ML16133A448
| ML16133A448 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 05/12/2016 |
| From: | Glenn Dentel Reactor Projects Branch 2 |
| To: | Coyle L Entergy Nuclear Operations |
| Dentel G | |
| References | |
| IR 2016001 | |
| Download: ML16133A448 (50) | |
See also: IR 05000247/2016001
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BLVD., SUITE 100
KING OF PRUSSIA, PA 19406-2713
May 12, 2016
Mr. Larry Coyle
Site Vice President
Entergy Nuclear Operations, Inc.
Indian Point Energy Center
450 Broadway, GSB
Buchanan, NY 10511-0249
SUBJECT: INDIAN POINT NUCLEAR GENERATING - INTEGRATED INSPECTION
REPORT 05000247/2016001 AND 05000286/2016001
Dear Mr. Coyle:
On March 31, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection
at your Indian Point Nuclear Generating (Indian Point), Units 2 and 3. The enclosed inspection
report documents the inspection results, which were discussed on April 29, 2016, with you and
other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report documents one self-revealing finding and two NRC-identified findings of very low
safety significance (Green). These findings involved violations of NRC requirements. However,
because of the very low safety significance and because they are entered into your corrective
action program, the NRC is treating these findings as non-cited violations, consistent with
Section 2.3.2.a of the NRC Enforcement Policy. If you contest any non-cited violation in this
report, 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, U.S. Nuclear Regulatory Commission, Washington, DC
20555-0001; and the NRC Senior Resident Inspector at Indian Point. In addition, if you
disagree with the cross-cutting aspect assigned to any finding in this report, you should provide
a response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region I, and the NRC Senior Resident Inspector
at Indian Point.
L. Coyle -2-
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs
Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be
available electronically for public inspection in the NRCs Public Document Room or from the
Publicly Available Records component of the NRCs Agencywide Documents Access and
Management System (ADAMS). ADAMS is accessible from the NRC website at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Glenn T. Dentel, Chief
Reactor Projects Branch 2
Division of Reactor Projects
Docket Nos. 50-247 and 50-286
License Nos. DPR-26 and DPR-64
Enclosure:
Inspection Report 05000247/2016001 and 05000286/2016001
w/Attachment: Supplementary Information
cc w/encl: Distribution via ListServ
Non-Sensitive Publicly Available
SUNSI Review
Sensitive Non-Publicly Available
OFFICE RI/DRP RI/DRP RI/DRP
BHaagensen/GTD for
NAME CLally/CL GDentel/GTD
per discussion w/BH
DATE 05/12/16 05/12/16 05/12/16
1
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos. 50-247 and 50-286
License Nos. DPR-26 and DPR-64
Report Nos. 05000247/2016001 and 05000286/2016001
Licensee: Entergy Nuclear Northeast (Entergy)
Facility: Indian Point Nuclear Generating Units 2 and 3
Location: 450 Broadway, GSB
Buchanan, NY 10511-0249
Dates: January 1, 2016, through March 31, 2016
Inspectors: B. Haagensen, Senior Resident Inspector
G. Newman, Resident Inspector
S. Rich, Resident Inspector
J. Furia, Senior Health Physicist
H. Gray, Senior Reactor Inspector
J. Patel, Reactor Inspector
P. Ott, Operations Engineer
Approved By: Glenn T. Dentel, Chief
Reactor Projects Branch 2
Division of Reactor Projects
Enclosure
2
TABLE OF CONTENTS
SUMMARY .................................................................................................................................... 3
REPORT DETAILS ....................................................................................................................... 6
1. REACTOR SAFETY .............................................................................................................. 6
1R01 Adverse Weather Protection ....................................................................................... 6
1R04 Equipment Alignment .................................................................................................. 7
1R05 Fire Protection ............................................................................................................. 8
1R06 Flood Protection Measures ......................................................................................... 9
1R08 Inservice Inspection Activities ..................................................................................... 9
1R11 Licensed Operator Requalification Program ............................................................. 13
1R12 Maintenance Effectiveness ....................................................................................... 14
1R13 Maintenance Risk Assessments and Emergent Work Control .................................. 15
1R15 Operability Determinations and Functionality Assessments ..................................... 18
1R18 Plant Modifications .................................................................................................... 18
1R19 Post-Maintenance Testing ........................................................................................ 20
1R22 Surveillance Testing .................................................................................................. 21
1EP6 Drill Evaluation .......................................................................................................... 22
2. RADIATION SAFETY .......................................................................................................... 22
2RS1 Radiological Hazard Assessment and Exposure Controls ........................................ 22
2RS2 Occupational ALARA Planning and Controls ............................................................ 23
4. OTHER ACTIVITIES ............................................................................................................ 24
4OA1 Performance Indicator Verification ............................................................................ 24
4OA2 Problem Identification and Resolution ....................................................................... 24
4OA3 Follow Up of Events and Notices of Enforcement Discretion .................................... 33
4OA5 Other Activities .......................................................................................................... 34
4OA6 Meetings, Including Exit ............................................................................................ 36
ATTACHMENT: SUPPLEMENTARY INFORMATION............................................................... 36
SUPPLEMENTARY INFORMATION ........................................................................................ A-1
KEY POINTS OF CONTACT .................................................................................................... A-1
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED ..................................... A-3
LIST OF DOCUMENTS REVIEWED ........................................................................................ A-3
LIST OF ACRONYMS ............................................................................................................. A-11
3
SUMMARY
Inspection Report 05000247/2016001, 05000286/2016001; 01/01/2016 - 03/31/2016; Indian
Point Nuclear Generating (Indian Point), Units 2 and 3; Maintenance Risk Assessments and
Emergent Work Control and Problem Identification and Resolution.
This report covered a three-month period of inspection by resident inspectors and announced
inspections performed by regional inspectors. The inspectors identified three findings of very
low safety significance (Green), which were non-cited violations (NCVs). 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 February 4, 2015. The NRCs program for overseeing the
safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
Oversight Process, Revision 5.
Cornerstone: Initiating Events
Green. A self-revealing NCV of Technical Specification (TS) 5.4.1, Procedures, was
identified for Entergys failure to provide adequate guidance in procedure 2-PT-R084C,
23 Emergency Diesel Generator (EDG) Eight-Hour Load Test. Specifically, Entergy failed
to provide adequate procedural guidance in order to prevent an overcurrent condition on the
52/3A 480 volt (V) bus normal feeder breaker. As a result, the plant experienced a loss of
normal power to their four 480V vital buses and a momentary loss of residual heat removal
(RHR) cooling. Entergy wrote condition report (CR)-IP2-2016-01256 and revised the test
procedure to add a specific amperage restriction on the vital buses and designate the
control indication to be used.
The finding was more than minor because it is associated with the procedure quality
attribute of the Initiating Events cornerstone and adversely affected the cornerstone
objective to limit the likelihood of events that upset plant stability and challenge critical safety
functions during shutdown. The performance deficiency caused a loss of normal power to
the vital 480V buses, which also resulted in a loss of RHR event. The Region I Senior Risk
Analyst (SRA) used IMC 0609, Appendix G, Shutdown Operations Significance
Determination Process, to assess the safety significance of this event. The SRA
determined that Worksheet 3 in Plant Operating State 1 [reactor coolant system (RCS)
closed with steam generators available for decay heat removal], best represents the actual
event and associated mitigation system available. Throughout the event, the RCS was
intact with steam generators available and 24 reactor coolant pump (RCP) running;
therefore, it was determined that this finding was of very low safety significance (Green).
This finding had a cross-cutting aspect in the area of Human Performance, Challenge the
Unknown, because personnel did not stop when faced with uncertain conditions. Risks
were not adequately evaluated and managed before proceeding [H.11 - Challenge the
Unknown]. (Section 4OA2)
4
Cornerstone: Mitigating Systems
Green. The inspectors identified an NCV of TS 3.7.3, Main Feedwater Isolation,
Surveillance Requirement (SR) 3.7.3.3 on March 26, 2016, when the inspectors determined
that Entergy had not conducted surveillance testing on the main boiler feed pump (MBFP)
trip function as required. Specifically, the MBFP trip function had never been tested. The
MBFP trip is designed to ensure isolation of feedwater flow into containment during a
feedline break accident to prevent exceeding pressure and temperature limits inside
containment. Entergy wrote CR-IP2-2016-02247 and assigned a mode 3 hold to evaluate
the testing to comply with the TS.
