ML17013A233
| ML17013A233 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 01/17/2017 |
| From: | Eugene Dipaolo Reactor Projects Branch 2 |
| To: | Vitale A Entergy Nuclear Operations |
| DiPaolo E | |
| References | |
| EA-16-193 IR 2016003 | |
| Download: ML17013A233 (55) | |
See also: IR 05000247/2016003
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BLVD., SUITE 100
KING OF PRUSSIA, PA 19406-2713
January 17, 2017
Mr. Anthony Vitale
Site Vice President
Entergy Nuclear Operations, Inc.
Indian Point Energy Center
450 Broadway, GSB
P.O. Box 249
Buchanan, NY 10511-0249
SUBJECT: INDIAN POINT NUCLEAR GENERATING - INTEGRATED INSPECTION
REPORT 05000247/2016003 AND 05000286/2016003 AND NOTICE OF
VIOLATION (EA-16-193)
Dear Mr. Vitale:
On September 30, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at Indian Point Nuclear Generating (Indian Point), Units 2 and 3. On October 26,
2016, the NRC inspectors discussed the results of this inspection with you and other members
of your staff. The results of this inspection are documented in the enclosed report.
The NRC inspectors documented seven findings of very low safety significance (Green) in this
report. Six of these findings involved violations of NRC requirements. For five of these findings,
the NRC is treating the associated violations as non-cited violations (NCVs) consistent with
Section 2.3.2.a of the Enforcement Policy. 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 Nuclear Regulatory Commission, ATTN: Document Control
Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the
Director, Office of Enforcement; and the NRC Resident Inspector at Indian Point. In addition, 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 U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk,
Washington, DC, 20555-0001; with copies to the Regional Administrator, Region I, and the NRC
Resident Inspector at Indian Point.
One violation associated with a finding of very low safety significance (Green) is cited in the
enclosed Notice of Violation (Notice), and the circumstances surrounding it are described in the
enclosed inspection report. The violation describes two examples of Entergys failure to conduct
operations to minimize the introduction of residual radioactivity into the subsurface
(groundwater) of the site. The violation is similar to two NCVs previously identified by the NRC
involving groundwater contamination events in 2014 and 2015 (NRC Inspection
Reports 05000247/2015002 and 05000247/2015003). Corrective actions for these NCVs were
insufficiently broad to address Entergys ineffective floor drain and radioactive liquid draining
operational controls, resulting in Entergys continued failure to minimize groundwater
contamination occurrences. The NRC evaluated this violation in accordance with the NRC
A. Vitale 2
Enforcement Policy. The current Enforcement Policy is available for review on the NRCs Web
site at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. This violation
meets the criteria in Section 2.3.2.a of the Enforcement Policy to be dispositioned as an NCV.
However, the NRC is citing the violation in the enclosed Notice because Entergys actions for
these most recent events do not adequately address the broader concern regarding a lack of
control and management of the site floor drain system. Accordingly, the NRC is issuing the
Notice and requiring a response from Entergy, as described below.
You are required to respond to this letter and should follow the instructions specified in the
enclosed Notice when preparing your response. In your response, describe a comprehensive
corrective action plan for maintaining an effective floor drain system and a process for
evaluating and using the floor drains to handle the volume and flowrates for draining activities
being conducted. 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 will
determine whether further enforcement action is necessary to ensure your compliance with
regulatory requirements.
This letter, its enclosures, and your response (if any) will be made available for public inspection
and copying at http://www.nrc.gov/reading-rm/adams.html and the NRC Public Document Room
in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.
To the extent possible, your response should not include any personal privacy or proprietary
information so that it can be made available to the Public without redaction.
Sincerely,
/RA/
Eugene M. DiPaolo, Acting Chief
Reactor Projects Branch 2
Division of Reactor Projects
Docket Nos. 50-247 and 50-286
License Nos. DPR-26 and DPR-64
Enclosures:
1. Notice of Violation
2. Inspection Report 05000247/2016003
and 05000286/2016003 w/Attachment:
Supplementary Information
cc w/encl: Distribution via ListServ
A. Vitale 3
Letter to Mr. Anthony J. Vitale from Eugene M. DiPaolo dated January 17, 2017
SUBJECT: INDIAN POINT NUCLEAR GENERATING - INTEGRATED INSPECTION
REPORT 05000247/2016003 AND 05000286/2016003 AND NOTICE OF
VIOLATION (EA-16-193)
DISTRIBUTION: (via e-mail)
DDorman, RA
DLew, DRA
MScott, DRP
DPelton, DRP
RLorson, DRS
JYerokun, DRS
EDiPaolo, DRP
TSetzer, DRP
JSchussler, DRP
SRich, DRP, RI
CSafouri, DRP, RI
JBowen, RI OEDO
RidsNrrPMIndianPoint Resource
RidsNrrDorlLpl1-1 Resource
ROPReports Resources
DOCUMENT NAME: G:\DRP\BRANCH2\A - INDIAN POINT\IP2&3 INSPECTION REPORTS\2016\2016-003\IP2&3 2016.003.FINAL.DOCX
ADAMS Accession Number: ML17013A233
SUNSI Review
Non-Sensitive Publicly Available
Sensitive Non-Publicly Available
OFFICE RI/DRP RI/DRP RI/DRP RI/ORA RI/DRS RI/DRP
SRich non- BHaagensen via
NAME TSetzer BBickett/MMM for GDentel EDiPaolo
concur via telcon email
DATE 1/12/17 1/11/17 1/12/17 1/13/17 1/12/17 1/12/17
OFFICIAL RECORD COPY
1
NOTICE OF VIOLATION
Entergy Nuclear Operations, Inc. Docket No. 50-247
Indian Point Nuclear Generating Unit 2 License No. DPR-26
During an NRC inspection conducted between July 1 and September 23, 2016, a violation of NRC
requirements was identified. In accordance with the NRC Enforcement Policy, the violation is listed
below:
Title 10 of the Code of Federal Regulations (10 CFR) 20.1406(c) requires, in part, that
licensees shall, to the extent practical, conduct operations to minimize the introduction of
residual radioactivity into the site, including the subsurface.
Contrary to the above, on two occasions between January 2016 and July 2016, Entergy
failed to conduct operations to minimize the introduction of residual radioactivity into the
subsurface of the site. Specifically, Entergy has not maintained its floor drain system clear of
obstructions and interferences, and has not verified the ability of the floor drains to handle
the volume and flowrates for draining activities being conducted. As a result, repeated spills
of contaminated water within the radiologically controlled area leaked into the groundwater
(subsurface of the site). Specifically, in January 2016, a spill caused by floor drain
obstructions resulted in the backup of contaminated water onto the floor and subsequent
leakage to the subsurface of the site. Similarly, a subsequent June/July 2016 groundwater
contamination event occurred due to an obstructed flow path through a floor drain in the
Unit 2 spent fuel building, which spilled to the subfloor and contaminated the subsurface of
the site.
This violation is associated with a Green Significance Determination Process finding.
Pursuant to the provisions of 10 CFR 2.201, Entergy 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 I, and a copy
to the NRC Resident Inspector at Indian Point, 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-16-193" 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) a description of a more comprehensive corrective action plan for maintaining
an effective floor drain system and a process for evaluating and using the floor drains to handle the
volume and flowrates for draining activities being conducted that will be taken to address the
repeated problems with maintaining and controlling the floor drain systems, 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.
Enclosure 1
2
Because your response will be made available electronically for public inspection in the NRC Public
Document Room or from the NRCs Agencywide Documents Access and Management System
(ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the
extent possible, it should not include any personal privacy, 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 (i.e., 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 17th day of January, 2017.
1
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos. 50-247 and 50-286
License Nos. DPR-26 and DPR-64
Report Nos. 05000247/2016003 and 05000286/2016003
Licensee: Entergy Nuclear Northeast (Entergy)
Facility: Indian Point Nuclear Generating Units 2 and 3
Location: 450 Broadway, GSB
Buchanan, NY 10511-0249
Dates: July 1, 2016, through September 30, 2016
Inspectors: B. Haagensen, Senior Resident Inspector
G. Newman, Resident Inspector
S. Rich, Resident Inspector
J. Ambrosini, Senior Resident Inspector, Millstone
F. Arner, Senior Reactor Analyst
S. Elkhiamy, Project Engineer
J. Furia, Senior Health Physicist
Approved By: Eugene M. DiPaolo, Acting Chief
Reactor Projects Branch 2
Division of Reactor Projects
Enclosure 2
2
TABLE OF CONTENTS
SUMMARY .................................................................................................................................... 3
REPORT DETAILS ....................................................................................................................... 8
1. REACTOR SAFETY .............................................................................................................. 8
1R01 Adverse Weather Protection ....................................................................................... 8
1R04 Equipment Alignment .................................................................................................. 9
1R05 Fire Protection ........................................................................................................... 10
1R11 Licensed Operator Requalification Program ............................................................. 11
1R12 Maintenance Effectiveness ....................................................................................... 13
1R13 Maintenance Risk Assessments and Emergent Work Control .................................. 14
1R15 Operability Determinations and Functionality Assessments ..................................... 16
1R18 Plant Modifications .................................................................................................... 21
1R19 Post-Maintenance Testing ........................................................................................ 22
1R22 Surveillance Testing .................................................................................................. 23
1EP6 Drill Evaluation .......................................................................................................... 25
2. RADIATION SAFETY .......................................................................................................... 25
2RS1 Radiological Hazard Assessment and Exposure Controls ........................................ 25
2RS2 Occupational ALARA Planning and Controls ............................................................ 28
2RS4 Occupational Dose Assessment ............................................................................... 30
4. OTHER ACTIVITIES ............................................................................................................ 31
4OA1 Performance Indicator Verification ............................................................................ 31
4OA2 Problem Identification and Resolution ....................................................................... 32
4OA3 Follow Up of Events and Notices of Enforcement Discretion .................................... 32
4OA5 Other Activities .......................................................................................................... 35
4OA6 Meetings, Including Exit ............................................................................................ 41
SUPPLEMENTARY INFORMATION ........................................................................................ A-1
KEY POINTS OF CONTACT .................................................................................................... A-1
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED ..................................... A-2
LIST OF DOCUMENTS REVIEWED ........................................................................................ A-3
LIST OF ACRONYMS ............................................................................................................... A-9
3
SUMMARY
Inspection Report 05000247/2016003 and 05000286/2016003; 07/01/2016 - 09/30/2016; Indian
Point Nuclear Generating (Indian Point), Units 2 and 3; Maintenance Risk Assessments and
Emergent Work Control, Operability Determinations and Functionality Assessments,
Surveillance Testing, Radiological Hazard Assessment and Exposure Controls, Occupational As
Low as Reasonably Achievable (ALARA) Planning and Controls, Follow Up of Events and
Notices of Enforcement Discretion, and Other Activities.
This report covered a three-month period of inspection by resident inspectors and announced
inspections performed by regional inspectors. The inspectors identified seven findings of very
low safety significance (Green), including one Notice of Violation (NOV), five non-cited violations
(NCVs), and one finding (FIN). The significance of most 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 U.S. Nuclear Regulatory Commission (NRC) requirements
are dispositioned in accordance with the NRCs Enforcement Policy, dated August 1, 2016. The
NRCs program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, Reactor Oversight Process, Revision 6.
Cornerstone: Mitigating Systems
Green. The inspectors identified a Green NCV of Title 10 of the Code of Federal
Regulations (10 CFR) 50.65(a)(4) because between August 1, 2016, and August 17, 2016,
Entergy did not perform an adequate risk assessment for the maintenance on the Unit 3
Appendix R diesel generator (ARDG). As a result, they did not take the required risk
mitigating actions (RMAs). Entergy wrote Condition Report (CR)-IP3-2016-2538, changed
fire risk status to Yellow, and began implementing RMAs on August 17, 2016.
The inspectors determined that this performance deficiency was more than minor because
it is associated with the Protection Against External Factors attribute of the Mitigating
Systems cornerstone and adversely affected its objective to ensure the reliability of
systems that respond to initiating events to prevent undesirable consequences.
Specifically, due to the inadequate risk assessment, Entergy did not perform shiftly
walkdowns for transient combustibles and related fire and ignition sources on the available
safe shutdown train. Using IMC 0609.04, Initial Characterization of Findings, and IMC
0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance
Determination Process, the inspectors determined that the failure to conduct RMAs for the
unavailability of the ARDG required further assessment. A Region I senior reactor analyst
(SRA) used SAPHIRE, Revision 8.1.14, and the Indian Point Unit 3 Standardized Plant
Analysis Risk (SPAR) Model, Revision 8.20, to complete an evaluation this performance
deficiency. The incremental conditional core damage probability (ICCDP) for this finding
was calculated to be less than 1E-7 or very low safety significance (Green). This finding
has a cross-cutting aspect in the area of Problem Identification and Resolution,
Identification, because Entergy did not identify that an improperly racked-in breaker had a
fire risk impact when combined with other plant conditions. [P.1 - Problem Identification
and Resolution, Identification] (Section 1R13)
Green. The inspectors identified a self-revealing Green NCV of 10 CFR 50, Appendix B,
Criterion XVI, Corrective Actions, because between 2012 and 2016, Entergy did not
4
perform vendor specified inspections of the 23 emergency diesel generator (EDG)
automatic voltage regulator (AVR) cards. As a result, on March 7, 2016, and March 10,
2016, the 23 EDG failed to run due to poor voltage regulation caused by degraded
connections on the AVR card. Entergy replaced the AVR card in the 23 EDG, repaired
similarly degraded solder joints on the AVR cards for the 21 and 22 EDGs, and wrote
CR-IP2-2016-1260 and CR-IP3-2016-1370.
The inspectors determined that this performance deficiency was more than minor because
it is associated with the Equipment Performance attribute of the Mitigating Systems
cornerstone and adversely affected its objective to ensure the reliability of systems that
respond to initiating events to prevent undesirable consequences. Specifically, the 23 EDG
failed to run on March 7, 2016, and March 10, 2016. The inspectors evaluated the finding
in accordance with IMC 0609, Appendix A and concluded it required a detailed risk
evaluation (DRE). The DRE was performed by a Region I SRA and concluded the
performance deficiency resulted in a change in core damage frequency of low E-8/year or
very low safety significance (Green). The inspectors determined that this violation was not
indicative of current performance because the last time Entergy would reasonably have
been prompted to create corrective actions to perform periodic inspections was during the
initial inspections in 2010. Therefore, no cross-cutting aspect was assigned.
(Section 1R15)
Green. The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion XVI,
Corrective Actions, because Entergy did not take timely corrective action to perform an
inspection of the 33 EDG AVR card. As a result, the degraded solder connections on the
card were not repaired for an excessive period of time. Entergy repaired the solder joints
on the AVR card in the 33 EDG and wrote CR-IP3-2016-3018.
