicative of a different problem than originally determined or a combination of
problems. As a result, the licensee failed to identify the continuous gas intrusion
incident. [H.12]
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action,
requires, in part, that CAQs, such as failures, malfunctions, deficiencies, deviations,
defective material and equipment, and non-conformances are promptly identified.
Contrary to the above, from February 10, 2015, to February 21, 2015, the licensee failed
to identify a CAQ. Specifically, the licensee failed to identify a continuous gas intrusion
incident, a CAQ, at RHR gas susceptible location 1RH-12 resulting in a continuous
undetected void growth that exceeded the applicable design limits. The licensee had
sufficient information to identify this CAQ because the GAMP procedure contained
sufficient guidance to determine the source of this void.
The licensee is still evaluating its planned corrective actions. However, the inspectors
determined that the continued non-compliance does not present an immediate safety
concern because the licensee vented the nitrogen that accumulated at location 1RH-12
and seated the associated check valves.
Because this violation was of very low safety significance and was entered into the
licensees CAP as AR 014465572, this violation is being treated as a NCV, consistent
with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000282/2015008-05;
05000306/2015008-05, Failure to Identify a Continuous Gas Intrusion into RHR)
19
4OA6 Meetings
.1 Exit Meeting Summary
On November 24, 2015, the inspectors presented the inspection results to
Mr. S. Northam, and other members of the licensee staff. The licensee acknowledged
the issues presented. The inspectors asked the licensee whether any materials
examined during the inspection should be considered proprietary. Several documents
reviewed by the inspectors were considered proprietary information and were either
returned to the licensee or handled in accordance with NRC policy on proprietary
information.
4OA7 Licensee-Identified Violations
The following violation of very low significance (Green) was identified by the licensee
and is a violation of NRC requirements, which meet the criteria of the NRC Enforcement
Policy for being dispositioned as an NCV.
- Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part,
that the licensee 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 the above, as of November 24, 2015, the licensee failed to verify
the adequacy of the ECCS vent designs. Specifically, the licensee did not verify
that the ECCS vent designs were adequate. As a result, some vents were
inadequate to remove gas that accumulated in excess of the applicable design
limits. The licensee captured their concern in their CAP as AR 01482500 and
AR 01465114, and initiated actions to add and/or modify the vents.
The inspectors determined the finding could be evaluated using the SDP in
accordance with IMC 0609, SDP, Attachment 0609.04, Initial Characterization
of Findings. Because the finding impacted the Mitigating Systems cornerstone,
the inspectors screened the finding through IMC 0609 Appendix A, The SDP for
Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions.
The finding screened as of very low safety significance (Green) because it did
not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee evaluated the voids that could not be vented and
reasonably determined they did not result in loss of operability.
ATTACHMENT: SUPPLEMENTAL INFORMATION
20
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
S. Northam, Vice President of Fleet Operations
K. Davison, Site Vice President
E. Blondin, Engineering Director
S. Martin, Performance Assessment Manager
M. Pearson, Regulatory Affairs Manager
J. Connors, Engineering Supervisor
U.S. Nuclear Regulatory Commission
K. Riemer, Chief, Reactor Projects Branch 2
C. Lipa, Chief, Engineering Branch 2
N. Féliz Adorno, Senior Reactor Inspector, Engineering Branch 2
T. Beltz, Project Mananger, Office of Nuclear Reactor Regulation
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened and Closed
05000306/2015008-01 VIO Failure to Correct an NCV Associated with Inadequate Gas
Monitoring of Inaccessible RHR Gas Susceptible Locations
(Section 4OA2.1.c(1))05000282/2015008-02; NCV Failure to Manage Gas Accumulation at the RHR Train
05000306/2015008-02 Credited for Emergency Core Cooling in MODE 4
(Section 4OA2.1.c(2))05000282/2015008-03; NCV Failure to Establish Procedures to Verify RHR is Full of Water
05000306/2015008-03 Following Maintenance Outages (Section 4OA2.1.c(3))05000282/2015008-04; NCV Failure to Manage Potential Gas Accumulation Due to SI
05000306/2015008-04 Isolation Check Valve Leakage Following Maintenance
Outages (Section 4OA2.1.c(4))05000282/2015008-05 NCV Failure to Identify a Continuous Gas Intrusion into RHR
05000306/2015008-05 (Section 4OA2.1.c(5))
Discussed
None
Attachemnt
LIST OF DOCUMENTS REVIEWED
The following is a partial list of documents reviewed during the inspection. Inclusion on this list
does not imply that the NRC inspector reviewed the documents in their entirety, but rather that
selected sections or portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