This finding is more than minor because it is associated with the procedural quality attribute
of the Mitigating Systems cornerstone because Entergy had not prepared a testing
procedure to verify that the surveillance requirements were met. In accordance with
IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of IMC 0609, Appendix A,
The Significance Determination Process for Findings at Power, the inspectors determined
that a detailed risk evaluation was required because the finding represented a loss of
function of a single train for greater than its TS allowable outage time (AOT). The detailed
risk evaluation concluded that the finding was of very low safety significance (Green)
because of the very low probability of a feedwater line break inside containment when
combined with the high probability that the feedwater regulating valve (FRV) and feedwater
isolation valve (FWIV) would successfully close from a safety injection signal to isolate
feedwater flow into containment. The total core damage contribution of this event is
approximately 1E-7 and based on the above considerations, the core damage risk was
assessed to be very low or Green. This finding had a cross-cutting aspect in the area of
Problem Identification and Resolution, Evaluation, because Entergy failed to thoroughly
evaluate the MBFP failure to trip during a reactor trip to ensure that corrective actions
address causes and extent of conditions commensurate with their safety significance [P.2 -
Evaluation]. (Section 4OA2)
Cornerstone: Barrier Integrity
Green. The inspectors identified an NCV of Title 10 of the Code of Federal Regulations
(10 CFR) 50.65(a)(4) because Entergy did not effectively manage the risk associated with
refueling maintenance activities. Specifically, Entergy did not demonstrate they could
implement their planned risk management action to restore the containment key safety
function within the time-to-boil using the equipment hatch closure plug. Entergy wrote CR-
IP2-2016-01503 and CR-IP2-2016-01883 to address this issue.
This performance deficiency is more than minor because it impacted the barrier
performance attribute of the Barrier Integrity cornerstone and affected the objective to
provide reasonable assurance that containment protects the public from radionuclide
releases caused by accidents or events. Specifically, Entergy did not demonstrate that they
could install the hatch plug within the time-to-boil and that the plug would seal the equipment
hatch opening, which affected the reliability of containment isolation in response to a loss of
shutdown cooling or other event inside containment. The inspectors determined the finding
could be evaluated using Attachment 0609.04, Initial Characterization of Findings.
Because the finding degraded the ability to close or isolate the containment, it required
review using IMC 0609, Appendix H, Containment Integrity Significance Determination
Process. Since containment status was not intact and the finding occurred when decay
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heat was relatively high, it required a phase two analysis. Since the leakage from
containment to the environment was less than 100 percent containment volume per day, the
finding screens as very low safety significance (Green). A subsequent demonstration
showed that the hatch plug provided an adequate seal with the containment hatch opening.
The inspectors concluded this finding had a cross-cutting aspect in the area of Human
Performance, Documentation, because Entergy did not maintain complete, accurate, and
up-to-date documentation related to the use of the hatch plug. Specifically, they tested the
seal integrity without using a work order (WO), and made pen-and-ink changes to the
procedure without processing a procedure change form.
[H.7 - Documentation] (Section 1R13)
6
REPORT DETAILS
Summary of Plant Status
Unit 2 began the inspection period at 100 percent power. On February 5, 2016, Unit 2 entered
end-of-cycle coast down operations. On March 6, 2016, operators commenced a shutdown,
from an initial power of 77 percent, for a planned refueling and maintenance outage (2R22).
The station reached mode 6 (refueling) on March 12, 2016, and the reactor was defueled on
March 18, 2016. On March 28, 2016, the inspectors verified that all the fuel was safely removed
from the reactor vessel and stored in the spent fuel pool. Unit 2 ended the inspection period in
a defueled condition.
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 - 1 sample)
Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
The inspectors reviewed Entergys preparations for the onset of a blizzard with
forecasted high winds and heavy snow accumulations on January 23, 2016. The
inspectors reviewed the implementation of adverse weather preparation procedures
including OAP-48, Seasonal Weather Preparation (Units 2 and 3), before the onset of
and during this adverse weather condition. The inspectors walked down the outside
areas of the site to ensure no challenges from missiles or snow blockage of safety
systems air intakes and that there were no problems as a result of the severe weather.
The inspectors verified that plant modifications, maintenance activities (i.e., temporary
hazard barrier removal), new evolutions, procedure revisions, or operator workarounds
implemented to address periods of adverse weather did not degrade maintenance rule
structures, systems, and components (SSCs). 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 cold weather preparedness with operators and maintained an awareness of
cold weather issues throughout the storm. Documents reviewed for each section of this
inspection report are listed in the Attachment.
b. Findings
No findings were identified.
7
1R04 Equipment Alignment
.1 Partial System Walkdowns (71111.04Q - 2 samples)
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
Unit 2
21 and 22 EDGs on January 27, 2016, while 23 EDG was inoperable due to a
service water leak
Safety injection system on February 25, 2016
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 Updated Final Safety Analysis
Report (UFSAR), TSs, WOs, 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
corrective action program (CAP) for resolution with the appropriate significance
characterization.
b. Findings
No findings were identified.
.2 Full System Walkdown (71111.04S - 1 sample)
a. Inspection Scope
On March 8 and March 15, 2016, the inspectors performed a complete system
walkdown of accessible portions of the Unit 3 auxiliary feedwater (AFW) system to verify
the existing equipment lineup was correct. The inspectors reviewed operating
procedures, surveillance tests, drawings, equipment line-up check-off lists, and the
UFSAR to verify the system was aligned to perform its required safety functions. The
inspectors also reviewed electrical power availability, component lubrication and
equipment cooling, hanger and support functionality, and availability of support systems.
The inspectors performed field walkdowns of accessible portions of the systems to verify
system configuration matched plant documentation and that system components and
support equipment remained operable. The inspectors confirmed that systems and
components were installed and aligned correctly, free from interference from temporary
services or isolation boundaries, environmentally qualified, and protected from external
threats. The inspectors also examined the material condition of the components for
degradation and observed operating parameters of equipment to verify that there were
no deficiencies. The inspectors discussed identified deficiencies with the system
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engineer to verify they had been appropriately documented. Additionally, the inspectors
reviewed a sample of related CRs and WOs to ensure Entergy appropriately evaluated
and resolved any deficiencies.
b. Findings
No findings were identified.
1R05 Fire Protection
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 out of service,
degraded, or inoperable fire protection equipment, as applicable, in accordance with
procedures.
Unit 2
Fuel support building, 70-foot, 80-foot, and 95-foot elevations (PFP-217 was
reviewed) on March 23, 2016
Vapor containment 95-foot elevation (PFP-203 was reviewed) on March 23, 2016
Vapor containment 46-foot and 68-foot elevations (PFP-201 and PFP-202 were
reviewed) on March 23, 2016
Unit 3
Component cooling pumps (PFP-306A was reviewed) on March 16, 2016
RHR pump area, primary auxiliary building (PAB) 15-0 (PFP-304 was reviewed), on
March 24, 2016
AFW building (PFP-365, PFP-366, and PFP-367 were reviewed) on March 25, 2016
b. Findings
No findings were identified.
9
1R06 Flood Protection Measures (71111.06 - 2 samples)
.1 Internal Flooding Review
a. Inspection Scope
The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to
assess susceptibilities involving internal flooding. The inspectors also reviewed the CAP
to determine if Entergy identified and corrected flooding problems and whether operator
actions for coping with flooding were adequate. In particular, the inspectors focused on
the Unit 2 RHR rooms in the PAB to verify the adequacy of equipment seals located
below the flood line, floor and penetration seals, common drain lines, sumps, and sump
pumps.
b. Findings
No findings were identified.