This performance deficiency was more than minor because it is associated with the
Equipment Performance attribute of the Mitigating Systems cornerstone and adversely
affected its objective to ensure the reliability of systems that respond to initiating events to
prevent undesirable consequences. The existence of degraded solder joints on the AVR
card decreases the reliability of the EDG, and the untimely corrective action allowed the
degradation to exist for longer than necessary without being corrected. In accordance with
IMC 0609, Appendix A, The Significance Determination Process for Findings at Power,
the inspectors determined that the finding was of very low safety significance (Green)
because the 33 EDG maintained its operability or functionality, it did not represent a loss of
system or function, and it did not involve external mitigation systems. The inspectors
determined that this finding had a cross-cutting aspect in the area of Human Performance,
Conservative Bias, because leaders did not take a conservative approach to decision
making, particularly when information is incomplete or conditions are unusual. Specifically,
Entergy did not inspect the 33 EDG AVR cards at the first available opportunity due to
resource constraints. [H.14 - Human Performance, Conservative Bias] (Section 1R22)
Green. The inspectors identified a self-revealing Green NCV for failing to comply with
Technical Specification (TS) Limiting Condition of Operation (LCO) 3.8.1, Electrical Power
Systems, Alternating Current (AC) Sources - Operating, from February 26, 2014, to
March 29, 2016. Specifically, Entergy failed to maintain the auto transfer function for the 6.9
kilovolt (kV) offsite electrical buses in an operable condition because the safety injection (SI)
anticipatory signal to the station auxiliary transformer (SAT) load tap changer (LTC) was
disconnected. As a result, one of two qualified offsite AC circuits was not operable. Entergy
5
initiated corrective actions and promptly restored the SAT LTC SI signal to operation prior to
restarting the plant from the refueling outage.
The failure to restore the LTC SAT SI signal following maintenance activities was a
performance deficiency that was more than minor because it is associated with the
Equipment Performance attribute of the Mitigating Systems cornerstone and adversely
affected the cornerstone objective to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences (i.e., core
damage). Specifically, the failure to reinstate the SAT LTC SI anticipatory signal following
maintenance resulted in the qualified offsite source of AC power becoming inoperable for a
period of time in excess of the TS allowable outage time. In accordance with IMC 0609,
Appendix A, The Significance Determination Process for Findings at Power, the inspectors
determined that the finding was of very low safety significance (Green) because a detailed
risk analysis determined the likelihood of core damage was less than E-8/year. The
inspectors determined that the finding had a cross-cutting aspect of Human Performance,
Work Management, because Entergy did not implement a process of controlling and
executing work activities. The work process did not coordinate with different groups or job
activities to ensure the state links were restored at the end of the work activities.
[H.5 - Human Performance, Work Management] (Section 4OA3)
Cornerstone: Occupational/Public Radiation Safety
Green. The inspectors identified a self-revealing NCV of TS 5.7.1e when workers entered
the Unit 2 Fuel Storage Building (FSB) truck bay that was posted and controlled as a high
radiation area (HRA) without receiving a briefing on the dose rates prior to entering the
HRA. Specifically, on June 6, 2016, two nuclear plant operators (NPOs) entered the Unit 2
FSB truck bay to hang tags on the backup spent fuel pool cooling filters. The NPOs signed
in on a HRA radiation work permit (RWP) but did not receive a briefing on the radiological
conditions in this work area. After entering the HRA, one worker received an electronic
dosimeter dose rate alarm; and subsequently, both workers promptly exited the area.
Immediate corrective actions included restricting the access of the two NPOs to the
radiologically controlled area (RCA). The issue was entered into Entergys corrective action
program (CAP) as CR-IP2-2016-03610.
The failure to adhere to a radiological briefing prior to entry into a HRA is a performance
deficiency that was reasonably within Entergys ability to foresee and correct. The
performance deficiency was determined to be more than minor based on similar example
6.h in IMC 0612, Appendix E, Examples of Minor Issues, and because it adversely affected
the Human Performance attribute of the Occupational Radiation Safety cornerstone
objective. Specifically, Entergy violated the TS 5.7.1e HRA radiological briefing
requirements designed to protect workers from unnecessary radiation exposure. Using IMC
0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the
finding was determined to be of very low safety significance (Green) because it did not
involve: (1) ALARA occupational collective exposure planning and controls, (2) an
overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to
assess dose. The inspectors determined that the finding had a cross-cutting aspect of
Human Performance, Procedure Adherence, in that the workers did not follow processes,
procedures, and work instructions for entering a posted HRA. [H.8 - Human Performance,
Procedure Adherence] (Section 2RS1)
6
Green. The inspectors identified a self-revealing finding (FIN) of very low safety significance
due to Entergy having unintended occupational collective exposure resulting from
performance deficiencies in work planning while preparing to perform reactor cavity liner
repair activities during the spring 2016 Unit 2 refueling outage. Inadequate work planning
that included an incomplete scope of work, welding method qualification, and inadequate
timing of shield placement resulted in unplanned, unintended collective exposure due to
conditions that were reasonably within Entergys ability to foresee. The work activity
planning deficiencies resulted in the collective exposure for these activities increasing from
the planned dose of 2.386 person-rem to an actual dose of 10.305 person-rem. This issue
was entered into Entergys CAP as CR-IP2-2016-02528, CR-IP2-2016-02502, and CR-IP2-
2016-02548.
The performance deficiency was more than minor because it was associated with the
Program and Process attribute of the Occupational Radiation Safety cornerstone and
adversely affected the cornerstone objective to ensure the adequate protection of the worker
health and safety from exposure to radiation. Additionally, the performance deficiency was
more than minor based on similar example 6.i in Appendix E of IMC 0612, Examples of
Minor Issues, in that the actual collective dose exceeded 5 person-rem and exceeded the
planned, intended dose by more than 50 percent. In accordance with IMC 0609, Appendix
C, "Occupational Radiation Safety Significance Determination Process," the finding was
determined to be of very low safety significance (Green) because Entergy had an issue
involving ALARA Planning, and Unit 2's current three-year rolling average collective dose is
less than the significance determination process criterion of 135 person-rem per pressurized
water reactor unit. The finding had a cross-cutting aspect in the area of Human
Performance, Work Management, in that the lack of accurate planning for work activities
adversely impacted radiological safety. [H-5 - Human Performance, Work Management]
(Section 2RS2)
Green. The inspectors identified an NOV of 10 CFR 20.1406(c), Minimization of
Contamination, for Entergys failure to conduct operations to minimize the introduction of
residual radioactivity into the subsurface of the site (groundwater). Specifically, Entergy did
not maintain the floor drain systems clear of obstructions and interferences and did not
verify the ability of the floor drains to handle the volume and flowrates for draining activities
being conducted. In January 2016, a spill caused by multiple floor drain obstructions
resulted in the backup of contaminated water onto the floor of the 35-foot elevation of the
primary auxiliary building (PAB) and the subfloor of the FSB and subsequent leakage to
onsite groundwater. Entergy entered this issue into their CAP as CR-IP2-2016-00264, CR-
IP2-2016-00266, and CR-IP2-2016-00564 with actions to characterize and evaluate the
leak. Similarly, in June/July 2016, another event occurred due to an obstructed flow path
through a floor drain in the FSB, which spilled to the subfloor and contaminated the onsite
groundwater. This event was documented by Entergy in CR-IP2-2016-05060.
The issue is more than minor because it is associated with the Program and Process
attribute of the Public Radiation Safety cornerstone and adversely affected the cornerstone
objective to ensure Entergys ability to prevent inadvertent release and/or loss of control of
licensed material to an unrestricted area. In accordance with IMC 0609, Appendix D,
"Public Radiation Safety Significance Determination Process," the finding was determined to
be of very low safety significance (Green) because Entergy had an issue involving
radioactive material control but did not involve transportation or public exposure in excess of
0.005 Rem. The finding had a cross-cutting aspect in the area of Problem Identification and
Resolution, Resolution, in that effective corrective actions to address issues identified in two
7
prior groundwater contamination events since 2014 were not implemented in a timely or
effective manner, which could have prevented two additional groundwater contamination
events that occurred in 2016. [P.3 - Problem Identification and Resolution, Resolution]
(Section 4OA5)
8
REPORT DETAILS
Summary of Plant Status
Unit 2 began the inspection period at 100 percent power. On July 6, 2016, Unit 2 experienced a
reactor trip caused by a human performance error. Operators returned Unit 2 to 100 percent
power on July 8, 2016. On August 6, 2016, Unit 2 reduced power to 80 percent due to a trip of
both heater drain pumps. They restarted the pumps and returned to 100 percent power the
following day. Unit 2 remained at or near 100 percent power for the remainder of the inspection
period.
Unit 3 operated at 100 percent power during the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01 - 3 samples)
.1 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors performed a review of Entergys readiness for the onset of seasonal high
temperatures. The inspectors reviewed procedure OAP-048, Seasonal Weather
Preparation (Units 2 and 3). The focus areas were the switchgear rooms and service
water (SW) pump areas. The inspectors reviewed the updated final safety analysis
report (UFSAR), TSs, control room logs, and the CAP to determine what temperatures
or other seasonal weather could challenge these systems and to ensure Entergy had
adequately prepared for these challenges. The inspectors reviewed station procedures,
including Entergys seasonal weather preparation procedure and applicable operating
procedures. The inspectors performed walkdowns of the selected systems to ensure
station personnel identified issues that could challenge the operability of the systems
during hot weather conditions. Documents reviewed for each section of this inspection
are listed in the Attachment.
b. Findings
No findings were identified.
.2 Summer Readiness of Offsite and AC Power Systems
a. Inspection Scope
The inspectors performed a review of plant features and procedures for the operation
and continued availability of the offsite and alternate AC power system to evaluate
readiness of the systems prior to seasonal high grid loading. The inspectors reviewed
Entergys procedures affecting these areas and the communications protocols between
the transmission system operator and Entergy. This review focused on the material
condition of the offsite and alternate AC power equipment. There were no changes to
the established program since the last inspection. The inspectors assessed whether
9
Entergy established and implemented appropriate procedures and protocols to monitor
and maintain availability and reliability of both the offsite AC power system and the
onsite alternate AC power system. The inspectors evaluated the material condition of the
associated equipment by reviewing CRs and open work orders (WOs) and walking down
portions of the offsite and AC power systems including the Units 2 and 3 transformer
yards.
b. Findings
No findings were identified.
.3 Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
The inspectors reviewed Entergys preparations for a Category 1 thunderstorm warning
on July 25, 2016. The inspectors reviewed the implementation of adverse weather
preparation procedures including OAP-008, Severe Weather Preparations, before the
onset of and during this adverse weather condition. The inspectors walked down the
Unit 2 SW pumps, the Unit 2 transformer yard, and the Unit 3 transformer yard to ensure
system availability and that there were no problems as a result of the severe weather.
The inspectors verified that operator actions defined in Entergys adverse weather
procedure maintained the readiness of essential systems. The inspectors discussed
readiness and staff availability for adverse weather response with operations and work
control personnel. The inspectors discussed severe weather preparedness with
operators and maintained an awareness of severe weather issues throughout the
inspection period.
b. Findings
No findings were identified.
1R04 Equipment Alignment
Partial System Walkdowns (71111.04Q - 5 samples)
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
Unit 2
22 auxiliary boiler feedwater pump (ABFP) while 21 ABFP was out of service (OOS)
for planned maintenance on July 18, 2016
Gas turbine 2/3 fuel forwarding system EDG fuel oil reserve on August 31, 2016
Component cooling water (CCW) system while 21 CCW pump and discharge check
valve were inoperable during troubleshooting on September 21, 2016
10
Unit 3
31 and 32 EDGs while 33 EDG was unavailable due to planned testing on 480V
bus 5A on September 15, 2016
ARDG and support systems following maintenance on September 29, 2016 (this
sample was part of an in-depth review of the ARDG system)
The inspectors selected these systems based on their risk-significance relative to the
reactor safety cornerstones at the time they were inspected. The inspectors reviewed
applicable operating procedures, system diagrams, the UFSAR, TSs, CRs, and the
impact of ongoing work activities on redundant trains of equipment in order to identify
conditions that could have impacted system performance of their intended safety
functions. The inspectors also performed field walkdowns of accessible portions of the
systems to verify system components and support equipment were aligned correctly and
were operable. The inspectors examined the material condition of the components and
observed operating parameters of equipment to verify that there were no deficiencies.
The inspectors also reviewed whether Entergy had properly identified equipment issues
and entered them into the CAP for resolution with the appropriate significance
characterization.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Resident Inspector Quarterly Walkdowns (71111.05Q - 6 samples)
a. Inspection Scope
The inspectors conducted tours of the areas listed below to assess the material
condition and operational status of fire protection features. The inspectors verified that
Entergy controlled combustible materials and ignition sources in accordance with
administrative procedures. The inspectors verified that fire protection and suppression
equipment was available for use as specified in the area pre-fire plan (PFP) and passive
fire barriers were maintained in good material condition. The inspectors also verified
that station personnel implemented compensatory measures for OOS, degraded, or
inoperable fire protection equipment, as applicable, in accordance with procedures.
Unit 2
ARDG/station blackout diesel generator (PFP-160A was reviewed) on August 4,
2016
Diesel fire pump house (PFP-265 was reviewed) on August 5, 2016
Independent spent fuel storage installation pad (PFP-266A was reviewed) on
September 29, 2016
Transformer yard (PFP-263 was reviewed) on September 29, 2016
11
Unit 3
Transformer yard (PFP-380 was reviewed) on September 27, 2016
ARDG (PFP-388 was reviewed) on September 29, 2016 (this sample was part of an
in-depth review of the ARDG system)
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation (71111.05A - 1 sample)
a. Inspection Scope
The inspectors observed a fire brigade drill scenario conducted on September 25, 2016,
that involved a pressurized oil leak fire on the Unit 3 main boiler feedwater pump (MBFP)
lube oil purifier located on the turbine building, 15-foot level. The inspectors evaluated
the readiness of the plant fire brigade to fight fires. The inspectors verified that Entergy
personnel identified deficiencies, openly discussed them in a self-critical manner during
the debrief, and took appropriate corrective actions as required. The inspectors verified
that the fire brigade:
Properly used turnout gear and self-contained breathing apparatus
Properly used and laid out fire hoses
Employed appropriate fire-fighting techniques
Brought sufficient fire-fighting equipment to the scene
Effectively used command and control
Searched for victims and for propagation of the fire into other plant areas
Conducted smoke removal operations
Properly used pre-planned strategies
Adhered to the pre-planned drill scenario
Met drill objectives
The inspectors also evaluated the fire brigades actions to determine whether these
actions were in accordance with Entergys fire-fighting strategies.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program (71111.11Q - 5 samples)
Unit 2
.1 Quarterly Review of Unit 2 Licensed Operator Performance in the Main Control Room
a. Inspection Scope
The inspectors observed and reviewed the Unit 2 reactor startup conducted on July 7,
2016. The inspectors observed infrequently performed test or evolution briefings,
12
pre-shift briefings, and reactivity control briefings to verify that the briefings met the
criteria specified in Entergys operating procedure 2-POP-1.2, Reactor Startup, and
administrative procedure EN-OP-115, Conduct of Operations. Additionally, the
inspectors observed test performance to verify that procedure use, crew
communications, and coordination of activities between work groups similarly met
established expectations and standards.
b. Findings
No findings were identified.