- H64; Gas Accumulation Management Program; Rev. 2B
- H64; Gas Accumulation Management Program; Rev. 2
- TP 1468; Unit 1 GL-08-01 Inspections; Rev. 6
- 1M-RH-TRN A; ECCS Train A: Isolate, Drain, Fill and Vent; Rev. 7
- 1C1.2-M4; Unit 1 Startup to MODE 4; Rev. 2
- 1C1.2-M4; Unit 1 Startup to MODE 4; Rev. 1
- SP 1466; Dynamic Flush of RHR System (GL 2008-01); Rev. 2
- Calc. 32-9236122; Operability Evaluation for Void Found at Location 1RH-11 in the PINGP
Unit 1 RHR System; Rev. 0
- Calc. 32-9237388; U1 RHR System Operability Evaluation for Void 1RH-11; Rev. 0
- Calc. 32-9241892; Operability Evaluation for Void Found at Location 1RH-12 in the PINGP
Unit 1 RHR System; Rev. 0
- NOS Observation Report 2013-03-006; Engineering Programs and Inservice Testing;
dated 09/25/13
- AR01291233; GL 08-01: Void Identified at Susceptible Location 1RH-21; dated 06/20/11
- AR01391787; Misuse of CAP Hinders Fix of GL 08-01 NRC Finding 2011003-09;
dated 07/29/13
- AR01391784; Misuse of CAPAs within the CAP Hinders GL 08-01 Fix; dated 07/29/13
- AR01464866; Void Identified During GL 08-01 Examination; dated 02/04/15
- AR01465572; Voids Identified in RH Piping; dated 02/10/15
- AR01465659; NRC Question: RHR Pump Availability Given Void Inoperability; dated 02/20/15
- AR01466757; Voids Identified in RH Piping at Location 1RH-12; dated 02/18/15
- AR01466999; Void Identified in RH Piping at Location 1RH-12; dated 02/19/15
- AR01467032; Elevated Temperature was Noted on Line 6-SI-25D; dated 02/20/15
- AR01482226; GAMP: Void Identified at Location 2RH-26 and 2RH-09; dated 06/08/15
- AR01482500; GAMP: Void Identified at Location 1RH-04 and 1RH-27; dated 06/10/15
- AR01484195; GAMP: Answer NRC Void Question for 2RH-09 and 2RH-26; dated 06/25/15
- AR01484157; GAMP: Void Identified at Location 2RH-09 and 2RH-26; dated 06/25/15
- AR01488704; GAMP: Acceptable Void Identified During TP 2468 Performance; dated 08/05/15
- AR01466967; Operations Needs to Evaluate Alternate RHR Venting Method; dated 02/19/15
- AR01281658; TI-177 GL08-01 Reviews Did Not Identify Susceptible Locations; dated 04/20/11
- AR01281682; TI-177 - Need Methods to Evaluate Inaccessible Locations; dated 04/20/11
- AR01271826; GL-08-01 TI-177 NRC Inspection Prep - H64 Gap Analysis; dated 02/21/11
- AR01281652; TI177 Results of Susceptible Location Reviews Not Documented; dated 04/20/11
- AR01271024; GL-08-01 TI-177 NRC Inspection Prep - H64 Gap Analysis; dated 02/15/11
- AR01456527; GL-08-01 Inspection Identified Void in Piping; dated 11/18/14
- AR01493599; GAMP: Acceptable Void Identified at 1RH-20; dated 09/17/15
- WO00514236; TP 2468 Unit 2 GL-08-01 Inspections; date 08/27/15
- WO00524641; Perform UT Inspection for GL 08-01 TP 2468; dated 07/09/15
- WO00513378; TP 1468 - Unit 1 GL-08-01 Inspections; dated 02/10/15
2
Corrective Action Documents Generated as a Result of the Inspection
- AR01497409; ECCS Fill and Vent Completed Procedures Not Retained; dated 10/19/15
- AR01498131; Record Pressure/Gas Property for Large Voids Founds; dated 10/22/15
- AR01496469; ACE 01281652 Corrective Actions Were Completed in C Level CAPs;
dated 10/12/15
- AR01497119; Analysis 32-9242120 Missed an Item for Additional Review; dated 10/16/15
- AR01496254; GAMP: H64 Wording Not Clear for Void Checks during Startup; dated 10/09/15
- AR01496191; GAMP: Corrective Action Implementation Was Inconsistent; dated 10/09/15
- AR01495447; GAMP: Vendor Product (EC22242) Does Not List All Susceptible; dated 10/2/15
- AR01495724; GAMP: Typing Error Found in TP 1468; dated 10/05/15
- AR01495444; GAMP: Alternate Testing Method Used but Not Well Documented; dated 10/02/15
- AR01498169; GAMP: Legacy - Ineffective Corrective Action from 2011 CAP 01271826;
dated 10/22/15
3
LIST OF ACRONYMS USED
ACE Apparent Cause Evaluation
ADAMS Agencywide Document Access Management System
AR Action Request
CAP Corrective Action Program
CAQ Condition of Adverse Quality
CE Condition Evaluation
CFR Code of Federal Regulations
DRP Division of Reactor Projects
ECCS Emergency Core Cooling System
GAMP Gas Accumulation Management Program
GL Generic Letter
IMC Inspection Manual Chapter
IP Inspection Procedure
IR Inspection Report
LCO Limiting Condition for Operation
NCV Non-Cited Violation
NRC U.S. Nuclear Regulatory Commission
PARS Publicly Available Records System
PTLR Pressure and Temperature Limits Report
RCP Reactor Coolant Pump
SDP Significance Determination Process
TS Technical Specification
4
K. Davision -2-
If you contest the subject or severity of any 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 III; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC
20555-0001; and the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant.
In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 III, and the NRC Resident Inspector at Prairie Island
Nuclear Generating Plant.
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections,
Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) will be available electronically for public inspection in the 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/
Christine A. Lipa, Chief
Engineering Branch 2
Division of Reactor Safety
Docket Nos. 50-282, 50-306
Enclosure:
IR 05000282/2015008; 05000306/2015008
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