.2 Annual Review of Cables Located in Underground Bunkers/Manholes
a. Inspection Scope
The inspectors conducted an inspection of underground bunkers/manholes subject to
flooding that contain cables whose failure could disable risk-significant equipment on
March 31, 2016. The inspectors observed the inspection and dewatering of manholes
31, 31A, and 31B containing service water pump cables, to verify that the cables were
not submerged in water, that cables and splices appeared intact, and to observe the
condition of cable support structures.
b. Findings
No findings were identified.
1R08 Inservice Inspection (ISI) Activities (71111.08P - 1 sample)
a. Inspection Scope
From March 14-24, 2016, the inspectors conducted an inspection and review of
Entergys implementation of ISI program activities for monitoring degradation of the RCS
boundary, risk significant piping and components, steam generator tube integrity, and
vessel internals during the Unit 2 refueling outage (RFO) 2R22. The sample selection
was based on the inspection procedure objectives and risk priority of those pressure
retaining components in systems where degradation would result in a significant
increase in risk. The inspectors observed in-process non-destructive examinations
(NDEs), reviewed documentation, and interviewed Entergy personnel to verify that the
NDE activities performed as part of the fourth interval, Unit 2 ISI program, were
conducted in accordance with the requirements of the American Society of Mechanical
Engineers (ASME) Boiler and Pressure Vessel Code,Section XI, 2001 Edition,
2003 Addenda, and augmented program guidelines.
10
Nondestructive Examination and Welding Activities (IMC Section 02.01)
Reviews and inspection were completed to verify whether the examinations were
performed in accordance with procedures that implemented ASME,Section XI,
requirements and that the results were reviewed and evaluated by certified ASME level
III personnel. The inspectors performed direct observations of NDE activities in process
and reviewed work instruction packages and records, including both documentation and
video of NDEs listed below:
ASME Code Required Examinations
Observation and record review of the work package, drawings, and procedure for the
manual volumetric ultrasonic examination (UT) of the ASME Class 1 inner radius of
three nozzle to head areas on the pressurizer
Review of the computer based UT and scope of eddy current testing (ECT)
examinations of the four reactor coolant cold leg and hot leg nozzle to safe end
dissimilar metal welds completed underwater from the internal root surfaces
Review of the computer based UT procedures and a sample of the reactor pressure
vessel nozzle to shell, circumferential and longitudinal welds, UT results completed
as part of the 10-year ASME code required by reactor pressure vessel examinations
Review of the procedure and observation of UT of the upper shell to pressurizer
head weld
Review of the procedure and preparations for magnetic particle examination of the
support skirt to pressurizer lower head weld
The inspectors sampled qualification certificates of the NDE examiners performing the
nondestructive testing.
Other Augmented or Industry Initiative Examinations
The inspectors reviewed Entergy procedure CEP-NDE-0504, Ultrasonic Examination of
Small Bore Diameter Piping for Thermal Fatigue Damage, for manual UT of small
diameter piping to detect thermal fatigue in accordance with Materials Reliability Project
(MRP)-24 and MRP-146. The inspectors further reviewed the WOs with the UT
technician performing the examinations to verify whether the activities were conducted in
accordance with the procedure. WOs 00390796, 00390797, and 00390798 were
reviewed for the UT of small diameter piping of charging system line segments 82, 83,
and 84 in the vicinity of welds 56-3 through 56-8.
A sample of the ECT at the bottom head to instrumentation penetration welds was
reviewed by the inspectors to determine the condition of these welds and to confirm
these examinations were completed in accordance with the Entergy augmented
inspection program and procedures.
The inspectors reviewed the UT data acquisition and analysis process for the
baffle-former bolts and observed portions of the remote visual observation of
baffle-former plates, baffle-edge bolts, and baffle-former bolts. The inspectors reviewed
a sample of Entergys evaluation of the data and the results to determine whether these
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activities were performed in accordance with Entergy augmented inspection program
and procedures as part of the MRP-227-A vessel internals inspection and evaluation
process.
The inspectors reviewed event report 51829, dated March 29, 2016, in which Entergy
notified the NRC that the level of degradation of baffle-former bolts was a condition not
previously analyzed. For the visual observations of 31 baffle-former bolts with locking
bar or nonconforming bolt head positions and the 182 bolts with UT indications,
additional information is necessary to determine the significance of these conditions and
whether there was a performance deficiency. The inspectors concluded that additional
information and inspection is needed to determine whether there is a performance
deficiency. As a result, the NRC opened an unresolved item (URI).
Review of Previous Indications
The examination preparations and results of the UT of previously identified NDE
indications on control rod drive mechanism (CRDM) 52 welds was reviewed. This
examination of a previously identified indication verified that that no changes had
occurred.
Repair/Replacement Consisting of Welding Activities
Repair/replacement activities on the service water system, including welding and control
of welding, were reviewed during this inspection. These included the 21 component
cooling water heat exchanger inlet, the 24 fan coil unit motor cooler return, and the
instrument air heat exchanger supply.
For the flex modification on WO-00375991-01 welds FW-1, 5, and 7, the radiographs
done per Entergy procedure CEP-NDE-0255, Radiographic Examination, were
reviewed.
Pressurized-Water Reactor Vessel Upper Head Penetration Inspection Activities
(IMC 02.02)
The inspectors verified that the reactor vessel upper head penetration J-groove weld
examinations were performed in accordance with requirements of 10 CFR 50.55a and
ASME Code Case N-729-1, Alternative Examination Requirements for Pressurized
Water Reactor Vessel Upper Heads, to ensure the structural integrity of the reactor
vessel head pressure boundary. The inspectors also observed portions of the remote
bare metal VT on the exterior surface of the reactor vessel upper head and CRDM
nozzle penetrations to verify that no boric acid leakage or wastage had been observed.
This included observation of the automatic computer based volumetric UT of the reactor
vessel upper head penetration nozzles in the vicinity of the CRDM to head welds,
including a specific review of the past and present condition of CRDMs 50 and 52.
The inspectors reviewed the ECT performed on outer diameter weld toe to tube area of
CRDM 50.
The inspectors further reviewed the work package instructions, procedure for liquid
penetrant surface examinations, and final visual record of the outer diameter weld toe to
12
tube area of CRDM 50 to confirm the material surface condition met the penetrant
white required condition.
Boric Acid Corrosion Control Inspection Activities (IMC Section 02.03)
During the plant shutdown process, the NRC resident inspectors observed the boric acid
leakage identification process. A region based inspector reviewed the boric acid
corrosion control program, which was performed in accordance with Entergy procedures
and discussed the program requirements with the boric acid program owner. The
inspectors reviewed photographic inspection records of a sample of identified boric acid
leakage locations and discussed the mitigation and evaluation plans. The inspectors
reviewed a sample of CRs for evaluation and disposition within the CAP. Samples
selected were based on component function, significance of leakage, and location where
direct leakage or impingement on adjacent locations could cause degradation of safety
system function.
Steam Generator Tube Inspection Activities (IMC Section 02.04)
The inspectors reviewed an assessment of the pre-RFO 2R22 operational conditions
and applicable operational experience of the steam generators that summarized the
basis for not examining the steam generator tubes by ECT during 2R22 as was
expected based on the ECT results at the last steam generator tube examinations.
Identification and Resolution of Problems (IMC Section 02.05)
The inspectors verified that ISI related problems and nonconforming conditions were
properly identified, characterized, and evaluated for disposition within the CAP.
b. Findings
Introduction. The inspectors determined the level of degradation of baffle-former bolts
reported to the NRC as a condition not previously analyzed was an issue of concern that
warrants additional inspection to determine whether there is a performance deficiency.
As a result, the NRC opened a URI.