.2 Quarterly Review of Unit 2 Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed Unit 2 licensed operator simulator training on August 10, 2016,
which included an instrument failure, a loss of 138kV offsite power, followed by a loss of
the 345kV grid, and a station blackout. The inspectors evaluated operator performance
during the simulated event and verified completion of risk significant operator actions,
including the use of abnormal and emergency operating procedures. The inspectors
assessed the clarity and effectiveness of communications, implementation of actions in
response to alarms and degrading plant conditions, and the oversight and direction
provided by the control room supervisor. The inspectors verified the accuracy and
timeliness of the emergency classification made by the shift manager and the TS action
statements entered by the shift technical advisor. Additionally, the inspectors assessed
the ability of the crew and training staff to identify and document crew performance
problems.
b. Findings
No findings were identified.
Unit 3
.3 Quarterly Review of Unit 3 Licensed Operator Performance in the Unit 3 Main Control
Room
a. Inspection Scope
The inspectors observed and reviewed swapping of main lube oil coolers in accordance
with 3-SOP-LO-001, Main Lube Oil System Operation, Revision 40, conducted on
September 30, 2016. The inspectors observed pre-job briefings to verify that the
briefings met the criteria specified in Entergys administrative procedure EN-OP-115,
Conduct of Operations. Additionally, the inspectors observed operator performance to
verify that procedure use, crew communications, and coordination of activities between
work groups similarly met established expectations and standards.
b. Findings
No findings were identified.
13
.4 Quarterly Review of Unit 3 Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed licensed operator simulator training on August 10, 2016, which
included the rupture of the letdown line, a mispositioned control valve, a misaligned
control rod, and a steam generator tube rupture. The inspectors evaluated operator
performance during the simulated event and verified completion of risk significant
operator actions, including the use of abnormal and emergency operating procedures.
The inspectors assessed the clarity and effectiveness of communications,
implementation of actions in response to alarms and degrading plant conditions, and the
oversight and direction provided by the control room supervisor. The inspectors verified
the accuracy and timeliness of the emergency classification made by the shift manager
and the TS action statements entered by the shift technical advisor. Additionally, the
inspectors assessed the ability of the crew and training staff to identify and document
crew performance problems.
b. Findings
No findings were identified.
.5 Quarterly Review of Unit 3 Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed operating crew performance during an emergency planning drill
on September 14, 2016, which included a failure of a steam generator level instrument,
loss of the 6A electrical bus, a turbine trip without reactor trip, a small break loss of
coolant accident, and entry into FR-C.2, Response to Inadequate Core Cooling. The
inspectors evaluated operator performance during the simulated event and verified
completion of risk significant operator actions, including the use of abnormal and
emergency operating procedures. The inspectors assessed the clarity and effectiveness
of communications, and the oversight and direction provided by the control room
supervisor. The inspectors reviewed the accuracy and timeliness of the emergency
classification made by the shift manager and shift technical advisor. Additionally, the
inspectors assessed the ability of the crew and training staff to identify and document
crew performance problems.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness (71111.12Q - 2 samples)
Routine Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the samples listed below to assess the effectiveness of
maintenance activities on structure, system, and component (SSC) performance and
reliability. The inspectors reviewed system health reports, CAP documents,
14
maintenance WOs, and maintenance rule basis documents to ensure that Entergy was
identifying and properly evaluating performance problems within the scope of the
maintenance rule. For each SSC sample selected, the inspectors verified that the SSC
was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and
verified that the (a)(2) performance criteria established by Entergy was reasonable. As
applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals
and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors
ensured that Entergy was identifying and addressing common cause failures that
occurred within and across maintenance rule system boundaries.
Unit 3
ARDG and auxiliaries (this sample was part of an in-depth review of the Unit 3
ARDG system) on June 28, 2016
Reactor protection and controls system on August 28, 2016
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 7 samples)
a. Inspection Scope
The inspectors reviewed station evaluation and management of plant risk for the
maintenance and emergent work activities listed below to verify that Entergy performed
the appropriate risk assessments prior to removing equipment for work. The inspectors
selected these activities based on potential risk significance relative to the reactor safety
cornerstones. As applicable for each activity, the inspectors verified that Entergy
performed risk assessments as required by 10 CFR 50.65(a)(4) and that the
assessments were accurate and complete. When Entergy performed emergent work,
the inspectors verified that operations personnel promptly assessed and managed plant
risk. The inspectors reviewed the scope of maintenance work and discussed the results
of the assessment with the stations probabilistic risk analyst to verify plant conditions
were consistent with the risk assessment. The inspectors also reviewed the TS
requirements and inspected portions of redundant safety systems, when applicable, to
verify risk analysis assumptions were valid and applicable requirements were met.
Unit 2
21 ABFP and 138kV feeder 33332 OOS for maintenance on July 18, 2016
Emergent work due to instrument air piping leak on August 8, 2016
23 station battery OOS for maintenance on September 14, 2016
13.8kV feeders 13W92 and 13W3 OOS for planned maintenance on September 28,
2016
Unit 3
32 ABFP OOS for maintenance on August 8, 2016
15
ARDG and 31 residual heat removal pump OOS for maintenance on August 16,
2016 (this sample was part of an in-depth review of the ARDG system)
31 EDG OOS for surveillance on September 20, 2016
b. Findings
Introduction. The inspectors identified a Green NCV of 10 CFR 50.65(a)(4),
Requirements for Monitoring the Maintenance Effectiveness at Nuclear Power Plants,
because between August 1, 2016, and August 17, 2016, Entergy did not perform an
adequate risk assessment for the maintenance on the Unit 3 ARDG. As a result, they
did not take the required RMAs.
Description. The Unit 3 ARDG was declared non-functional on June 28, 2016, due to a
failed battery charger. Entergy performed a modification to replace the battery charger
and cleared the tag-out to restore the diesel generator to service on July 27, 2016.
Entergy determined that the ARDG was available at this time, although the
post-modification testing was not complete, in accordance with guidance in procedure
IP-SMM-WM-101, Fire Protection and Maintenance Rule (a)(4) Risk Assessment. On
July 31, 2016, the input breaker to the battery charger tripped open. Entergy determined
that the ARDG was no longer available for risk purposes and commenced corrective
maintenance. On August 1, 2016, during rounds, an operator discovered that the output
breaker for the ARDG was crooked in its cubicle. The following day, maintenance staff
reported a crackling noise from the output breaker indicating that it was not making
proper contact in its crooked position. During follow-up interviews, Entergy determined
that the output breaker had been racked in improperly while the tag-out was being
cleared on July 27, 2016.
Per IP-SMM-WM-101, and the Equipment OOS risk tool, fire risk is Green when taking a
component OOS for maintenance results in only one safe shutdown path and that
component will be OOS for less than thirty days. If the component will be OOS for more
than thirty days, fire risk is Yellow and RMAs are required in certain fire areas,
depending on the component. With the Unit 3 ARDG OOS, the Unit 2 ARDG is the only
remaining credited safe shutdown path. After thirty days in this configuration, RMAs are
required in the 31 and 33 EDG rooms, the cable spreading room, the switchgear room,
the control room, and the upper electrical tunnel. These actions include shiftly
walkdowns to look for transient combustibles, prohibiting hot work, confirming
functionality of the fire protection equipment, postponing maintenance on fire protection
equipment, and limiting work in the areas affected.
On August 16, 2016, the inspectors asked Entergy whether fire risk was Green or
Yellow. Entergy stated that they considered fire risk to be Green because the ARDG
had only been OOS since July 31, 2016, which was less than thirty days. The
inspectors observed that since the breaker had been racked in incorrectly while they
were restoring from the original battery charger replacement, the ARDG had been OOS
continuously since June 28, 2016, a time period greater than thirty days. Entergys
response was that they had not considered the impact of the breaker on risk. As a
result, Entergy wrote CR-IP3-2016-2538, changed fire risk status to Yellow, and began
implementing RMAs on August 17, 2016.
Analysis. The inspectors determined that not performing an adequate risk assessment
for the work on the Unit 3 ARDG was within Entergys ability to foresee and correct and
16
was a performance deficiency. The inspectors determined that this performance
deficiency was more than minor because it is associated with the Protection Against
External Factors attribute of the Mitigating Systems cornerstone and adversely affected
its objective to ensure the reliability of systems that respond to initiating events to
prevent undesirable consequences. Specifically, due to the inadequate risk
assessment, Entergy did not perform shiftly walkdowns for transient combustibles and
related fire and ignition sources on the available safe shutdown train.
Using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix K,
Maintenance Risk Assessment and Risk Management Significance Determination
Process, the inspectors determined that the failure to conduct RMAs for the
unavailability of the ARDG required further assessment. A Region I SRA used
SAPHIRE, Revision 8.1.14 and the Indian Point Unit 3 SPAR Model, Revision 8.20 to
complete the DRE of this performance deficiency. To calculate the ICCDP for this
finding, the SRA used an exposure time of 16 days and modeled the unavailability of the
ARDG by setting the generators output breaker basic event (ACP-CRB-00-52EG4)
failure probability to 1.0. Truncation for the analyses was set to 1.0E-11. The ICCDP for
this finding was calculated to be less than 1E-7 or very low safety significance (Green).
The dominant core damage sequences involve fires leading to a station blackout event
resulting in a small break loss of coolant accident associated with reactor coolant pump
seal failures.
This finding has a cross-cutting aspect in the area of Problem Identification and
Resolution because Entergy did not identify that an improperly racked-in breaker had a
fire risk impact when combined with other plant conditions. [P.1]
Enforcement. 10 CFR 50.65(a)(4) states that before performing maintenance activities,
the licensee shall assess and manage the increase in risk that may result from the
proposed maintenance activities. Contrary to this, between August 1, 2016, and
August 17, 2016, Entergy did not adequately assess and manage the increase in risk
from maintenance on the Unit 3 ARDG. Entergy wrote CR-IP3-2016-2538, changed fire
risk status to Yellow, and began implementing RMAs on August 17, 2016. Because this
violation was of very low safety significance (Green) and Entergy entered this
performance deficiency into the CAP, the NRC is treating this as an NCV in accordance
with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000286/2016003-01,
Failure to Adequately Assess Fire Risk Associated with Maintenance on the Unit 3
ARDG)
1R15 Operability Determinations and Functionality Assessments (71111.15 - 8 samples)
a. Inspection Scope
The inspectors reviewed operability determinations and functionality assessments for the
following degraded or non-conforming conditions:
Unit 2
CR-IP2-2016-05220, missed implications of baffle bolt jetting indications on Units 2
and 3 spent fuel on August 22, 2016
CR-IP-2016-05418, metal impact monitor system functionality assessment on
September 1, 2016
17
CR-IP2-2016-05503, through-wall leak on non-essential SW header between 23
Zurn strainer and SWN-2-2, 23 SW pump discharge valve on September 6, 2016
CR-IP2-2016-05757, 21 CCW pump motor baker test results invalid on
September 21, 2016
CR-IP2-2016-05877, unexpected drop in SW header pressure on September 27,
2016
Unit 3
CR-IP3-2016-01961, prompt operability determination for implications of degraded
baffle bolts on July 11, 2016
CR-IP3-2016-02910, bus 5A undervoltage time delay relay 62-2/5A failed to meet
acceptance criteria on September 15, 2016
CR-IP3-2016-01370, EDG AVR card solder joint cracking extent of condition on
September 23, 2016
The inspectors selected these issues based on the risk significance of the associated
components and systems. The inspectors evaluated the technical adequacy of the
operability determinations to assess whether TS operability was properly justified and
the subject component or system remained available such that no unrecognized
increase in risk occurred. The inspectors compared the operability and design criteria in
the appropriate sections of the TSs and UFSAR to Entergys evaluations to determine
whether the components or systems were operable.
The inspectors confirmed, where appropriate, compliance with bounding limitations
associated with the evaluations. Where compensatory measures were required to
maintain operability, the inspectors determined whether the measures in place would
function as intended and were properly controlled by Entergy. The inspectors
determined, where appropriate, compliance with bounding limitations associated with the
evaluations.
b. Findings
(Closed) Unresolved Item (URI) 05000247/2016001-06: 23 EDG Automatic Voltage
Regulator Failure
Introduction. The inspectors identified a self-revealing Green NCV of 10 CFR 50,
Appendix B, Criterion XVI, Corrective Actions, because between 2012 and 2016,
Entergy did not perform specified inspections of the 23 EDG AVR cards. As a result, on
March 7, 2016, and March 10, 2016, the 23 EDG failed to run due to poor voltage
regulation caused by degraded connections on the AVR card.
Description. A URI was issued in NRC Inspection Report 05000247/2016001. This item
is closed based on the finding described below. On March 7, 2016, approximately one
hour after the trip of the 3A normal feed breaker, the 23 EDG tripped on overcurrent
while powering the 6A 480V safety bus. The 6A bus remained de-energized for
approximately one hour until the crew restored the 6A bus via off-site power. The 23
EDG was declared inoperable. All four 480V safety buses were restored to off-site
power. Entergy suspected that an overcurrent relay had spuriously tripped, replaced the
overcurrent relays, and retested the 23 EDG satisfactorily on March 8, 2016. However,
18
subsequent bench testing of the overcurrent relays demonstrated that they were
accurately calibrated.
On March 10, 2016, during performance of PT-R14, Automatic SI System Electrical
Load and Blackout Test, the 23 EDG exhibited anomalous behavior during the train B
load sequencing. During this test, the voltage on safety bus 6A dropped to
approximately 200V when the 23 auxiliary feedwater pump was sequenced onto the bus
(CR-IP2-2016-01430) and the sequencer failed to complete the first two sequences.
The 23 EDG was again declared inoperable and the period of inoperability was
backdated to March 7, 2016, when it originally tripped. Further troubleshooting and
additional failure modes analysis by Entergy initially determined that the cause of both
events may have been a degraded resistor (R25) on the 23 EDG AVR card.
The 23 EDG AVR card was replaced, and the 23 EDG was again tested satisfactorily.
The voltage anomaly issues exhibited during the March 10, 2016, test were documented
in CR-IP2-2016-01430 which was closed in CR-IP2-2016-01260 to be included in the
causal assessment associated with the tripping of 23 EDG breaker on March 7, 2016.
Entergy assigned a vendor to perform confirmatory laboratory bench testing and failure
analysis of the 23 EDG AVR card. The vendor report attributed the cause of the
March 10, 2016, loss of voltage control to a degraded solder joint on the L1 magnetic
amplifier on the AVR card. The vendor report explicitly did not attribute the event on
March 7, 2016, to the same cause. Entergy assigned a corrective action in CR-IP2-
2016-01260 to review the cause of the 23 EDG overcurrent trip on March 7, 2016, and in
light of the vendor report. On September 1, 2016, Entergy documented that their initial
investigation into the failure on March 7, 2016, concluded that the failure was most likely
due to an intermittent connection to the L1 mag amp on the AVR card. Since they have
determined the causes of the failures on March 7, 2016, and March 10, 2016, are likely
the same direct cause, this violation closes URI 05000247/2016001-06, 23 Emergency
Diesel Generator Automatic Voltage Regulator Failure. The URI is closed because it
was determined that there was a performance deficiency.
In 2007, Entergy received a 10 CFR 21 notification (ML072750470) that there was a
potential for solder joint cracks on their AVR cards and wrote CR-IP2-2007-3825 and
CR-IP3-2007-3686. Cracked solder joints on the AVR cards affect the ability of the EDG
to achieve and/or maintain voltage. Because the connectivity of the joint can be
degraded by vibration, the impact on voltage regulation may be intermittent. The
notification recommended an initial inspection to look for cracked solder joints and then
subsequent inspections every refueling outage once the cards had been in service for 15
years. Entergy wrote a corrective action to write work requests to perform the initial
inspections but did not write any corrective actions to address the need for recurring
inspections. Entergy performed the initial inspections for all of their cards in 2009 and
2010 and did not find any degraded solder joints on any of the Unit 2 EDGs, although
the AVR card from the Unit 3 32 EDG did have degraded solder joints and was repaired.
Entergy did not establish a preventive maintenance activity to perform the subsequent
inspections every two years as stated in the service bulletin.
In response to the events of March 7, 2016, and March 9, 2016, Entergy performed
extent of condition inspections on both the 21 and 22 EDG AVR cards and identified
partially cracked solder joints on both cards. Entergy repaired the solder joints and
replaced the cards. Like the 23 EDG AVR card, the AVR card for the 21 EDG is also
original equipment, while the 22 EDG AVR card was replaced more recently.
19
Analysis. The failure to establish recurring (two-year) inspections of the AVR cards that
had longer than 15 years in service is a performance deficiency that was reasonably
within Entergys ability to foresee and correct. The inspectors determined that this
performance deficiency was more than minor because it is associated with the
Equipment Performance attribute of the Mitigating Systems cornerstone and adversely
affected its objective to ensure the reliability of systems that respond to initiating events
to prevent undesirable consequences. Specifically, the 23 EDG failed to run on
March 7, 2016, and March 10, 2016.
The performance deficiency represented a loss of function of a single train (23 EDG) for
greater than its TS allowed outage time of seven days. Inspection of the 21, 22, and 23
EDG AVR cards all showed substantial degradation of the solder joints to the L1 mag
amp. The 22 EDG AVR card was observed to have degradation in the solder joint and
had been previously replaced in 2010. This degraded condition likely existed prior to the
failure on March 7, 2016. As a result, the failure mechanism could have activated at any
time between the last successful test on February 7, 2016, and the failure at the next
demand event on March 7, 2016. The inspectors evaluated the finding in accordance
with IMC 0609, Appendix A, The Significance Determination Process for Findings at
Power, Exhibit 2, Mitigating Systems Screening Questions. The inspectors noted that
while the degraded 23 EDG AVR had resulted in a trip of the EDG on March 7, 2016, it
was subsequently run on March 8, 2016, and twice on March 9, 2016, during test 2-PT-
R014, Automatic SI System Electrical Load and Blackout Test. During this test, the A
side logic was completed with no anomalies noted with the 23 EDG; however, during the
B side test, the 6A bus voltage dropped to 200V with several equipment load sheds
automatically occurring prior to success on the third attempt to load the EDG. The 23
EDG did not trip during this test because the low voltage relay protection is overridden
during an emergency start (when the EDG is started from an SI signal). Subsequently,
the AVR was identified as the likely cause of the voltage drop during the March 9, 2016,
test and the EDG was declared inoperable. While the facts support an intermittent type
of failure (several successful runs after March 7, 2016, without the AVR being repaired),
the inspectors concluded that the previous failure on March 7, 2016, was most likely
caused by the degraded AVR function. Therefore, the inspectors determined that the
23 EDG trip on March 7, 2016, represented an actual loss of function for greater than its
TS allowed outage time and a DRE was performed.
The Region I SRA determined that the estimated increase in core damage frequency
associated with this performance deficiency is low E-8/year or very low safety
significance (Green). The DRE was performed with the conservative assumption that
the intermittent failures would have resulted in impacting at-power conditions going back
to the last successful 23 EDG surveillance test performed on February 7, 2016. The
SRA used the guidance within the Risk Assessment of Operational Events, Volume 1 -
Internal Events, Section 2.4, to determine an exposure time at unit power conditions of
T/2 or 14 days from the last successful test due to the unknown nature of the failure
mechanism. This provided a bounding assessment. The SRA used the Systems
Analysis Programs for Hands-On Evaluation, Revision 8.1.4, and the SPAR Model for
Indian Point Unit 2, Model Version 8.19. The SRA considered the last load test which
resulted in unexpected load shedding to be a failure. Therefore, the last 5 times the
EDG had run, two of the runs were considered to be failures for a 0.40 failure probability.
Additionally, the SRA had to make modifications to update the model to perform the
evaluation. This included revising the base case SPAR model to substitute the Unit 2
ARDG for the combustion turbine which is no longer used for the offsite power recovery
20
fault trees. The SRA reviewed Entergys probabilistic risk assessment model and
established a failure probability for the ARDG of 5E-2 based on a review of the Entergys
probabilistic risk assessment model which included operator actions and equipment
failure modeling.
The condition case was represented by developing post-processing rules to recognize
that the 23 EDG ran for over 75 minutes on March 7, 2016, prior to its failure.
Modifications to the SPAR model were performed to recognize that plant procedures
direct alignment of the ARDG to restore power to any safety-related 480V bus which
becomes de-energized (2A, 3A, 5A, or 6A buses) during a loss of offsite power (LOOP)
event and failure of an EDG. Therefore, if the 23 EDG would have failed during an at
power event, procedures direct for the ARDG to be aligned to its respective bus. The
SRA developed the modification only for LOOP events where capability may not exist to
isolate a failed open power operated relief valve (PORV). For events where a PORV
cannot be isolated, the ARDG is not credited due to timing considerations in aligning the
ARDG for this type of loss of coolant scenario. The SRA determined for this intermittent
failure condition, modeling should provide for the capability to isolate a failed open
PORV associated with the 23 EDG powered block isolation valve because the 23 EDG
had run for a nominal 75 minutes prior to its initial failure on March 7, 2016. Additionally,
the SRA made a conservative modeling assumption related to common cause, by
setting the 23 EDG failure to run basic event to TRUE to increase the probability of
common cause failure for all of the EDGs, even though the failure was intermittent. The
common cause failure probability for the EDGs was increased to 4.7E-3 from its nominal
value of 1.4E-4. Finally, the 23 EDG failure rate was set at a 40 percent probability of
failure due to the recent performance data. As a result, the SRA determined that the
estimated increase in core damage frequency associated with the performance
deficiency was 1.5E-8/yr for the 14-day exposure time assumed at-power conditions.
The dominant core damage sequences for the at-power condition involved LOOP events
with failure of the auxiliary feedwater system and feed and bleed. The dominant core
damage cutset consisted of a LOOP with failure of the turbine driven auxiliary feedwater
pump, failure of the 22 EDG to run, failure of the 23 EDG to run, and failure of the ARDG
to align power to a safety bus.
Because the 23 EDG AVR was not replaced and repaired until after the March 9, 2016,
test anomaly, the SRA also reviewed the risk associated with the EDG being degraded
during the unit shutdown condition until the AVR was repaired and the 23 EDG
clearance removed on March 16, 2016. The SRA determined the shutdown risk using
IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination
Process Phase 1 Initial Screening Characterization of Findings. The SRA noted the
March 7, 2016, loss of safety bus power event and residual heat removal cooling was
caused by inadequate guidance in procedures, resulting in an overcurrent condition on
the Bus 3A normal supply breaker as part of load test setup activities for a surveillance
test. Without this error, the trip of the 23 EDG would not have caused a loss of residual
heat removal cooling; and, therefore, the EDG performance deficiency was not relevant
to any shutdown initiating event. The performance deficiency associated with the
23 EDG was evaluated within Exhibit 3 - Mitigating Systems Screening Questions.
Because the 23 EDG was conservatively assumed to have lost its safety function for
greater than its TS outage time, a Phase 2 evaluation within Appendix G was performed.
Using Worksheet 3, Loss of Offsite Power in plant operating state 1 (Head On, Reactor
Coolant System Closed), for the limiting condition, the SRA made the following
21
assumptions: 1) initiating event likelihood equal to two given the exposure time, 2)
emergency AC credit of three based upon the availability of the 21 and 22 EDGs, 3)
steam generator cooling credit of three based on the fact that the 24 reactor coolant
pump was in operation and providing forced circulation, and 4) a credit of one for
recovery of offsite power before core damage (RLOOP3). Based upon the Phase 2
worksheet results, the shutdown safety significance of the performance deficiency was
estimated in the E-9 range. The SRA noted the condition would also be in the E-8 range
considering a plant operating state 2 condition (reactor coolant system vented) with no
credit given for aligning the Unit 2 ARDG. Therefore, the total risk (at-power and
shutdown) for this condition was estimated to be in the E-8 range or of very low safety
significance (Green) and was considered to be a conservative bounding analysis (i.e.,
assuming EDG exposure time 14 days at power, EDG common cause effect and no
recovery of buses with ARDG during the outage risk evaluation).
The inspectors determined that this violation was not indicative of current performance
because the last time Entergy would reasonably have been prompted to create
corrective actions to perform periodic inspections was during the initial inspections in
2010. Therefore, no cross-cutting aspect was assigned.
Enforcement. 10 CFR 50, Appendix B, Criterion XVI, states 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 this, between 2010 and March 2016,
Entergys CAP did not assure that a condition adverse to quality associated with the
safety-related EDG system was promptly identified and corrected. Specifically, they did
not perform the recommended once per refueling cycle inspections of the EDG AVR
cards, and as a result, the 23 EDG failed to run due to undetected degraded
connections. Entergy replaced the AVR card in the 23 EDG, repaired the solder joints in
the AVR cards for the 21 and 22 EDGs, and wrote CR-IP2-2016-1260 and
CR-IP3-2016-1370. Because this violation was of very low safety significance (Green)
and Entergy has entered this performance deficiency into the CAP, the NRC is treating
this as an NCV in accordance with Section 2.3.2.a of the NRC Enforcement Policy.
(NCV 05000247/2016003-02, Missed Inspections on Automatic Voltage Regulator
Cards Results in Emergency Diesel Generator Failure to Run)
This URI is closed.
1R18 Plant Modifications (71111.18 - 3 samples)
a. Inspection Scope
The inspectors reviewed the temporary modifications listed below to determine whether
the modifications affected the safety functions of systems that are important to safety.
The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing
results and conducted field walkdowns of the modifications to verify that the temporary
modifications did not degrade the design bases, licensing bases, and performance
capability of the affected systems.
22
Unit 2
Temporary modification 66349 to repair a crack on vital battery 23, cell 4
Unit 3
Temporary modification 65773 to replace the failed ARDG battery charger with a
digital battery charger (this sample was part of an in-depth review of the ARDG
system)
Temporary modification 66780 to install jumpers in order to maintain bus 5A
interlocking relay circuit while relay 62-2/5A is replaced
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19 - 7 samples)
a. Inspection Scope
The inspectors reviewed the post-maintenance tests for the maintenance activities listed
below to verify that procedures and test activities ensured system operability and
functional capability. The inspectors reviewed the test procedure to verify that the
procedure adequately tested the safety functions that may have been affected by the
maintenance activity and that the acceptance criteria in the procedure were consistent
with the information in the applicable licensing basis and/or design basis documents.
The inspectors verified that the test results were properly reviewed and accepted and
problems were appropriately documented. The inspectors also walked down the
affected job site, observed the pre-job brief and post-job critique where possible,
confirmed work site cleanliness was maintained, and witnessed the test or reviewed test
data to verify quality control hold points were performed and checked, and that results
adequately demonstrated restoration of the affected safety functions.
Unit 2
21 ABFP recirculation valve FCV-1121 actuator preventative maintenance on
July 19, 2016
Replacement of 138kV breaker BT4-5 on August 12, 2016
Corrective maintenance on the 21 CCW pump discharge check valve on
September 22, 2016
Unit 3
ARDG protective relay replacement and calibration on August 23, 2016 (this sample
was part of an in-depth review of the ARDG system)
ARDG four-year preventive maintenance on September 2, 2016 (this sample was
part of an in-depth review of the ARDG system)
ARDG battery charger replacement on September 12, 2016 (this sample was part of
an in-depth review of the ARDG system)
Undervoltage relay 62-2/5A replacement on September 17, 2016
23
b. Findings
No findings were identified.
1R22 Surveillance Testing (71111.22 - 4 samples)
a. Inspection Scope
The inspectors observed performance of surveillance tests and/or reviewed test data of
selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR,
and Entergys procedure requirements. The inspectors verified that test acceptance
criteria were clear, tests demonstrated operational readiness and were consistent with
design documentation, test instrumentation had current calibrations and the range and
accuracy for the application, tests were performed as written, and applicable test
prerequisites were satisfied. Upon test completion, the inspectors considered whether
the test results supported that equipment was capable of performing the required safety
functions. The inspectors reviewed the following surveillance tests:
Unit 2
2-PT-Q034, 22 auxiliary feed pump quarterly surveillance, on August 1, 2016
Unit 3
3-PT-Q062A, 31 charging pump quarterly surveillance test, on August 24, 2016
3-PT-Q98C, steam line pressure functional test, on September 13, 2016
WO 00446386, 31 EDG AVR card inspection, on September 20, 2016
b. Findings
Introduction. The inspectors identified a Green NCV of 10 CFR 50, Appendix B,
Criterion XVI, Corrective Actions, because Entergy did not take timely corrective action
to perform an inspection of the 33 EDG AVR card. As a result, the degraded
connections on the L1 magnetic amplifier card on the 32 EDG were not repaired for a
prolonged period of time.
Description. On March 7, 2016, and March 10, 2016, the 23 EDG on Unit 2 experienced
voltage control issues while in unit mode. After performing troubleshooting on the
voltage regulator card, Entergy determined that the solder joints on the L1 magnetic amp
connections were degraded, resulting in intermittent connections that affected the ability
to achieve and maintain voltage. Entergy further determined that the solder joints had
been the subject of a 10 CFR 21 report in 2007. The solder joints on all six affected
diesel generators at Indian Point had been inspected initially in 2009 and 2010, but the
recommended follow-up inspections had not been performed. Entergy took action to
inspect the AVR cards on the Unit 2 EDGs before the end of the Unit 2 refueling outage
in May 2016 and identified indications of degradation in the L1 mag amp solder joints on
all three cards.
On May 19, 2016, Entergy wrote a corrective action to perform the same inspections on
the 31, 32, and 33 EDG AVR cards, under CR-IP3-2016-1370, CA-5. This corrective
24
action was originally due on June 10, 2016, with the intent to perform it prior to the next
monthly surveillance of each EDG. The EDGs had been evaluated as operable-
degraded/non-conforming, and completion of the corrective actions would restore the
EDGs to operable status. The inspections were not performed prior to the June
surveillances because Entergy staff raised questions about the adequacy of the planned
post-maintenance testing. The due date was extended to coincide with the next monthly
surveillance test. The inspections were not performed prior to the July surveillances
because Entergy prioritized post-outage work at Unit 2 over the inspections and the due
date was extended for a second time to August. The inspections were not performed
prior to the August surveillances because Entergy once again prioritized other work at
the station (repairs to the 23 circulating water pump) over the inspections, and the due
date was extended a third time. Entergys CAP requires that due date extensions
include the basis for why the extension is acceptable. The justifications provided for
each due date extension were that the EDGs had been determined to be operable-
degraded/non-conforming (vice inoperable). The third due date extension also stated
that this was an administrative action. Subsequent discussions with management
revealed that the scheduling of resources prevented the completion of the Unit 3 EDG
AVR card solder joints because of higher priority assignments of resources. These
assignments did not rise to the same level of risk significance as the Unit 3 EDG AVR
card degradation.