Description. Additional inspection is warranted to determine whether a performance
deficiency exists related to event number 51829 dated March 29, 2016, in which Entergy
reported to the NRC that the level of degradation of baffle-former bolts was a condition
not previously analyzed. The baffle-former bolts secure plates in the reactor core barrel
to form a shroud around the fuel core. The inspectors planned to review the results of
Entergys cause evaluation of this issue. (URI 05000247/2016001-01, Baffle-Former
Bolts with Identified Anomalies)
13
1R11 Licensed Operator Requalification Program (71111.11Q - 4 samples)
Unit 2
.1 Quarterly Review of Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed Unit 2 licensed operator simulator training on March 3, 2016,
which included a plant startup from 0 to 25 percent power, main turbine startup, main
generator startup, and synchronization to the grid. Component/instrument failures
included the loss of the 21 MBFP, a steam flow instrument channel failed high, a steam
dump valve failed open, a pressurizer pressure instrument failed high, and a turbine
control valve failed open. 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. 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.
.2 Quarterly Review of Licensed Operator Performance in the Main Control Room
a. Inspection Scope
The inspectors observed and reviewed Unit 2 power reduction and plant shutdown for
RFO 2R22 conducted on March 6 and 7, 2016. The inspectors observed infrequently
performed test or evolution briefings, pre-shift briefings, and reactivity control briefings to
verify that the briefings met the criteria specified in Entergys 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.
Unit 3
.3 Quarterly Review of Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed Unit 3 licensed operator simulator training during a January 20,
2016, emergency planning drill, which included a large break loss of coolant accident
with subsequent loss of offsite power. The inspectors evaluated operator performance
during the simulated event and verified completion of risk significant operator actions,
14
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.
.4 Quarterly Review of Licensed Operator Performance in the Main Control Room
a. Inspection Scope
The inspectors observed Unit 3 control room operator response to rising temperature
indication on the pressurizer power operated relief valve line on March 14, 2016. The
inspectors verified that alarm response procedure use, crew communications, and
monitoring of plant parameters met established expectations and standards. The crew
confirmed that the power operated relief valves remained closed, that there were no
indications of leakage on the acoustic monitors, and that the temperature eventually
returned to normal. The inspectors also verified that the unexpected alarm was
documented appropriately in CR-IP3-2016-00746.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness (71111.12Q - 1 sample)
a. Inspection Scope
The inspectors reviewed the sample listed below to assess the effectiveness of
maintenance activities on SSC performance and reliability. The inspectors reviewed
CAP documents, 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. Additionally, the inspectors ensured that Entergy was identifying and
addressing common cause failures that occurred within and across maintenance rule
system boundaries.
Unit 2
The inspectors reviewed the failure of the 11 station air centrifugal air compressor
after planned maintenance, associated (a)(1) evaluation, and performed a system
15
review to ensure the effectiveness of maintenance activities. The inspectors
reviewed past planned and corrective maintenance on the 11 centrifugal air
compressor to verify it had been performed in accordance with work instructions.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13 - 3 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
Yellow risk for 22 EDG unplanned maintenance on March 3, 3016
Yellow risk for containment closure during decreased inventory on March 9, 2016
Unit 3
Yellow fire risk due to Wide Range Nuclear Instrument N38 inoperable on
February 22, 2016
b. Findings
Introduction. The inspectors identified an NCV of very low safety significance (Green) of
10 CFR 50.65(a)(4) because Entergy did not effectively manage the risk associated with
refueling maintenance activities. Specifically, Entergy did not demonstrate they could
implement their planned risk management action to restore the containment key safety
function within the time-to-boil using the equipment hatch closure plug.
Description. For both Unit 2 and Unit 3, once the reactor is in the cold shutdown mode,
Entergy staff remove the equipment hatch from containment. The equipment hatch
opening is approximately 16 feet in diameter, located at ground level, and allows the
easy passage of material into and out of containment. The equipment hatch must be
moved using the polar crane and can be replaced in a few hours. Shortly after the start
of the outage, the time-to-boil upon loss of cooling in the RCS can be very short
(approximately 20 minutes) due to the high decay heat load from the fuel in the vessel.
16
In order to reduce the risk of a release of radioactive steam as a result of a loss of
shutdown cooling, Entergy uses an equipment hatch closure plug (hatch plug) that can
be installed more rapidly than the equipment hatch. Before the start of RFO 2R22,
Entergy staff moved the hatch plug from the storage warehouse to the hill just outside
the equipment hatch opening. If needed, Entergy staff use a forklift to move the hatch
plug into the equipment hatch opening, engage strong-backs that hold the hatch plug in
place, and inflate a pair of tire-like rubber seals that circle the hatch plug. Both Unit 2
and Unit 3 use the same hatch plug.
Entergys outage risk assessment team (ORAT) report for RFO 2R22 evaluates the risk
of each key safety function for each day of the outage. Whenever the equipment hatch
is removed and fuel is still in the reactor vessel, the ORAT report credits a number of risk
management actions to provide sufficient compensation for the degradation of the
containment key safety function. One of them is C4.A5, which states, Maintain the
ability to install the temporary hatch plug installation of the hatch plug
demonstrated to not approach time to boil, if to be removed with pressurizer level less
than 10 percent. To achieve that risk management action, Entergy performs procedure
0-CON-401-EQH, Section 4.5, Equipment Hatch Closure Plug Installation Practice
Steps, during both the day shift and the night shift. Each crew is required to
demonstrate the ability to install the hatch plug in less than the calculated time to boil,
thereby ensuring that the risk management action is established.
During 2R22, on March 9, 2016, both the day shift crew and the night shift crew
demonstrated successful hatch plug installation. Upon review of the completed
procedure, the inspectors noted that Entergy did not inflate the seals on the plug, as
required by step 4.5.11. Instead, the outage control center directed the crew to simulate
performing the step. By simulating the step, Entergy failed to demonstrate that they
could fully install the hatch plug within the time-to-boil and failed to demonstrate that the
hatch plug would seal the hatch as designed. Entergy documented the discrepancy in
CR-IP2-2016-01503 and CR-IP2-2016-01883.
During interviews, Entergy staff told the inspectors that they typically do not inflate the
seals during the installation demonstration, and the inspectors confirmed this by a review
of completed WOs from prior RFOs on both Unit 2 and Unit 3. Several of those WOs
included a note or a pen-and-ink change to the procedure stating that the seals were not
inflated as directed by step 4.5.11. Entergy staff stated that they inflate the seals (to an
undetermined pressure) before taking the plug out of the warehouse to verify they will
hold air but do not use a WO, so there is no record of the test or pressure used.
Additionally, inflating the seals when the hatch plug is not in the equipment hatch
opening does not demonstrate that the hatch plug will seal the containment opening or
will hold full pressure.
Entergy began RFO 2R22, entered mode 5 (cold shutdown), and removed the
equipment hatch on March 7, 2016. Pressurizer water level had been reduced below
10 percent on March 10, 2016, without fully demonstrating that the hatch plug could be
successfully installed in less than the time-to-boil. On April 5, 2016, the inspectors
observed as Entergy performed section 4.8 of 0-CON-401-EQH and partially
demonstrated that the hatch plug could be installed, the seals inflated, and the seals
functioned to seal the containment opening. This partial demonstration was only
performed on Unit 2. The hatch plug was last successfully tested in Unit 3 in 2011.
Since the same hatch plug and procedure are used for both units, it is reasonable to
17
conclude that the installation would be successful on Unit 3 as well because there is no
indication of significant degradation of the Unit 3 equipment hatch opening in the last five
years.
Section 4.8 of 0-CON-401-EQH is used for general-purpose installation of the hatch
plug, and so it does not require timing the installation like section 4.5. The supervisor
informally timed the evolution and resulting time had margin to the time-to-boil on
March 9, 2016. However, there was variability between the conditions during the partial
demonstration and the conditions during the timed installation tests. Therefore, it was
not conclusively demonstrated whether the hatch plug could have been installed within
the time to boil during 2R22.
Analysis. With the containment equipment hatch removed and the pressurizer level
below 10 percent, Entergy did not adequately implement their risk management action to
ensure they could promptly restore the containment key safety function. Specifically,
they did not demonstrate that the hatch plug could be effectively installed and did not
obtain a representative time for the installation to ensure it could be installed within the
time-to-boil for a loss of shutdown cooling. This was a performance deficiency that was
within their ability to foresee and correct and should have been prevented. This
performance deficiency is more than minor because it impacted the barrier performance
attribute of the Barrier Integrity cornerstone and affected the objective to provide
reasonable assurance that containment protects the public from radionuclide releases
caused by accidents or events. Specifically, Entergy did not demonstrate that they could
install the hatch plug within the time-to-boil and that the plug would seal the equipment
hatch opening, which affected the reliability of containment isolation in response to a
loss of shutdown cooling or other event inside containment. The inspectors evaluated
the finding using Attachment 0609.04, Initial Characterization of Findings. Because the
finding degraded the ability to close or isolate the containment, it required review using
IMC 0609, Appendix H, Containment Integrity Significance Determination Process.
Since containment status was not intact and the finding occurred when decay heat was
relatively high, it required a phase two analysis. Since the leakage from containment to
the environment was less than 100 percent containment volume per day, the finding
screens as very low safety significance (Green). A subsequent demonstration showed
that the hatch plug provided an adequate seal with the containment hatch opening.
The inspectors concluded this finding had a cross-cutting aspect in the area of Human
Performance, Documentation, because Entergy did not maintain complete, accurate,
and up-to-date documentation related to the use of the hatch plug. Specifically, they
initially tested the seal integrity without using a WO or test procedure (by pressurizing
the seal in the warehouse) and subsequently made pen-and-ink changes to the
procedure in use during the initial partial demonstration without processing a procedure
change form. [H.7 - Documentation]
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, Entergy did not effectively manage
the risk associated with refueling maintenance activities. Specifically, Entergy did not
adequately implement their risk management action to ensure they could promptly
restore the containment key safety function. Entergy wrote CR-IP2-2016-01503 and
CR-IP2-2016-01883 to address this. Because this violation was of very low safety
significance and was entered into the CAP, this violation is being treated as an NCV,
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consistent with section 2.3.2 of the NRC Enforcement Policy. (NCV 05000247 and
05000286/2016001-02, Failure to Adequately Implement Risk Management Actions
for the Containment Key Safety Function)
1R15 Operability Determinations and Functionality Assessments (71111.15 - 4 samples)
a. Inspection Scope
The inspectors reviewed operability determinations for the following degraded or non-
conforming conditions:
Unit 2
21 component cooling water heat exchanger through-wall leak (CR-IP2-2015-05358)
on January 20, 2016
Equipment qualification during coast-down (CR-IP2-2015-03115) on February 17,
2016
Failed pipe restraint SR-48 on refueling water storage tank common supply line 155
to safety injection and RHR pumps (CR-IP2-2016-01025) on February 25, 2016
23 EDG voltage anomalies (CR-IP2-2016-01430) on March 7, 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.
b. Findings
No findings were identified.
1R18 Plant Modifications (71111.18 - 1 sample)
a. Inspection Scope
The inspectors reviewed a temporary modification on Unit 3. On March 1, 2016, Entergy
performed an emergency temporary modification to reactor protective system (RPS)
block relay 15-B in an energized position after they found it de-energized during
surveillance testing. The inspectors reviewed the use of the relay blocking device to
determine whether the modification affected the safety function of the RPS. The
inspectors reviewed 10 CFR 50.59 documentation and engineering change 63282 once
it was completed to verify that the temporary modification did not degrade the design
19
bases, licensing bases, and performance capability of RPS. The inspectors also
reviewed associated standing orders, temporary procedure changes, and affected
drawings to ensure the modification was appropriately documented.
b. Findings and Observations
Introduction. The inspectors identified that Entergy conducted testing on the Unit 3 RPS
that was not described in the UFSAR without performing an adequate 50.59 evaluation,
contrary to EN-LI-100, Process Applicability Determination. Specifically, Entergy made
temporary changes to the Unit 3 reactor coolant temperature channel functional test
procedures, pressurizer pressure loop functional test procedures, and nuclear power
range channel axial offset calibration procedures to use jumpers to bypass RPS trip
functions. As a result, the NRC opened an URI related to this concern.
Description. On October 21, 2014, Entergy implemented temporary procedure changes
to three sets of reactor protection system surveillance procedures. These procedures
were 3-PT-Q87A, B, and C, Channel Functional Test of Reactor Coolant Temperature
Channel 411, 421, and 431; 3-PT-Q95A, B, and C, Pressurizer Pressure Loop P-455,
456, and 457 Functional Test; and 3-PT-Q109A, B, and C, Nuclear Power Range
Channel N-41, 42, and 43 Axial Offset Calibrations. Entergy made the temporary
procedures changes as an interim corrective action following a trip of Unit 3 on
August 13, 2014, during reactor protection system surveillance testing when a spurious
actuation signal occurred in the channel that was not being tested. Entergy was initially
unable to identify and correct the cause of the spurious over-temperature delta
temperature (OTDT) channel trip and, therefore, wanted to perform their TS required
surveillances without risking another unit trip should another spurious actuation occur in
the degraded channel not under test. In each case, the change was to install a jumper
at the beginning of the testing to maintain the trip relay in an energized condition for the
tested channel of the OTDT trip circuit thereby effectively bypassing the channel in test.
Each quarterly test was performed three or four times over the course of approximately
ten months. On July 1, 2015, Entergy determined that they had corrected the cause of
the spurious OTDT channel trips and removed the temporary procedure changes from
the controlled document system. Despite this, on August 12, 2015, Entergy performed
the surveillances 3-PT-Q95A, B, and C, Pressurizer Pressure Loop P-455, 456, and 457
Functional Test, which incorporated the temporary procedure changes that had been
discontinued.
Operating experience has shown that human error has allowed jumpers to remain
installed even after testing is over because there is no obvious indication that the
channel is in bypass when a jumper is used. Indian Point is committed to IEEE
Standard 279-1971, Criteria for Protective Systems for Nuclear Power Plants. Section
4.13, Indication of Bypass, requires that any channel placed in a bypass configuration for
testing shall have continuous indication in the control room that the channel has been
removed from service. These standards preclude the use of jumpers for routine testing.
This commitment was further documented in the Safety Evaluation Report for TS
Amendment 107 that approved the extension of surveillance testing intervals and
approved the use of the bypass feature for testing. Although Unit 3 was not originally
built with RPS bypass switches, New York Power Authority had planned to install bypass
switches, which would comply with IPEEE 279-1971. Entergy terminated the WO for
installation of these switches.
20
Normally, during the course of RPS channel surveillance testing, the affected channel of
the OTDT trip circuit would de-energize the trip relay. If one of the other three redundant
RPS channels spuriously de-energized at the same time, the two of four signal RPS trip
logic would be satisfied and Unit 3 would trip, as occurred on August 13, 2015. By
putting the jumper in place, the affected channel trip relay would remain energized under
all conditions, including actual conditions that would require a plant trip on OTDT.
During testing, the use of the jumper did not increase the likelihood of a malfunction of
an SSC over that previously evaluated in the UFSAR because Unit 3 had received a
license amendment (Agencywide Documents Access and Management System
(ADAMS) Accession No. ML003779650) that allowed testing a bypassed channel.
However, the safety evaluation report for that license amendment stated that, The
licensee further commits that only those instruments whose hardware capability does not
require the lifting of leads or installing of jumpers will be routinely tested in bypass.
When Unit 3 applied for the license amendment, the intent was to permanently install
bypass switches that would allow bypassing a channel and would clearly indicate in the
control room that a channel was bypassed. The risk of inadvertently leaving a jumper in
place is greater than the risk of inadvertently leaving a channel bypassed using
hardware that brings in an alarm in the control room, because the jumper can go
unnoticed for a longer period of time since it does not result in clear indication in the
control room.