On September 23, 2016, Entergy performed the inspection on the 33 EDG AVR card
and identified two solder joints with signs of degradation. They replaced all of the solder
joints for the L1 mag amp and returned the diesel generator to service. The 33 EDG
performed satisfactorily during its last surveillance run.
Analysis. The failure to ensure that the solder joint cracking on the 33 EDG AVR card
was promptly identified and corrected was a performance deficiency that was within
Entergys ability to foresee and correct. Specifically, Entergy extended the due date
three times and performed the card inspections nearly four months after identifying that
the recommended periodic inspections had not been performed and that degradation
had occurred on three identical cards in Unit 2. The performance deficiency is more
than minor because it is associated with the Design Control attribute of the Mitigating
Systems cornerstone and adversely affected its objective to ensure the reliability of
systems that respond to initiating events to prevent undesirable consequences. The
existence of cracked solder joints on the AVR card decreases the reliability of the EDGs,
and the untimely corrective action allowed this degraded condition to persist without
being corrected. In accordance with IMC 0609.04, Initial Characterization of Findings,
and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for
Findings At-Power, issued June 19, 2012, the inspectors determined that the finding
was of very low safety significance (Green) because the 33 EDG maintained its
operability or functionality, it did not represent a loss of system or function, and it did not
involve external mitigation systems.
The inspectors determined that this finding had a cross-cutting aspect in the area of
Human Performance, Conservative Bias, because leaders did not take a conservative
approach to decision making, particularly when information is incomplete or conditions
are unusual. Specifically, Entergy did not inspect the 33 EDG AVR cards at the first
available opportunity due to resource constraints. [H.14]
25
Enforcement. 10 CFR 50, Appendix B., Criterion XVI, states 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 this, between June 2016 and
September 2016, Entergys CAP did not assure that a condition adverse to quality
associated with the safety-related EDG system was promptly corrected. Specifically,
they did not perform the recommended inspection of the 33 EDG AVR card, and as a
result, the degraded condition existed for prolonged period of time. Entergy repaired the
degraded solder joints on the AVR card in the 33 EDG and wrote CR-IP3-2016-3018.
Because this violation was of very low safety significance (Green) and Entergy has
entered this performance deficiency into the CAP, the NRC is treating this as an NCV in
accordance with Section 2.3.2.a of the NRC Enforcement Policy. (NCV
05000286/2016003-03, Untimely Corrective Actions for Degraded Automatic
Voltage Regulator Cards)
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation (71114.06 - 1 sample)
Training Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine Entergy emergency drill on
September 14, 2016, to identify any weaknesses and deficiencies in the classification,
notification, and protective action recommendation development activities. The
inspectors observed emergency response operations in the simulator to determine
whether the event classification, notifications, and protective action recommendations
were performed in accordance with procedures. The inspectors also attended the
station drill critique to compare inspector observations with those identified by Entergy in
order to evaluate Entergys critique and to verify whether Entergy was properly
identifying weaknesses and entering them into the CAP.
b. Findings
No findings were identified.
2. RADIATION SAFETY
Cornerstone: Public Radiation Safety and Occupational Radiation Safety
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01 - 4 samples)
a. Inspection Scope
The inspectors reviewed Entergys performance in assessing and controlling radiological
hazards in the workplace. The inspectors used the requirements contained in
10 CFR 20, TSs, applicable regulatory guides (RGs), and the procedures required by
TSs as criteria for determining compliance.
26
Instructions to Workers (1 sample)
The inspectors reviewed HRA work permit controls and use, observed containers of
radioactive materials, and assessed whether the containers were labeled and controlled
in accordance with requirements.
The inspectors reviewed several occurrences where a workers electronic personal
dosimeter alarmed. The inspectors reviewed Entergys evaluation of the incidents,
documentation in the CAP, and whether compensatory dose evaluations were
conducted when appropriate. The inspectors verified follow-up investigations of actual
radiological conditions for unexpected radiological hazards were performed.
Contamination and Radioactive Material Control (1 sample)
The inspectors observed the monitoring of potentially contaminated material leaving the
RCA and inspected the methods and radiation monitoring instrumentation used for
control, survey, and release of that material. The inspectors selected several sealed
sources from inventory records and assessed whether the sources were accounted for
and were tested for loose surface contamination. The inspectors evaluated whether any
recent transactions involving nationally tracked sources were reported in accordance
with requirements.
Risk-Significant HRA and Very High Radiation Area Controls (1 sample)
The inspectors reviewed the procedures and controls for HRAs, very high radiation
areas, and radiological transient areas in the plant.
Problem Identification and Resolution (1 sample)
The inspectors evaluated whether problems associated with radiation monitoring and
exposure control (including operating experience) were identified at an appropriate
threshold and properly addressed in the CAP.
b. Findings
Introduction. A self-revealing Green NCV of TS 5.7.1e was identified when workers
entered the Unit 2 FSB truck bay that was posted and controlled as a HRA without
receiving a briefing on dose rates in the work area. Specifically, on June 6, 2016, two
NPOs entered the Unit 2 FSB truck bay to hang tags on the backup spent fuel pool
cooling filters. The NPOs signed in on an RWP but did not receive a radiological briefing
on the dose rates in their work area. After entering the area, one worker received an
electronic dosimeter dose rate alarm and subsequently both workers promptly exited the
area. Immediate corrective actions included restricting the access of the two NPOs to
the RCA. The issue was entered into Entergys CAP as CR-IP2-2016-03610.
Description. On June 6, 2016, two NPOs entered the Unit 2 FSB truck bay, a posted
HRA, to hang tags on the backup spent fuel pool cooling filters. The NPOs signed in on
a HRA RWP but did not receive a briefing on the radiological conditions in their work
area. After entering the area, one worker received an electronic dosimeter dose rate
alarm of 991 mrem/hr. The two NPOs exited the HRA after receiving the alarm and
reported the incident to radiation protection.
27
Event follow-up (apparent cause evaluation for CR-IP2-2016-03610) determined that the
NPOs entered the RCA at the Unit 2 health physics (HP) control point (HP1) but did not
check in with the HP shift technician. They subsequently proceeded to the 80-foot
elevation of the Unit 2 PAB where they were expected to dress out and receive a
detailed radiological briefing at the outage HP desk. The NPOs bypassed the normal
dress-out area and proceeded to the NPO field office, located on the 98-foot elevation of
the PAB, to dress-out. After completing dress-out, the NPOs proceeded directly to their
work location, a posted HRA, without having received a briefing on radiological
conditions from the HP control desk on the 80-foot elevation of the PAB as required.
Shortly after entering the Unit 2 FSB truck bay HRA, one NPO received a dose rate
alarm, later determined to be at 991 mrem/hr (alarm set point of 900 mrem/hr). Both
workers exited the truck bay and proceeded to the HP control point.
TS 5.7.1 requires that activities in a HRA with dose rates greater than or equal to
100 mrem/hr at 30 centimeters from the source but less than 1000 mrem/hr shall be
controlled by means of an RWP. This includes specification of radiation dose rates in the
immediate work area and other appropriate radiation protection equipment and
measures and that all workers shall be briefed on the radiological conditions in their work
area prior to entry.
Analysis. The failure to obtain a radiological briefing prior to entry into a posted HRA is a
performance deficiency that was reasonably within Entergys ability to foresee and
correct. The performance deficiency was determined to be more than minor based on
similar example 6.h in IMC 0612, Appendix E, and because it adversely affected the
Human Performance attribute of the Occupational Radiation Safety cornerstone
objective. Specifically, Entergy staff violated the TS 5.7.1 HRA radiological briefing
requirement designed to protect workers from unnecessary radiation exposure. Using
IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination
Process, the finding was determined to be of very low safety significance (Green)
because it did not involve: (1) ALARA occupational collective exposure planning and
controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an
impaired ability to assess dose. The finding was self-revealing because Entergy was
made aware of the situation as a result of an electronic dose rate alarm.
The cause of the finding is related to the cross-cutting aspect of Human Performance,
Procedure Adherence, in that the workers did not follow processes, procedures, and
work instructions for entering a posted HRA. [H.8]
Enforcement. TS 5.7.1e requires that entry into an HRA with dose rates not exceeding
1.0 rem/hr at 30 centimeters from the source be performed by personnel that have been
briefed on the radiological conditions in the area prior to entry. Contrary to this
requirement, on June 6, 2016, two NPOs entered the Unit 2 FSB truck bay, a posted
HRA, to hang tags on the backup fuel pool cooling filters. The NPOs signed in on an
RWP but did not receive a briefing on the radiological conditions in the area prior to
entry. After entering the area, one worker received an electronic dosimeter dose rate
alarm and both workers promptly exited the area. Immediate corrective actions included
restricting the access of the two NPOs to the RCA. Because this finding was determined
to be of low safety significance (Green) and was entered into Entergys CAP as
CR-IP2-2016-03610, this violation is being treated as an NCV consistent with
Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000247/2016003-04,
Entry into a High Radiation Area without Radiological Briefing)
28
2RS2 Occupational ALARA Planning and Controls (71124.02 - 2 samples)
a. Inspection Scope
The inspectors assessed Entergys performance with respect to maintaining
occupational individual and collective radiation exposures ALARA. The inspectors used
the requirements contained in 10 CFR 20, applicable RGs, TSs, and procedures
required by TSs as criteria for determining compliance.
Radiological Work Planning (1 sample)
The inspectors selected the following radiological work activities based on exposure
significance for review:
RWP 20162615, PCI-Baffle Bolt Removal/Repair
RWP 20162616, Westinghouse-Baffle Bolt Removal/Repair
RWP 20162601, Radiation Protection Support
RWP 20162642, Cavity Liner Repair
For each of these activities, the inspectors reviewed ALARA work activity evaluations,
exposure estimates, exposure reduction requirements, results achieved (dose rate
reductions, actual dose), person-hour estimates and results achieved, and post-job
reviews that were conducted to identify lessons learned.
Verification of Dose Estimates and Exposure Tracking Systems (1 sample)
The inspectors reviewed the current annual collective dose estimate; basis methodology;
and measures to track, trend, and reduce occupational doses for ongoing work activities.
The inspectors evaluated the adjustment of exposure estimates or re-planning of work.
The inspectors reviewed post-job ALARA evaluations of excessive exposure results.
b. Findings
Introduction. A self-revealing finding of very low safety significance (Green) was
identified due to Entergy having unintended occupational collective exposure resulting
from performance deficiencies in planning while preparing to perform reactor cavity liner
repair activities during the Unit 2 refueling outage 2R22. Inadequate work planning
resulted in unplanned, unintended collective exposure due to conditions that were
reasonably within Entergys ability to foresee. The work activity planning deficiencies
resulted in the collective exposure for these activities increasing from the planned dose
of 2.386 person-rem to an actual dose of 10.305 person-rem.
Description. Unit 2 has had a long-standing issue with refueling water storage tank
water from the reactor refueling cavity (during refueling outages) leaking into the
basement of the containment structure. Leakage rates of 4.5 gallons per minute were
observed during initial cavity flood-up, and continued throughout the outage, placing an
additional burden on the liquid radiological waste system to collect and process this
leakage. Due to a period of limited work activity during the outage (2R22), a decision
was made to effect repairs by draining down the cavity and performing
29
welding activities on the cavity liner. Although the cavity liner leakage was a long-
standing issue, no extensive work/repair plan existed when this window of opportunity
opened.
The original scope of work was an area on the west face of the cavity liner approximately
eight feet in length. Upon closer examination of the cavity liner, it was determined by
Entergy that the area needing repair was much larger than originally intended on the
west face of the cavity liner and also needed to include the opposite face of the liner.
The welding method in the original repair plan also proved inadequate to the task,
resulting in most of the weld repairs not being able to be appropriately tested. As a
result, the repairs had only limited effectiveness, resulting in a small decrease of the
cavity leak rate from 4.5 gallons per minute to 3.7 gallons per minute. Initial work was
performed on April 4, 2016, without the intended shielding being installed, resulting in an
additional 1.1 person-rem of exposure before the appropriate shielding was put in place.
The work estimate in person-hours was challenged by scope increases, consisting of
greater than expected areas needing repair, difficulty of welding, and the material
condition of the cavity walls. Unintended collective exposure that was greater than the
planned collective exposure for cavity liner repair work was the result of the limited and
inadequate plan for the work to be performed and included the following: (1) conflicts
and discrepancies in the original repair plan (CR-IP2-2016-02528), (2) two significant
defects beyond the repair plan (CR-IP2-2016-02502), and (3) repairs could not be
completed due to the condition of the existing liner in localized areas
Consequently, the total collective dose for the reactor cavity liner repair increased from
the planned collective dose of 2.386 person-rem to the actual collective dose of 10.305
person-rem. This issue was entered into Entergys CAP as CR-IP2-2016-02528,
CR-IP2-2016-02502, and CR-IP2-2016-02548.
Analysis. The failure to develop an adequate outage work plan for the reactor cavity
liner repair work was a performance deficiency that was within Entergys ability to control
and prevent. The performance deficiency was more than minor because it was
associated with the Program and Process attribute of the Occupational Radiation Safety
cornerstone and adversely affected the cornerstone objective to ensure the adequate
protection of the worker health and safety from exposure to radiation. Additionally, the
performance deficiency was determined to be more than minor based on similar
example 6.i in Appendix E of IMC 0612, in that the actual collective dose exceeded
5 person-rem and exceeded the planned, intended dose by more than 50 percent. In
accordance with IMC 0609, Appendix C, "Occupational Radiation Safety Significance
Determination Process," the finding was determined to be of very low safety significance
(Green) because Unit 2's current three-year rolling average collective dose for
2013-2015 is 39.69 person-rem, which is less than the criteria of 135 person-rem per
pressurized water reactor unit. The finding had a cross-cutting aspect in the area of
Human Performance, Work Management, in that the process of planning work activities
adversely impacted radiological safety. [H.5]
Enforcement. No violation of regulatory requirements occurred. The ALARA rule
(10 CFR 20.1101(b)) Statements of Consideration indicate that compliance with the
ALARA requirement will be judged on whether Entergy has incorporated measures to
track and, if necessary, to reduce exposures, and not whether exposures and doses
represent an absolute minimum or whether Entergy has used all possible methods to
30
reduce exposures. The overall exposure performance of a nuclear power plant is used
to determine its compliance with the ALARA rule. Since Unit 2s current three-year
rolling average is 39.69 person-rem, which is below the three-year rolling average
criterion of 135 person-rem per unit, and has an established ALARA program to reduce
exposure consistent with the 10 CFR 20.1101 Statements of Consideration, no violation
of 10 CFR 20.1101(b) occurred. Entergy entered this issue into their CAP as
CR-IP2-2016-02528, CR-IP2-2016-02502, and CR-IP2-2016-02548. Because this issue
does not involve a violation and has very low safety significance, it is identified as a
finding. (FIN 05000247/2016003-05, Failure to Maintain Radiation Exposure ALARA
During Unit 2 Reactor Cavity Liner Repairs)
2RS4 Occupational Dose Assessment (71124.04 - 5 samples)
a. Inspection Scope
The inspectors reviewed the monitoring, assessment, and reporting of occupational
dose. The inspectors used the requirements in 10 CFR 20, RG 8.9, RG 8.34, TSs, and
procedures required by TSs as criteria for determining compliance.