Per procedure EN-LI-100, Entergy performed a 50.59 screening review for these
temporary procedure changes. In this screening, they incorrectly determined that the
temporary procedure changes did not involve a test not described in the UFSAR, and as
a result, did not perform a 50.59 evaluation. Although the UFSAR describes reactor
protection system testing by bypassing channels, it specifically does not authorize the
use of jumpers to do so. The UFSAR for Unit 3, chapter 7, states, Test procedures also
allow the bistable output relays of the channel under test to be placed in the bypassed
mode prior to proceeding with the analog channel test this may only be done for
circuits whose hardware does not require the use of jumpers or lifted leads to be placed
in bypass mode. Jumpering out the RPS trip relay in an RPS channel under test
created an adverse condition because it removed the automatic trip signal from the RPS
logic. Entergy was required to fully evaluate the adverse condition rather than authorize
the change under an abbreviated 50.59 screening process.
The inspectors concluded that not performing an adequate 50.59 evaluation was a
performance deficiency that was reasonably within Entergys ability to foresee and
correct and should have been prevented. Because Entergy was in the process of
performing a retroactive 50.59 evaluation at the end of the inspection period, the
inspectors were not able to evaluate if the performance deficiency was more than minor.
The inspectors determined that the issues concerning the use of jumpers for RPS testing
is an URI pending Entergy completion and NRC review of the 50.59 evaluation. (URI
05000286/2016001-03, Inadequate Screening of Reactor Protection System Test
Method Change)
1R19 Post-Maintenance Testing (71111.19 - 4 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
21
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, that the acceptance criteria in the procedure was consistent with
the information in the applicable licensing basis and/or design basis documents, and 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
point were performed and checked, and that results adequately demonstrated
restoration of the affected safety functions.
Unit 2
21 auxiliary boiler feedwater pump after motor coupling preventative maintenance on
January 19, 2016
Repairs to 21 fan cooler unit through-wall leak on February 1, 2016
Unit 3
Pressurizer level transmitter LM-461B replacement on January 15, 2016
Appendix R diesel generator after preventative maintenance on February 24, 2016
b. Findings
No findings were identified.
1R22 Surveillance Testing (71111.22 - 6 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-M021C, EDG 23 Load Test, on January 13, 2016
2-PT-R006, Main Steam Safety Valve Setpoint Determination, on March 4, 2016
2-PT-R014, Automatic Safety Injection System Electrical Load and Blackout Test, on
March 9 and 10, 2016
2-PT-26A-DS014, Reactor Coolant Pump Component Coolant Water Supply
(Containment Isolation) Valve 797, on March 18, 2016
2-PT-R084C, 23 EDG 8-Hour Load Test, on March 23, 2016
22
Unit 3
3-PT-Q120B, 32 ABFT (Turbine Driven) Surveillance and Inservice Test, on
January 25, 2016
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation (71114.06 - 1 sample)
Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine emergency drill for Unit 3 on
January 20, 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 and emergency
operations facility to determine whether the event classification, notifications, and
protective action recommendations were performed in accordance with procedures. The
inspectors also reviewed 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 - 3 samples)
a. Inspection Scope
During March 6-10, 2016, the inspectors reviewed Entergys performance in assessing
the radiological hazards and exposure control in the workplace. The inspectors used the
requirements in 10 CFR 20, TS, applicable industry standards, and procedures required
by TS as criteria for determining compliance.
Radiological Hazards Control and Work Coverage
The inspectors reviewed:
Ambient radiological conditions during tours of the radiological controlled area,
posted surveys, radiation work permits (RWPs), adequacy of radiological controls,
radiation protection job coverage, and contamination controls
23
Use of electronic personal dosimeters in high noise areas and in high radiation areas
(HRA)
RWPs for work within airborne radioactivity areas
Airborne radioactivity controls and monitoring, contamination containment integrity,
and temporary high-efficiency particulate air ventilation system operation
Controls for highly activated or contaminated materials stored within spent fuel pools
Posting and physical controls for HRAs and very HRAs
Radiation Worker Performance
The inspectors reviewed radiation worker performance and radiological problem reports
since the last inspection.
Radiation Protection Technician Proficiency
The inspectors reviewed performance of radiation protection technicians and radiological
problem reports since the last inspection.
b. Findings
No findings were identified.
2RS2 Occupational ALARA Planning and Controls (71124.02 - 3 samples)
a. Inspection Scope
During March 6-10, 2016, the inspectors assessed performance with respect to
maintaining occupational individual and collective radiation exposures as low as is
reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR 20,
TS, applicable industry standards, and procedures required by TS as criteria for
determining compliance.
Radiological Work Planning
The inspectors reviewed:
Work activities ranked by actual exposure that were completed during the last outage
ALARA work activity evaluations, exposure estimates, and exposure mitigation
requirements
ALARA work planning, use of dose mitigation features, and dose goals
ALARA evaluations for the use of respiratory protective devices
Work planning and the integration of ALARA requirements
Evaluation of person-hour estimates provided by maintenance planning and other
groups to the radiation protection group based on actual work activity person-hour
results
24
Verification of Dose Estimates and Exposure Tracking Systems
The inspectors reviewed ALARA work packages, assumptions and basis for the current
annual collective exposure estimate, and ALARA procedures to determine the
methodology for estimating and tracking collective exposures.
Radiation Worker Performance
The inspectors reviewed radiation worker and radiation protection technician
performance during work with respect to the radiological hazards present and the
ALARA program requirements.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151 - 4 samples)
RCS Specific Activity (BI01) and RCS Leak Rate (BI02)
a. Inspection Scope
The inspectors reviewed Entergys submittal for the RCS specific activity and RCS leak
rate performance indicators for both Unit 2 and Unit 3 for the period of January 1, 2015,
through December 31, 2015. 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 RCS
sample analysis and control room logs of daily measurements of RCS leakage, and
compared that information to the data reported by the performance indicator.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution (71152 - 3 samples)
.1 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.
25
b. Findings
No findings were identified.
.2 Annual Sample: Unit 2 MBFP Failure to Trip Corrective Actions
a. Inspection Scope
The 21 MBFP failed to trip automatically or manually on December 5, 2015, when Unit 2
experienced a reactor trip. Specifically, the 21 MBFP failed to trip automatically or
manually from the control room and from the local control panel and the pump discharge
valve, BFD-2-21, failed to close. The operators had to manually close the MBFP steam
supply valve to stop the pump. The cause of the failure to trip was a contaminated
control oil system. Subsequently, the inspectors noted that there was a yellow tag
hanging on the hand control switch for the 22 MBFP that stated the pump had to be
tripped locally because the remote trip switch in the control room did not function. The
inspectors performed an in-depth review of Entergys evaluation and corrective actions
associated with the failures of the Unit 2 MBFP trip function (CR-IP2-2015-05459).
The inspectors assessed Entergys problem identification threshold, cause analyses,
extent of condition reviews, compensatory actions, and the prioritization and timeliness
of Entergy corrective actions to determine whether Entergy was appropriately identifying,
characterizing, and correcting problems associated with this issue and whether the
planned or completed corrective actions were appropriate. The inspectors compared the
actions taken to the requirements of Entergys CAP and 10 CFR 50, Appendix B. In
addition, the inspectors performed field walkdowns and interviewed engineering
personnel to assess the effectiveness of the implemented corrective actions.
b. Findings and Observations
Introduction. The inspectors identified a Green NCV of TS 3.7.3, Main Feedwater
Isolation, SR 3.7.3.3 on March 26, 2016, when the inspectors determined that Entergy
had not conducted surveillance testing on the MBFP trip function as required by
SR 3.7.3.3. There was no evidence that the MBFP trip function had ever been
tested. The MBFP trip is a design feature that is relied upon in the UFSAR accident
analysis to mitigate a feedwater line break inside containment event.
Description. On December 5, 2015, during a reactor trip on Unit 2, the operators
identified that the 21 MBFP failed to trip when commanded from the control
room. Subsequent efforts to electrically and mechanically trip the pump from the local
control panel were unsuccessful. The operators finally stopped the pump by isolating
steam to the pump by closing the steam admission valve. In addition, the 22 MBFP had
a known degraded condition since the previous RFO that the pump would not trip from
the control room; it had to be tripped locally by an operator.
The cause of the 21 MBFP trip was determined to be caused by contaminated control
oil. Entergy took corrective action to clean up the control oil system, replace the
solenoid valves that open to dump oil pressure to trip the pump, and restored the MBFP
to normal operation. Unit 2 was restored to 100 percent power on December 7,
2015. CR-IP2-2016-05459 evaluated the corrective actions and concluded that all
26
safety functions associated with a MBFP trip are operable. However, the inspectors
questioned whether the post-maintenance test had included end-to-end testing of the
MBFP trip function in response to a safety injection engineered safety features actuation
system signal. The inspectors recognized that TS 3.7.3, Main Feedwater Isolation,
condition D, required the main feedwater pump trip functions to be operable. SR 3.7.3.3
required a verification of the pump trip function. The inspectors subsequently
questioned the basis for concluding that the MBFP trip function was not required.
The inspectors noted that CR-IP2-2015-05459, that reported the 21 MBFP failed to trip
when commanded, was initially screened as a category B requiring an apparent cause
evaluation (ACE) and was assigned six corrective actions. The screening was later
downgraded from a B to an NC, which did not require any causal analysis; and
corrective actions 1, 3, 4, and 5 were cancelled without taking any action. The basis for
this downgrade in the immediate operability determination was that all safety functions
associated with the 21 MBFP trip were operable.
Further inspection efforts determined that TS 3.7.3, Main Feedwater Isolation, limiting
condition of operation (LCO) D required that if one or more MBFP trips were inoperable,
Entergy had an AOT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to either restore the MBFP trip to an operable status or
trip the MBFP. Furthermore, SR 3.7.3.3 required verification of the MBFP trip function
every 24 months. The basis for this SR was to prevent adding excessive energy into the
containment structure during a feedline or steam line break inside containment. The
closure of the MBFP discharge valves and trip of the MBFP was a redundant design
feature to the closure of the FRVs in the UFSAR. TS 3.7.3 bases states in part
closure of the MBFP discharge valves [alone] does not satisfy the accident analysis
assumptions. Therefore, when the MBFP discharge valves close in response to an
engineered safety features actuation system signal, the MBFP will automatically trip
when the associated MBFP discharge valve moves off its open seat. The inspectors
questioned when the MBFP trip function was last tested.
Entergy subsequently determined that the MBFP trip function had never been tested
(CR-IP2-2016-02247) and therefore did not qualify for treatment as a missed
surveillance under SR 3.0.3. Entergy routinely tested the closure of the MBFP discharge
valves but not the associated MBFP trip function. Unit 2 was defueled at the time of
discovery on March 26, 2016, and this LCO did not apply at that time. Entergy
subsequently placed a mode hold (prohibition to enter mode 3 until corrected) on
CR-IP2-2016-02247 corrective actions and is currently evaluating the testing required to
restore full compliance with SR 3.7.3.3.
Analysis. The inspectors determined that failing to establish and conduct adequate
surveillance testing of the 21 and 22 MBFP trip circuitry as required by TS 3.7.3 was a
performance deficiency that was within Entergys ability to foresee and correct. This
finding is more than minor because it is associated with the procedural quality attribute
of the Mitigating Systems cornerstone and adversely affected the cornerstone objective
to ensure availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences (i.e., core damage). Specifically, Entergy
had not prepared a testing procedure to verify surveillance requirements were met. In
accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 3 of
IMC 0609, Appendix A, The Significance Determination Process for Findings at Power,
the inspectors determined that a detailed risk evaluation was required because the
finding represented a loss of function of a single train for greater than its TS AOT. A
27
detailed risk evaluation was conducted by a Region I SRA. The NRC risk models do not
model a main steam line or feedline break inside of containment without isolation, since
the total contribution to core damage is less than one percent. As a result, a qualitative
assessment was performed. The loss of the automatic trip of the MBFP, given a steam
or feed line break inside of containment, would result in the continuous feeding of hot
water into containment causing containment pressure and temperature to rise possibly
above the environmental qualification limits. This could impact the functionality of
mitigating equipment and instrumentation. The following were the major considerations
for the evaluation:
Unit 2 specific initiating event frequency of the event is relatively low at
approximately 4E-4/year
Isolation of the FRVs, or the FWIVs serves the same function as tripping the MBFP
and would likely prevent or minimize containment pressure and temperature rise
given the break inside of containment
NUREG-0933, Resolution of Generic Safety Issues, Item A-21: Main Steam Line
Break Inside Containment - Evaluation of Environmental Conditions for Equipment
Qualification (Revision 1), determined that equipment was not expected to fail if
temperatures were to rise slightly above the qualification temperatures
As described in the Indian Point Individual Plant Examination Section 3.1.3.4.2.7, if
feedwater isolation is successful, containment over pressure is controlled as long as
feed and bleed is successful and containment cooling continues to function.
Given that the total core damage contribution of this event is approximately 1E-7 and
based on the above considerations, the core damage risk was assessed to be very low
or Green.
This finding had a cross-cutting aspect in the area of Problem Identification and
Resolution, Evaluation, because Entergy failed to thoroughly evaluate the MBFP failure
to trip during the reactor trip of December 5, 2015, to ensure that corrective actions
address causes and extent of conditions commensurate with their safety significance.
Entergy did not adequately evaluate the underlying causes of the 21 MBFT failure to trip
when required to ensure that the actions taken to correct the problem identified in CR-
IP2-2015-05459 were comprehensive and addressed the underlying issues [P.2]
Enforcement. TS 3.7.3, SR 3.7.3.3, requires the MBFP trip function to be tested once
every 24 months in modes 1, 2, and 3. Contrary to this requirement, from original
construction until April 1, 2016, SR 3.7.3.3 was not adequately implemented and the
MBFPs trip function was not tested. Entergy entered this into their CAP
(CR-IP2-2016-02247) and assigned a mode 3 hold requirement to evaluate the testing to
comply with SR 3.7.3.3. Because this violation is of low safety significance (Green), and
Entergy entered this performance deficiency into their CAP, the NRC is treating this
violation as a NCV in accordance with section 2.3.2 of the NRC Enforcement Policy.
(NCV 05000247/2016001-04, Failure to Implement Surveillance Requirement for
Main Boiler Feed Pump Trip Function)
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.3 Annual Sample: Review of Root Cause Evaluation and Corrective Actions Associated
with the Unit 3 Main Transformer Failure
a. Inspection Scope
The inspectors performed an in-depth review of Entergys root cause evaluation and
corrective actions associated with CR-IP3-2015-02913, documenting the failure of the
31 main transformer. On May 9, 2015, a fault occurred on 31 main transformer, which
resulted in an automatic trip of the Unit 3 reactor. Entergy identified that a fault on the
transformer caused multiple protective relays to actuate as per design. The 31 main
transformer differential phase A and the Unit 3 differential phase A and phase B
relays actuated resulting in a turbine trip and reactor trip via main generator primary and
back-up lockout relays 86P and 86BU, respectively. As a result of this fault, the
transformer tank experienced a rapid increase in pressure. This sudden pressure
increase fractured the seam weld between the transformer cover and the side wall,
allowing the transformer oil to escape and become ignited. Entergys immediate
corrective action was to replace the failed transformer. On January 6, 2016, Entergy
completed the root cause evaluation report for the fault that occurred on the 31 main
transformer on May 9, 2015.
The inspectors assessed Entergys problem identification threshold, causal analyses,
technical analyses, extent of condition reviews, operational decision making, and the
prioritization and timeliness of corrective actions to determine whether Entergy was
appropriately identifying, characterizing, and correcting problems associated with this
issue. The inspectors focused on opportunities for Entergy to have identified any earlier
degradation of the transformer. The inspectors assessed Entergys transformer
condition monitoring program that included thermography, periodic oil screening, on-line
dissolved gas analysis, electrical testing, and periodic maintenance inspection of the
transformers.
b. Findings and Observations
No findings were identified.