Inspection Planning
The inspectors reviewed radiation protection program audits, National Voluntary
Laboratory Accreditation Program (NVLAP) dosimetry testing reports, and procedures
associated with dosimetry operations.
Source Term Characterization (1 sample)
The inspectors reviewed the plant radiation characterization (including gamma, beta,
alpha, and neutron) being monitored. The inspectors verified the use of scaling factors
to account for hard-to-detect radionuclides in internal dose assessments.
External Dosimetry (1 sample)
The inspectors reviewed dosimetry NVLAP accreditation, onsite storage of dosimeters,
the use of correction factors to align electronic personal dosimeter results with NVLAP
dosimetry results, dosimetry occurrence reports, and CAP documents for adverse trends
related to external dosimetry.
Internal Dosimetry (1 sample)
The inspectors reviewed internal dosimetry procedures, whole body counter
measurement sensitivity and use, adequacy of the program for whole body count
monitoring of plant radionuclides or other bioassay technique, adequacy of the program
for dose assessments based on air sample monitoring and the use of respiratory
protection, and internal dose assessments for any actual internal exposure.
Special Dosimetric Situations (1 sample)
The inspectors reviewed Entergys worker notification of the risks of radiation exposure
to the embryo/fetus, the dosimetry monitoring program for declared pregnant workers,
31
external dose monitoring of workers in large dose rate gradient environments, and dose
assessments performed since the last inspection that used multi-badging, skin dose, or
neutron dose assessments.
Problem Identification and Resolution (1 sample)
The inspectors evaluated whether problems associated with occupational dose
assessment were identified at an appropriate threshold and properly addressed in the
CAP.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151 - 8 samples)
Mitigating Systems Performance Index
a. Inspection Scope
The inspectors reviewed Entergys submittals for the following Mitigating Systems
Cornerstone performance indicators for the period of July 1, 2015, through June 30,
2016:
Unit 2
Emergency AC Power System (MS06)
High Pressure Injection System (MS07)
Heat Removal System (MS08)
Residual Heat Removal System (MS09)
Unit 3
Emergency AC Power System (MS06)
High Pressure Injection System (MS07)
Heat Removal System (MS08)
Residual Heat Removal System (MS09)
To determine the accuracy of the performance indicator data reported during those
periods, the inspectors used definitions and guidance contained in Nuclear Energy
Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 7. The inspectors also reviewed Entergys operator narrative logs, CRs,
mitigating systems performance index derivation reports, event reports, and NRC
integrated inspection reports to validate the accuracy of the submittals.
b. Findings
No findings were identified.
32
4OA2 Problem Identification and Resolution (71152)
Routine Review of Problem Identification and Resolution Activities
a. Inspection Scope
As required by Inspection Procedure 71152, Problem Identification and Resolution, the
inspectors routinely reviewed issues during baseline inspection activities and plant
status reviews to verify that Entergy entered issues into the CAP at an appropriate
threshold, gave adequate attention to timely corrective actions, and identified and
addressed adverse trends. In order to assist with the identification of repetitive
equipment failures and specific human performance issues for follow up, the inspectors
performed a daily screening of items entered into the CAP and periodically attended CR
review group meetings. The inspectors also confirmed, on a sampling basis, that, as
applicable, for identified defects and non-conformances, Entergy performed an
evaluation in accordance with 10 CFR 21.
b. Findings
No findings were identified.
4OA3 Follow Up of Events and Notices of Enforcement Discretion (71153 - 3 samples)
.1 Plant Event
a. Inspection Scope
On July 6, 2016, Unit 2 experienced a reactor trip caused by a human performance
error. The inspectors reviewed and observed plant parameters, reviewed personnel
performance, and evaluated performance of mitigating systems. The inspectors
communicated the plant status to appropriate regional personnel and compared the
event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for
Reactors, for consideration of potential reactive inspection activities. The inspectors
verified that Entergy properly reported the event in accordance with 10 CFR 50.72 and
50.73. The inspectors reviewed Entergys follow-up actions related to the events to
assure that Entergy implemented appropriate immediate corrective actions
commensurate with their safety significance.
b. Findings
No findings were identified.
.2 (Closed) Licensee Event Report (LER) 05000247/2016-005-00: TS Prohibited Condition
Due to a Surveillance Requirement (SR) Never Performed for Testing the Trip of the
On March 26, 2016, an NRC inspector identified that the trip of the MBFPs was not
tested in accordance with TS 3.7.3 (Main Feedwater System) SR 3.7.3.3. This
performance deficiency was discovered as a result of an assessment of the failure of the
MBFPs steam stop valves to close after the reactor trip on December 5, 2015. TS
SR 3.7.3.3 required testing the MBFP trip function every 24 months on an actual or
33
simulated actuation signal. Surveillance tests 2-PT-V024DS60 and 2-PT-V24DS61 were
performed every 24 months, but only tested up to the limit switch contact that actuates
the MBFP turbine trip solenoid valves and did not include the trip function of the pump.
A review determined the requirement to verify the trip of the MBFPs was added to the
TS during the implementation of the improved TS conversion program in 2000 but the
corresponding testing for MBFP trip was not added to the surveillance tests. The
condition was recorded in the Entergys CAP in CR-IP2-2016-02247.
The inspectors previously issued a Green NCV of TS 3.7.3 for failing to conduct required
surveillance testing on the MBFP trip function as required by SR 3.7.3.3 in NRC
Integrated Inspection Report 05000247/2016001. There was no evidence that the
MBFP trip function had ever been tested and, therefore, did not qualify for treatment as a
missed surveillance under SR 3.0.3. (NCV 05000247/2016001-04, Failure to Implement
SR for MBFP Trip Function)
The inspectors did not identify any new issues during the review of the LER. This LER is
closed.
.3 (Closed) LER 05000247/2016-006-00: TS Prohibited Condition Due to Inoperable
138kV Offsite Circuits Caused by a Disconnected SI Signal to the Station Auxiliary
Transformer LTC
The inspectors reviewed Entergys actions and reportability criteria associated with LER
05000247/2016-006-00, which was submitted to the NRC on May 27, 2016. On
March 9, 2016, during shutdown for a refueling outage, while performing testing of the SI
system, the station SAT LTC failed to increase per design upon actuation of an SI signal.
At the time, the condition was acceptable for the current mode but was unacceptable
when the offsite AC electric power distribution and SI system is required to be operable.
An investigation was performed and it was discovered on March 28, 2016, that the SAT
control cabinet terminal blocks Wl05 and Wl06 had their links open thereby preventing
proper operation of the LTC. A review of tests and WO did not identify any previous
failed tests or any WO with instructions to open the links. The last successful test of LTC
operation was performed on February 26, 2014. The inspectors reviewed the LER, the
associated apparent cause evaluation analysis, and interviewed Entergy staff.
Introduction. The inspectors identified a self-revealing, Green NCV for failing to comply
with TS LCO 3.8.1, Electrical Power Systems, AC Sources - Operating, from
February 26, 2014, to March 29, 2016. During this time, the auto transfer function for
the 6.9kV offsite electrical buses was not operable because the SI anticipatory signal to
the SAT LTC was disconnected. As a result, one of two qualified offsite AC circuits was
not operable.
Description. On March 9, 2016, Entergy discovered that the SAT LTC failed to increase
voltage as designed in response to an SI signal during the performance of surveillance
test 2-PT-R013, SI System, in Mode 5. Unit 2 conducted the loss of normal power
surveillance test by manually actuating the SI signal from the control room. Test results
revealed that the SAT LTC would not adjust to raise bus voltage in anticipation of the
fast transfer of vital buses from the unit auxiliary transformer (UAT) to the SAT. Upon
initiation of an SI signal, the SAT LTC was designed to raise bus voltage within 30
seconds in anticipation of the fast transfer of the vital buses 1 through 4 to buses 5 and 6
when loads are transferred from the UAT to the SAT and safeguards loads are
34
sequenced in. This anticipatory auto transfer feature is required to be operable by TS
LCO 3.8.1 whenever the 138kV offsite line is supplying buses 5 and 6 through the SAT
and buses 1, 2, 3, and 4 are supplied from the UAT in modes 1 through 4. With the
as-found LTC condition, an event resulting in an SI and fast bus transfer could cause the
secondary voltage to drop below the degraded voltage setpoint for more than
10 seconds, resulting in a separation of the safety buses from offsite power.
On March 28, 2016, while in mode 6, Entergy identified that the state links (W105 and
W106) that connected the SI anticipatory signal to the SAT LTC were disconnected. A
document review over a two-year period did not identify any WOs or other activities
which directed these links to be opened. Entergy concluded that the most likely cause
was human error during the last outage, 2RFO21, when workers apparently left the links
in the open position following maintenance activities. The last successful test of the SAT
LTC was conducted on February 26, 2014. Entergy closed the links and reinstituted to
the SAT LTC SI anticipatory signal protective feature prior to entering mode 4. Entergy
also implemented corrective actions to maintenance procedures to require and
troubleshooting WOs to require concurrent verification that equipment was restored to
the proper configuration.
The failure to reinstitute the anticipatory SI signal to the SAT LTC increased the
likelihood that a LOOP to the vital buses during a fast dead bus transfer would occur if a
reactor trip and SI had actuated. If the reduction in vital bus voltage caused the
degraded voltage relay(s) to actuate during a fast transfer and during the period when
safeguards loads were sequenced onto the safety buses, the associated EDGs (which
would have already started on the SI signal) would have automatically stripped and
resequenced the safety loads onto the vital bus, which would then be powered directly
from the EDGs. In addition, the SAT LTC would have responded in automatic control to
the voltage transient and may have responded adequately to prevent a reduction in
voltage during the loss of normal power test on March 9, 2016.
A note in TS 3.8.1 states The automatic transfer function for the 6.9kV buses shall be
operable whenever the 138kV is supplying 6.9kV bus 5 and 6 and the UAT is supplying
6.9kV bus 1, 2, 3, and 4. UFSAR section 7.5.2.1.12.1 further states, The LTC is used
to maintain the nominal voltage level on the SATs 6.9kV buses by automatically raising
or lowering the SAT secondary winding taps in response to voltage variations on the
6.9kV buses. During an SI event, the SI anticipatory signal will raise the LTC tap
position, increasing the voltage towards a pre-selected voltage, in anticipation of the
increased loads from the fast transfer of the loads held by the four 6.9kV in-house buses
to the SAT, thus reducing the severity of a degraded voltage condition on the 480V and
6.9kV buses. As a result, Entergy concluded that TS 3.8.1(a) was not met because the
state links were not installed.
Analysis. The failure to reinstall the state links (W105 and W106) following maintenance
activities was a performance deficiency that was within Entergys ability to foresee and
prevent. Specifically, since February 2014, the SI anticipatory signal to the SAT LTC
was nonfunctional. TS 3.8.1 requires this signal to be functional in order for the
associated offsite AC source to be operable. This performance deficiency was more
than minor because it is associated with the Equipment Performance attribute of the
Mitigating Systems cornerstone to ensure the availability, reliability, and capability of
systems that respond to initiating events to prevent undesirable consequences (i.e., core
damage). Using IMC 0609, Appendix A, The Significance Determination Process for
35
Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, this issue
required a DRE because the loss of the SI anticipatory function may have resulted in the
SAT being unavailable under low or degraded grid voltage conditions and the second
qualified offsite AC power line was therefore inoperable for a period longer than the TS
allowable outage time. A Region I SRA completed a DRE using the Unit 2 SPAR model
and qualitative analysis. The following assumptions were used in the SPAR model
analysis: 1) an exposure period one year (maximum length of time per significance
determination process guidance), 2) to mimic the LTC OOS (plant design feature not
modeled) the failure probability of the SAT basic event (ACP-TFM-SAT) was increased
from 2.27E-5 to 2.27E-4 (one order of magnitude) to represent the increased likelihood
of the SAT being rendered unavailable due to a low grid voltage condition, 3) truncation
was left at 1E-11, and 4) SAT recovery credit was not provided, although the SAT could
be manually restored to service following initial electrical plant stabilization using the
EDGs to restore power to the safety buses. Based upon these conservative modeling
assumptions and the condition under which the SI anticipatory signal would be relied
upon (a coincident loss of coolant accident and SI actuation), the safety significance of
this issue is less than E-8/year or very low safety significance (Green). The dominant
sequences involve a loss of coolant accident and failure of the EDGs.
The inspectors determined that the finding had a cross-cutting aspect of Human
Performance, Work Management, because Entergy did not implement a process of
controlling and executing work activities. Specifically, the work process did not
coordinate with different groups or job activities to ensure the state links were restored at
the end of the work activities. [H.5]
Enforcement. TS 3.8.1 requires two offsite AC electrical sources to be operable when in
modes 1 through 4. A note in TS 3.8.1 requires the automatic transfer function for the
6.9kV buses to be operable in modes 1 through 4 whenever the 138kV is supplying
6.9kV bus 5 and 6 and the UAT is supplying 6.9kV bus 1, 2, 3, and 4. The UFSAR
concludes that the SAT LTC SI signal feature is required to support the automatic
transfer function. Contrary to this requirement, the automatic transfer function was not
operable from February 26, 2014, until March 29, 2016. Unit 2 was operating in Mode 1
for most of this time. Entergy entered this condition into their CAP (CR-IP2-2016-01386
and CR-IP2-2016-02293) and restored the SAT LTC anticipatory SI signal by closing the
state links W105 and W106. This finding was of very low safety significance and was
documented in Entergys CAP. Therefore, this violation is being treated as an NCV,
consistent with section 2.3.2.a of the NRC Enforcement Policy.
(NCV 05000247/2016003-06, Failure to Maintain Two Qualified AC Sources of
Offsite Power)
This LER is closed.
4OA5 Other Activities
.1 Groundwater Contamination
a. Inspection Scope
In February 2016, Entergy notified the NRC of a significant increase in groundwater
tritium levels measured at three monitoring wells (MW-30, MW-31, and MW-32) located
36
near the Unit 2 FSB. In August 2016, Entergy notified the NRC of the detection of
Cobalt-58 measured in MW-32 located near the Unit 2 FSB.
b. Findings and Observations
(Closed) URI 05000247/2016001-07: January 2016 Groundwater Contamination
Introduction. The inspectors identified a Green NOV of 10 CFR 20.1406(c) for Entergys
failure to conduct operations to minimize the introduction of residual radioactivity into the
subsurface of the site (groundwater). Specifically, Entergy has not maintained the floor
drain systems clear of obstructions and interferences and has not verified the ability of
the floor drains to handle the volume and flowrates for draining activities being
conducted. As a result, repeated spills of contaminated water within the RCA leaked to
onsite groundwater. Two previous occurrences in April 2014 (NRC Inspection Report 05000247/2015002) and February 2015 (NRC Inspection Report 05000247/2015003)
resulted in a licensee-identified Green NCV and an NRC-identified Green NCV. This
inspection report documents two additional similar floor drain backup spill events that
resulted in groundwater contamination that are the subject of this violation. Specifically,
on January 2016, a spill caused by multiple floor drain obstructions resulted in the
backup of contaminated water onto the floor of the 35-foot elevation of the PAB and the
subfloor of the Unit 2 FSB with subsequent leakage to onsite groundwater. In June/July
2016, another event occurred due to an obstructed flow path through a floor drain in the
FSB, which spilled to the subfloor and contaminated the onsite groundwater.
Description. This violation involves two separate incidents of contaminated water spills
that resulted in groundwater contamination due to poor floor drain management. The
first incident involved a January 2016 groundwater contamination event. The inspectors
previously identified a URI regarding whether Entergys controls to prevent the
introduction of radioactivity into the site groundwater for this occurrence were adequate.
Specifically, Entergy obtained increased tritium concentrations from onsite groundwater
monitoring well samples in January 2016 indicating that a leak or spill had occurred
allowing the introduction of radioactivity into the subsurface of the site. Entergy entered
this issue into their CAP as CR-IP2-2016-00264, CR-IP2-2016-00266, and CR-IP2-
2016-00564 with actions to characterize and evaluate this new leak. The initial Entergy
investigation focused on identifying the source of the contamination which was
preliminarily determined to originate from the reject water of a reverse osmosis (RO) skid
that was in service from January 16-31, 2016. This causal determination was based on
the timing of the groundwater contamination event and based on the unique matching of
the radionuclide signature from the groundwater samples and the RO skid reject water.
Based on subsequent completion of Entergys root cause evaluation, the URI can be
evaluated and assessed. Two pathways to the site subsurface were identified. One
pathway was the floor drain pathway in the PAB from below the RO unit to the PAB
sump, where multiple drain obstructions led to spillage from two uncapped cut drain lines
located above the floor on the 35-foot elevation of the PAB, and leakage to the
subsurface from the floor wall interface on the 35-foot elevation of the PAB. The second
cause was attributed to filling the Unit 2 radiological waste sump 28 until it backed up
into the subfloor of the Unit 2 FSB truck bay and subsequently leaked out into the
ground, contaminating the groundwater. This was attributed to rerouting a drain path for
the RO skid reject water into a floor drain with a higher operating level in radiological
waste sump 28 that caused backup into a subfloor drain channel into the subfloor of the
37
Unit 2 FSB truck bay. This condition was the result of an inoperable radiological waste
pump and a temporary drain path arrangement that was not fully evaluated to prevent
potential groundwater contamination spills.
Regarding the second groundwater contamination incident, on August 10, 2016, Entergy
notified the NRC of the detection of Co-58 in monitoring well MW 32-59 located near the
Unit 2 FSB. This sample was drawn on July 5, 2016, and analyzed on the week of
August 1, 2016. The concentration detected was 76.7 pCi/l. This event was
documented by Entergy in CR-IP2-2016-05060. Following identification of Co-58 in the
well sample, Entergy directed its vendor laboratory to recount the sample, and to also
immediately send off the next sample taken from MW 32-59, on July 18, 2016, for
analysis. The sample recount, together with the counting of the July 18, 2016, sample,
confirmed the presence of Co-58. No increase in tritium concentration was seen at
MW 32 on either of these dates. The Entergy groundwater team, previously assembled
for the January 2016 event (described above), began investigating the cause of this new
leak. The presence of Co-58 was determined to be indicative of reactor coolant, due to
its relatively short half-life. Since Unit 2 had recently (in June 2016) completed a
refueling outage, the source of the leak could also have been from the spent fuel pool,
as the two systems were connected throughout the refueling outage. Previously, on
July 19, 2016, in CR-IP2-2016-04559, Entergy had identified high levels of
contamination in the Unit 2 FSB truck bay subfloor as part of their investigation into the
leakage path for the January 2016 event. Analysis of this contamination revealed the
presence of Co-58.
Entergys investigation focused on examination of the source of the contamination with a
pathway from the Unit 2 FSB truck bay subfloor. Based on this investigation, Entergy
identified that in June 2016 following conclusion of the Unit 2 refueling outage, the spent
fuel pool alternate decay heat removal system was drained to sump 28. This equipment
contained spent fuel pool water and could, therefore, have been the source of the Co-58
contamination. Review of the drainage pathway from the system to sump 28 identified
that the system was drained by pumping its contents to a floor drain located on the west
side of the Unit 2 FSB truck bay, with that drain going to sump 28. Further analysis
identified that the floor drain used was partially blocked by the presence of another large
temporary drain line previously used during the 2015 dry fuel cask storage project. The
presence of this second line going into the floor drain significantly reduced the capacity
of the drain, resulting in the alternate decay heat removal liquids backing up inside the
drain system, back-flowing into the north crane rail sole plate, and then spilling onto the
Unit 2 FSB truck bay subfloor, which was already identified as a known leakage pathway
to groundwater. This pathway was confirmed by Entergy based on the high
contamination levels detected in the north crane rail sole plate and the FSB truck bay
subfloor, including the presence of Co-58.
The NRC assessment of the safety significance of these events focused on validating
the safety impact of dose to the public from the release of tritium and Co-58 to the site
groundwater, and ultimately to the Hudson River. The NRC verified that Entergys
bounding public dose calculations on the groundwater contamination leaks were
sufficiently conservative, and a maximum worst case scenario would result in 0.000112
millirem (mrem) per year, which represents a very small fraction of the allowable dose
(liquid effluent dose objective of 3 mrem per year).
38
Analysis. The failure to conduct operations to minimize the introduction of residual
radioactivity into the subsurface of the site, as required by 10 CFR 20.1406(c), is a
performance deficiency within Entergys ability to foresee and correct and should have
been prevented. Specifically, two events involving the leakage of contaminated water to
the onsite groundwater occurred due to Entergys failure to control and maintain its floor
drain systems clear of obstructions and interferences and to verify their ability to handle
the volume and flowrates for draining activities being conducted.
The issue is more than minor because it is associated with the Program and Process
attribute of the Public Radiation Safety cornerstone and adversely affected the
cornerstone objective to ensure Entergys ability to prevent inadvertent release and/or
loss of control of licensed material to an unrestricted area due to the actual
contamination of groundwater that occurred. In accordance with IMC 0609, Appendix D,
"Public Radiation Safety Significance Determination Process," the finding was
determined to be of very low safety significance (Green) because Entergy had an issue
involving radioactive material control but did not involve transportation or public
exposure in excess of 0.005 Rem.
In accordance with IMC 0310, Aspects within the Cross-Cutting Areas, dated
December 4, 2014, the finding had a cross-cutting aspect in the area of Problem
Identification and Resolution, Resolution, in that effective corrective actions to address
issues identified in two previous groundwater leaks since 2014 were not implemented in
a timely manner, which could have prevented this leak. [P.3]
Enforcement. 10 CFR 20.1406(c) requires, in part, that licensees shall, to the extent
practical, conduct operations to minimize the introduction of residual radioactivity into the
site, including the subsurface. Contrary to the above, on two occasions between
January 2016 and July 2016, Entergy failed to conduct operations to minimize the
introduction of residual radioactivity into the subsurface of the site. Specifically, Entergy
has not maintained its floor drain system clear of obstructions and interferences and has
not verified the ability of the floor drains to handle the volume and flowrates for draining
activities being conducted. As a result, repeated spills of contaminated water within the
RCA leaked into the site groundwater. Specifically, in January 2016, a spill caused by
floor drain obstructions resulted in the backup of contaminated water onto the floor and
subsequent leakage to the subsurface of the site. A subsequent June/July 2016
groundwater contamination event occurred due to an obstructed flow path through a
floor drain in the Unit 2 FSB, which spilled to the subfloor and contaminated the
subsurface of the site.
Entergys immediate corrective actions included decontamination of the adversely
affected plant areas, revision of the operating procedure for radiological waste sump 28,
and sealing the Unit 2 FSB subfloor to make it water tight to prevent further groundwater
contamination from this location. Entergys planned corrective action to address the
existing groundwater contamination is the start-up and operation of a recovery well
system (RW-1). The system will allow for the collection of contaminated groundwater to
be returned inside the PAB for processing.
This violation meets the criteria in Section 2.3.2.a of the NRC Enforcement Policy to
disposition as an NCV. However, the NRC considered that in April 2014 (NRC
Inspection Report 05000247/2015002) and again in February 2015 (NRC Inspection
Report 05000247/2015003), Entergy also had contaminated water spills inside the RCA
39
which leaked to groundwater due to blockages in the Unit 2 floor drain system.
Entergys corrective actions for these previous occurrences were limited to clearing the
specific floor drains involved in the flow paths for each event. The NRC concluded that
Entergys actions for these most recent events, while similarly responsive to the specific
occurrences, do not adequately address the broader concern regarding a lack of control
and management of the site floor drain system. Therefore, the NRC is issuing a NOV
and is requiring a response from Entergy that describes a more comprehensive CAP for
maintaining an effective floor drain system and a process for evaluating and using the
floor drains to handle the volume and flowrates for draining activities being conducted.
The NOV is enclosed (Enclosure 1). (VIO 05000247/2016003-07, Inadequate Control
of Floor Drains to Minimize Groundwater Contamination)
This URI is closed.
.2 (Closed) URI 05000247/2016002-01, CVCS Goal Monitoring Under the Maintenance
Rule
a. Inspection Scope
During the 2nd quarter of 2016, the inspectors identified issues of potential concern with
Entergys application of 10 CFR 50.65(a)(1), Requirements for Monitoring the
Effectiveness of Maintenance at Nuclear Plants, in regards to the reliability of the Unit 2
chemical and volume control system (CVCS). These concerns included the
establishment of appropriate (a)(1) goals and whether appropriate justification was
established that the corrective actions to address identified maintenance weaknesses
were effective prior to removal from (a)(1) status. A URI (05000247/2016002-01) was
identified because additional NRC review and evaluation was needed to determine
whether three identified issues of concern represented performance deficiencies and
whether they were more than minor. The inspectors further evaluated the issues and
reviewed against 10 CFR 50.65, Requirements for monitoring the effectiveness of
maintenance at nuclear power plants; NUMARC 93-01, Industry guideline for monitoring
the effectiveness of maintenance at nuclear power plants, Revision 4A; EN-DC-206,
Maintenance Rule (a)(1) Process, Revision 3; and NRC Enforcement Manual, Revision
9.
For two issues of concern identified in URI 05000247/2016002-01, the inspectors
determined that Entergys goals established for each of the issues were adequate to
provide reasonable assurance that system components would perform their intended
function on demand in accordance with the requirements of 10 CFR 50.65. For these
two issues, the inspectors determined that Entergy placed the CVCS system in
Maintenance Rule (a)(1) status and established goals to monitor performance. The
goals were adequate to provided reasonable assurance that system components would
perform their intended function. Therefore, no violation of 10 CFR 50.65(a)(1) occurred.
However, the inspectors identified weaknesses in the narrowness of the scope, the
applicable time periods, and the technical justification for the goals. The weaknesses
are as follows:
23 charging pump internal oil tube failure. Although 10 CFR 50.65 industry and site
guidance documents provide leeway in whether to establish system, train, or specific
component goals, the inspectors concluded that the goal on only the 23 charging
40
pump was narrowly focused and did not include similar conditions for the 21 and 22
charging pumps
22 charging pump check valve failure. Although 10 CFR 50.65 industry, and site
guidance documents provide latitude on the number of surveillances and
occurrences to monitor in accordance with your goal, the inspectors concluded that
the goal with only one fill and vent maintenance activity was narrowly focused and
additional activities were not included
The third issue of concern involved a failure of the Unit 2 valve FCV-110A, boric acid
flow control valve, to fully open on January 5, 2015. The valve was insufficiently
insulated and, as a result, boron crystallized above the valve plug and blocked
movement. The inspectors reviewed the (a)(1) action plan for FCV-110A, which
specified a monitoring interval of six months to include the winter because previous
valve failures had all occurred during the winter months. The inspectors noted that the
action plan did not specify a goal and that the actual monitoring interval documented in
the corrective action was from April to October 2015 and, therefore, did not include the
winter months when failure would most likely occur. The inspectors determined that this
was not in accordance with EN-DC-206, Maintenance Rule (a)(1) Process, Section
5.5[3], which states, in part, that monitoring intervals should be long enough to detect
recurrence of the applicable failure mechanism and 5.3[4](h) which states, in part,
Goals should be quantifiable with specific limits, and trendable if practicable. In
addition, the inspectors determined that represented a violation of 10 CFR 50.65(a)(1),
Requirements for monitoring the effectiveness of maintenance at nuclear power plants,
because the failure to monitor the condition during the winter months against licensee
established goals, was a failure to monitor the performance of FCV-110A in a manner
sufficient to provide a reasonable assurance that the valve was capable of performing its
intended functions. This issue was determined to be a minor violation because the
reliability of FCV-110A and the CVCS was not impacted. Although, Entergys failed to
adequately monitor the performance FCV-110A, no valve performance issues or failures
occurred during the winter months following repair of the insulation. Consistent with the
NRC Enforcement Policy, Section 2.2.2, minor violations generally do not warrant
enforcement action but are required to be entered into the stations CAP and actions
taken to restore compliance. Entergy entered this issue into their CAP as CR-IP2-2017-
00084 for resolution.
URI 05000247/2016002-01 is closed.
b. Findings
No findings were identified.
41
4OA6 Meetings, Including Exit
On October 26, 2016, the inspectors presented the inspection results to Mr. Anthony
Vitale, Site Vice President, and other members of Entergy. On January 6, 2017, a
telephone call was conducted between Mr. Eugene DiPaolo, Acting Branch Chief,
Reactor Projects Branch 2, and Mr. Robert Walpole, Nuclear Safety Assurance
Manager, to clarify details associated with the closure of URI 05000247/2016002-01.
The inspectors verified that no proprietary information was retained by the inspectors or
documented in this report.
ATTACHMENT: SUPPLEMENTARY INFORMATION
A-1
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Entergy Personnel
A. Vitale, Site Vice President
J. Kirkpatrick, Plant Operations General Manager
R. Alexander, Unit 2 Shift Manager
N. Azevedo, Engineering Supervisor
K. Baumbach, Chemistry Supervisor
S. Bianco, Operations Fire Marshal
C. Bohrens, Unit 2 Shift Manager
R. Burroni, Engineering Director
T. Chan, Engineering Supervisor
R. Daley, Engineering Supervisor
D. Dewey, Unit 3 Assistant Operations Manager
R. Dolansky, ISI Program Manager
R. Drake, Civil Design Engineering Supervisor
J. Ferrick, Regulatory Assurance and Performance Improvement Director
D. Gagnon, Security Manager
L. Glander, Emergency Preparedness Manager
F. Kich, Performance Improvement Manager
M. Lewis, Unit 2 Assistant Operations Manager
N. Lizzo, Training Manager
B. McCarthy, Operations Manager
F. Mitchell, Radiation Protection Manager
E. Mullek, Maintenance Manager
E. Portanova, System Engineer I (Nuclear)
M. Tesoriero, System Engineering Manager
M. Troy, Nuclear Oversight Manager
R. Walpole, Regulatory Assurance Manager
Attachment
A-2
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened
05000247/2016003-07 VIO Inadequate Control of Floor Drains to Minimize
Groundwater Contamination (Section 4OA5)
Opened/Closed
05000286/2016003-01 NCV Failure to Adequately Assess Fire Risk
Associated with Maintenance on the Unit 3
Appendix R Diesel Generator (Section 1R13)05000247/2016003-02 NCV Missed Inspections on Automatic Voltage Regulator
Cards Results in Emergency Diesel Generator
Failure to Run (Section 1R15)05000286/2016003-03 NCV Untimely Corrective Actions to Address Degraded
Automatic Voltage Regulator Cards (Section 1R22)05000247/2016003-04 NCV Entry into a High Radiation Area without
Radiological Briefing (Section 2RS1)05000247/2016003-05 FIN Failure to Maintain Radiation Exposure ALARA
During Unit 2 Reactor Cavity Liner Repairs
(Section 2RS2)05000247/2016003-06 NCV Failure to Maintain Two Qualified AC Sources of
Offsite Power (Section 4OA3)
Closed
05000247/2016001-06 URI 23 EDG Automatic Voltage Regulator Failure
(Section 1R15)05000247/2016001-07 URI January 2016 Groundwater Contamination
(Section 4OA5)05000247/2016002-01 URI CVCS Goal Monitoring Under the Maintenance
Rule (Section 4OA5)
05000247/2016-005-00 LER TS Prohibited Condition Due to a SR Never
Performed for Testing the Trip of the MBFPs
(Section 4OA3)
05000247/2016-006-00 LER TS Prohibited Condition Due to Inoperable
138kV Offsite Circuits Caused by a Disconnected
SI Signal to the Station Auxiliary
Transformer LTC (Section 4OA3)
A-3
LIST OF DOCUMENTS REVIEWED
Common Documents Used
Indian Point Unit 2, UFSAR
Indian Point Unit 3, UFSAR
Indian Point Unit 2, Individual Plant Examination
Indian Point Unit 3, Individual Plant Examination
Indian Point Unit 2, Individual Plant Examination of External Events
Indian Point Unit 3, Individual Plant Examination of External Events
Indian Point Unit 2, TSs and Bases
Indian Point Unit 3, TSs and Bases
Indian Point Unit 2, Technical Requirements Manual
Indian Point Unit 3, Technical Requirements Manual
Control Room Narrative Logs
Plan of the Day
Section 1R01: Adverse Weather Protection
Procedures
OAP-008, Severe Weather Preparations, Revision 23
Condition Reports (CR-IP2-)
2016-04699
Section 1R04: Equipment Alignment
Procedures
2-COL-4.1.1, Component Cooling Water System, Revision 26
2-COL-21.3, Steam Generator Water Level and Auxiliary Boiler Feedwater, Revision 34
2-COL-31.2, Gas Turbine 2, Revision 7
2-COL-31.3, Gas Turbine 3, Revision 10
3-SOP-EL-013, ARDG Operation, Revision 30
COL-EL-6, ARDG, Revision 10
Drawings
9321-F-21213, Flow Diagram Appendix R 6.9kV EDG Fuel Oil System, Revision 6
9321-F-21203, Flow Diagram Appendix R 6.9kV EDG Lube Oil System, Revision 2
9321-F-21223, Flow Diagram Appendix R 6.9kV EDG Jacket Water System, Revision 3
Drawing 304122, GT-2/3 Fuel Forwarding System, Revision 7
Section 1R05: Fire Protection
Procedures
EN-TQ-125, Fire Brigade Drills, Revision 4
Condition Reports (CR-IP3-)
2016-03052
Miscellaneous
Transient Combustible Evaluation 16-017, Revision 1
A-4
Section 1R11: Licensed Operator Requalification Program
Procedures
2-POP-1.2, Reactor Startup, Revision 59
3-AOP-ROD-1, Rod Control and Indication System Malfunctions, Revision 3
3-E-0, Reactor Trip or SI, Revision 6
3-E-3, Steam Generator Tube Rupture, Revision 4
EN-OP-115, Conduct of Operations, Revision 17
Condition Reports (CR-IP3-)
2016-02892 2016-02899
Miscellaneous
Simulator Training Scenario I3SX-LOR-SES013, Letdown Line Rupture, Main Turbine
Generator Control Valve Shuts, Misaligned Rod, Steam Generator TR, Revision 4
Simulator Training Scenario LRQ-SES-ECA00A, Loss of 13.8/138kV (AOP-138kv-1) with
Subsequent Loss of Grid and Main Generator Trip (E-0) and Loss of All AC Power
(ECA-0.0, 0.1, 0.2), Following Turbine First Stage Press Instrument, PT412A,
(AOP-INST-1) Failure and Loss of MCC-28, Revision 9
Section 1R12: Maintenance Effectiveness
Procedures
EN-DC-153, Preventive Maintenance Component Classification, Revision 14
EN-DC-205, Maintenance Rule Monitoring, Revision 5
EN-LI-102, Corrective Action Program, Revision 27
EN-WM-100, Work Request Generation, Screening and Classification, Revision 13
Condition Reports (CR-IP3-)
2011-05686 2014-00544 2014-00700 2014-01678 2014-02338 2014-02579
2014-02661 2014-02696 2014-02753 2014-02762 2015-01751 2015-01961
2015-03009 2015-03456 2015-03522 2015-03779 2015-03838 2016-01352
2016-02339
Miscellaneous
Maintenance Rule Action Plan - Unit 3 Reactor Protection and Controls, 07/30/2015
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
EN-OP-119, Protected Equipment Postings, Revision 8
IP-SMM-WM-101, Fire Protection and Maintenance Rule (a)(4) Risk Assessment, Revision 5
Condition Reports (CR-IP3-)
2016-02267 2016-02538
Miscellaneous
Equipment Out-of-Service Risk Assessment Tool, Unit 3
A-5
Section 1R15: Operability Determinations and Functionality Assessments
Procedures
0-IC-SI-90-142, Digital Metal Impact Monitoring System (DMIMs) Baseline Recording Using
Calibrated Hammers, Revision 0
0-IC-SI-90-143, DMIMs Signal Conditioning Calibration, Revision 4
0-IC-SI-90-145, DMIMs Operational Test, Revision 3
2-SOP-1.9, DMIMS Operation, Revision 7
3-PT-V49, DMIM System Check, Revision 1
EN-OP-104, Operability Determination Process, Revision 11
RXC-B-023-A, Metal Impact Monitoring System Signal Conditioner Calibration (NSID-EIS-90-
143, Revision 4), Revision 0
RXC-B-024-A, Metal Impact Monitoring System Operational Test (NSID-EIS-90-145, Revision
4), Revision 0
Condition Reports (CR-IP2-)
2010-03316 2010-03773 2010-04545 2010-05677 2010-07126 2010-07468
2011-01205 2011-01266 2011-03693 2012-03453 2012-04766 2012-06131
2012-07266 2013-01009 2013-02540 2014-01718 2014-02261 2014-02550
2014-02653 2014-02738 2014-05812 2014-05813 2014-05816 2016-01260
2016-01500 2016-03360 2016-03525 2016-03800 2016-03856 2016-04764
2016-05220 2016-05418 2016-05442 2016-05444 2016-05528 2016-05757
Condition Reports (CR-IP3-)
2016-01370 2016-02551 2016-02910 2016-02961 2016-03018
Maintenance Orders/Work Orders
WO 130432 WO 130454 WO 130456 WO 130460 WO 130462 WO 446386
Miscellaneous
Report of Defect per 10 CFR 21, Basler Electric SBSR AVR Card Solder Joints, dated
September 21, 2007
Safety Evaluation by the Office of Nuclear Reactor Regulation Related to the Elimination of
Large Primary Loop Ruptures as a Design Basis, Power Authority of the State of New York,
Indian Point Nuclear Generating Unit No. 3, Docket No. 50-286, dated March 10, 1986
Supplement to Safety Evaluation by the Office of Nuclear Reactor Regulation Regarding
Leakage Detection Capability in Elimination of Large Primary Loop Ruptures as a Design
Basis, Indian Point Nuclear Generating Unit No. 3, Docket No. 50-286, dated January 30,
2002
Westinghouse Proprietary Letter (RIDA 16-152)
Section 1R18: Plant Modifications
Procedures
EN-DC-112, Engineering Change Request Process, Revision 8
EN-DC-115, Engineering Change Process, Revision 18
EN-DC-136, Temporary Modifications, Revision 12
EN-DC-136, Temporary Modifications, Revision 13
EN-LI-100, Process Applicability Determination, Revision 18
Condition Reports (CR-IP2-)
2016-05311
A-6
Condition Reports (CR-IP3-)
2016-02937
Maintenance Orders/Work Orders
WO 00454240-02 WO 00454240-03 WO 52713002
Miscellaneous
Engineering Change (EC) 66780, Temporary Modification to Install Jumpers in Order to
Maintain Bus 5A Interlocking
EC 65773, Replace ARDG Battery Charger
Relay Circuit While Relay 62-2/5A Is Replaced
MCENPC23, Battery Charger Users Manual, Revision 2.2
Temp Mod No. 66349, Temp Modification to Preserve Structural Integrity of Battery 23 Cell
Jar No. 4
TMCN 66790, Clarification for Connection of Temp Jumpers to Maintain Daisy chain
TMCN 66801, Alternate Connection Point for One of Temp Jumpers to Maintain Daisy chain
Section 1R19: Post-Maintenance Testing
Procedures
2-PT-Q030A, 21 Component Cooling Water Pump, Revision 19
3-GNR-028-ELC, ARDG 4-Year Inspection, Revision 8
3-GNR-036-ELC, ARDG Semi-Annual Inspection, Revision 8
3-PT-M66, Appendix R Diesel Battery Inspection, Revision 21
3-PT-Q139, ARDG Functional Test, Revision 1
Condition Reports (CR-IP2-)
2016-05742 2016-05777 2016-05795
Maintenance Orders/Work Orders
WO 00311837 WO 445129 WO 456276 WO 52509887
WO 52516076 WO 52680382 WO 52713002
Miscellaneous
EC 65773, Replace ARDG Battery Charger
Section 1R22: Surveillance Testing
Procedures
2-PT-Q034, 22 Auxiliary Feed Pump, Revision 30
3-PT-M079A, 31 EDG Functional Test, Revision 51
3-PT-Q062A, 31 Charging Pump Operability Test, Revision 17
3-PT-Q98C, Steam Line Pressure Functional Test - Channel III, Revision 8
Condition Reports (CR-IP3-)
2016-02881
A-7
Maintenance Orders/Work Orders
WO 00446386 WO 52699018 WO 52699700
Miscellaneous
3-PT-Q062A, 31 Charging Pump Operability Test, completed August 24, 2016
IP3-CALC-ESS-00276, Instrument Loop Accuracy/Setpoint Calculation - Steam Line Pressure
(Low) and Steam Line Delta P (High), Revision 2
MB-2007-01, Potential for Solder Joint Cracks on Basler SBSR AVR Cards and Technical
Manual Addendum TM-2007-01, dated November 5, 2007
Section 1EP6: Drill Evaluation
Condition Reports (CR-IP3-)
2016-02892 2016-02894 2016-02895 2016-02899
Miscellaneous
Drill Scenario
Section 2RS2: Occupational ALARA Planning and Controls
Condition Reports (CR-IP2-)
2016-02502 2016-02528 2016-02548
Miscellaneous
Indian Point 2 Refueling Outage 22 ALARA Report
ALARA Committee Meeting Minutes for: March 29, 2016, April 5, 2016, April 6, 2016, April 8,
2016, April 12, 2016, May 2, 2016, and June 14, 2016
Section 2RS4: Occupational Dose Assessment
Procedures
EN-RP-204, Special Monitoring Requirements, Revision 10
EN-RP-204-01, Effective Dose Equivalent Monitoring, Revision 0
EN-RP-205, Prenatal Monitoring, Revision 3
EN-RP-207, Planned Special Exposures, Revision 3
EN-RP-314, Passive Monitoring Sensitivity Tests, Revision 0
Miscellaneous
NVLAP Personnel Dosimetry Performance Testing for Landauer, Inc., 2016
Section 4OA1: Performance Indicator Verification
Procedures
EN-LI-114, Regulatory Performance Indicator Process, Revision 7
Section 4OA2: Problem Identification and Resolution
Procedures
CEP-NDE-0255, Radiographic Examination for ASME Welds and Components, ASME
Section XI, Revision 8
CEP-NDE-0404, (PDI UT-1) Manual Ultrasonic Testing of Ferritic Piping Welds (ASME XI),
Revision 5
A-8
Welding Procedure Specification,134 F42 MN-GTAW, Manual Gas Tungsten Arc Welding,
Revision 0
Condition Reports (CR-IP2)
2015-05755 2016-03818 2016-04085 2016-05358 2016-05503
Condition Reports (CR-IP3)
2015-05136 2016-01113
Maintenance Orders/Work Orders
Miscellaneous
Engineering Standard - Pipe Wall Thinning Structural Evaluation, Revision 0
Indian Point Energy Center NRC Generic Letter 89-13 SW Program, Revision 6
SW System Health Reports, IP Unit 2 and IP Unit 3, Second Quarter 2016
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
Procedures
2-PT-V024-DS060, Valve BFD-2-21 IST Data Sheet, Revision 10
Condition Reports (CR-IP2-)
2015-05459 2016-02247
Drawings
9321-3140 Sheet 12, Boiler Feed Pump No. 22 Turbine Trip and Reset, Revision 34
IP2_SOD_013, Feedwater System, Revision 2
Miscellaneous
LER 05000247/2016-005-00, TS Prohibited Condition Due to a Surveillance Requirement Never
Performed for Testing the Trip of the MBFP
LER 05000247/2016-006-00, TS Prohibited Condition Due to Inoperable 138kV Offsite Circuits
Caused by a Disconnected SI Signal to the Station Auxiliary Transformer LTC
Section 4OA5: Other Activities
Condition Reports (CR-IP2-)
2016-00264 2016-00266 2016-00564 2016-04559 2016-05060
Miscellaneous
Root Cause Evaluation for CR-IP2-2016-00564
A-9
LIST OF ACRONYMS
10 CFR Title 10 of the Code of Federal Regulations
ABFP auxiliary boiler feedwater pump
AC alternating current
ALARA as low as is reasonably achievable
ARDG Appendix R diesel generator
AVR automatic voltage regulator
CAP corrective action program
CCW component cooling water
CR condition report
CVCS chemical and volume control system
DRE detailed risk evaluation
EDG emergency diesel generator
FSB Fuel Storage Building
HP health physics
ICCDP incremental conditional core damage probability
IMC Inspection Manual Chapter
kV kilovolt
LCO limiting condition of operation
LER licensee event report
LOOP loss of offsite power
LTC load tap changer
MBFP main boiler feedwater pump
NCV non-cited violation
NOV notice of violation
NPO nuclear plant operator
NVLAP National Voluntary Laboratory Accreditation Program
NRC Nuclear Regulatory Commission, U.S.
OOS out of service
PAB primary auxiliary building
PFP pre-fire plan
PORV power operated relief valve
RCA radiologically controlled area
RG regulatory guide
RMA risk mitigating action
RO reverse osmosis
RWP radiation work permit
SAT station auxiliary transformer
SI safety injection
SPAR standardized plant analysis risk
SR surveillance requirement
SRA senior reactor analyst
SSC structure, system, and component
TS technical specification
UAT unit auxiliary transformer
UFSAR updated final safety analysis report
URI unresolved item
WO work order