The inspectors found that Entergy promptly initiated an investigation and chartered a
team to determine the root cause of the fault that resulted in the failure of the 31 main
transformer. Entergy additionally assessed all potential collateral damage in the vicinity
of the failed transformer. Entergys immediate corrective actions included replacing the
failed transformer, bushing apparatus, and portions of the iso-phase duct bus. Entergy
also completed an engineering assessment to assess the condition on the other
transformers prior to plant restart.
The inspectors determined that Entergys transformer condition monitoring plan,
including thermography, periodic oil screening, on-line dissolved gas analysis, electrical
testing, and periodic maintenance inspection was in agreement with the fleet template
and Electric Power Research Institute guidance. The inspectors verified that Entergy
took appropriate actions for reviewing the data gathered from the condition monitoring to
determine if it could have predicted a type of fault that resulted in the May 9, 2015,
failure. In addition, the inspectors reviewed documentation associated with this issue,
including failure investigation reports, equipment failure evaluation, and interviewed
engineering personnel to assess the effectiveness of the implemented and planned
29
corrective actions and to determine possible common elements among the past
transformer failures at Indian Point. A Special Inspection Team and resident inspectors
previously reviewed the plants response to the May 9, 2015, event, including
performance of the automatic shutdown systems, safety systems, and the activation of
the fire brigade. The review was documented in the Special Inspection Report
05000286/2015010 (ADAMS Accession No. ML15204A499) and in the event follow-up
inspection activities in NRC Integrated Inspection Report 05000247/2015002 and
05000286/2015002 (ADAMS Accession No. ML15222A186), Section 4OA3.1.
The inspectors review of the root cause analysis found that, due to the extent of the
damage caused by the event, the exact fault initiating location in the transformer could
not be identified. However, data gathered from the disturbance monitoring equipment
fault recorder, relay targets, visual inspection of the failed transformer, and detail
forensic inspection of coil assemblies and bushing, Entergy determined two possible
locations of the initiating fault that caused the rapid pressure increase in the transformer:
Directly in the high voltage A phase winding
Within the high voltage A phase bushing (internal to the transformer)
For each of the possible causes, the inspectors determined that Entergy has planned
corrective actions to ensure that a new transformer would not be subject to the same
conditions. Entergys corrective actions included adding enhanced testing requirements
of main transformers to perform partial discharge testing and requirements to perform
additional factory and site acceptance testing for new or currently ordered transformers.
The inspectors determined that Entergys overall response to the issue was
commensurate with the safety significance and the actions taken and planned were
reasonable to restore the main transformer to service and to ensure degradation did not
exist on the remaining transformers.
.4 Annual Sample: Initial and Subsequent Loss of 480V Vital Buses and Loss of RHR
Cooling
a. Inspection Scope
The inspectors performed a follow-up inspection for two electrical transients that
occurred on March 7, 2016, that both resulted in the loss of normal power to the 480V
vital buses and a loss of RHR cooling. The events occurred during cold shutdown
operations with the RCS pressurized at 330 psig, RCS temperature at 168°F, and
pressurizer level at 95 percent. Both RHR cooling trains were in service and the 24 RCP
was in service with all steam generators available for shutdown cooling. Throughout
both electrical transients, all steam generators and the 24 RCP remained in service and
available for RCS heat removal as the 24 RCP is powered from 6.9 kilovolt (kV) which
remained energized from off-site power. The initial loss of normal power to the 480V
vital buses resulted from actions taken during the preparation for the performance of 2-
PT-R084C, 23 EDG Eight-Hour Load Test. Entergy documented these electrical
transients in their CAP with CR-IP2-2016-01256 and CR-IP2-2016-01260 respectively.
The inspectors performed this follow-up inspection and focused on a review of the
operator response to the events and Entergys preliminary corrective actions. The
inspectors reviewed completed procedures, CRs, narrative logs, and interviewed the
operating crew, test team members, and engineering regarding the event and their
30
response. The inspectors reviewed the initial classification of the CRs and determined
that Entergy was conducting ACEs for both transients in accordance with Entergys CAP
procedure, EN-LI-102.
b. Findings and Observations
On March 7, 2016, Unit 2 experienced two losses of normal power to the 480V vital
buses that resulted in a loss of the RHR system. The first loss occurred when 480V vital
buses 3A and 6A were inadvertently overloaded during a surveillance test of the
23 EDG. Procedural direction to the operators was not sufficient to prevent this event
from occurring. This event is the subject of a Green NCV in the section that follows.
The subsequent loss of 480V vital bus power occurred approximately one hour later
when the 23 EDG tripped while powering the 6A bus. The cause of this second trip is
still under review by Entergy, and the NRC opened an URI to further assess the issue.
Initial Loss of 480V Vital Buses and Loss of RHR Cooling
Introduction. A self-revealing Green NCV of TS 5.4.1, Procedures, was identified for
Entergys failure to provide adequate guidance in procedure 2-PT-R084C, 23 EDG
Eight-Hour Load Test. Specifically, Entergy failed to provide adequate procedural
guidance in order to prevent an overcurrent condition on the 480V bus normal feeder
breaker. As a result, the plant experienced a loss of normal power to their four 480V
vital buses and a loss of RHR cooling.
Description. On March 7, 2016, while operators were cooling down the RCS and raising
pressurizer level in preparation for taking the pressurizer solid, the operations test group
was performing surveillance procedure 2-PT-084C, 23 EDG Eight-Hour Load Test. At
10:04 a.m., the test group had completed the breaker alignment in accordance with
section 4.2. This section cross-tied the 3A and 6A 480V vital buses by closing the
52/3AT6A tie breaker and then opening the 52/6A breaker; normal feed (i.e., offsite
power) to the 6A 480V bus. The plant was in cold shutdown (mode 5). Both RHR
cooling trains were in service and the 24 RCP was in service with all steam generators
available. At approximately 10:10 a.m., the control room received a switch gear 21 or
22 under-voltage overhead alarm (SGF 4-6). The operating crew responded to the
alarm and stopped the 26 service water pump, which cleared the alarm condition. The
operations test group continued performance of the surveillance procedure and at
10:17 a.m. started the 23 EDG in unit mode of operation in preparation for subsequent
parallel operation with the cross-tied 3A-6A 480V buses. At 10:18 a.m. the 52/3A; 480V
bus 3A normal feed breaker tripped open on an overcurrent condition. Because of the
electrical lineup required by the 23 EDG load test surveillance, this resulted in the loss of
the 3A and 6A 480V buses and initiated the station blackout signal with unit trip logic.
That load shed all the 480V vital buses, started all three EDGs, and loaded three of the
four vital buses; 5A, 2A, and 6A buses on the 21, 22, and 23 EDGs respectively. The 3A
bus was locked out due to the overcurrent trip that occurred on the 3A normal feed
breaker. Offsite power was maintained throughout the event.
The operating crew responded to this electrical transient entering 2-AOP-480V-1, Loss
of Normal Power to Any 480V Bus, and 2-AOP-RHR-1, Loss of RHR. The RHR
cooling was restored within three minutes. Throughout the transient, 24 RCP remained
in service and available for RCS heat removal as it is powered from 6.9 kV which
remained energized from offsite power.
31
Investigation by Entergy determined that the initial transient initiated by the opening of
the 52/3A breaker was caused by an actual overcurrent condition. Entergy determined
that the total 6.9 kV current on buses 3 and 6 prior to tying buses was observed to be
approximately 280 amps. This equated to approximately 3,940 amps transformed
through the station service transformer on the 480V side for buses 3A and 6A. The long
delay trip setting for breaker 52/3A is equivalent to 3,600 amps on the primary 480V
side. The procedure provided a precaution and limitation that stated that the maximum
current for the breaker should be maintained below 3,240 amps (90 percent of the
breaker trip setting of 3,600 amps). However, the procedure provided no guidance to
the operator as to how to convert current indications at 6.9 kV across the station service
transformers into current indications at 480V to ensure this load limit was not exceeded
as there was no direct indication of current on the 3A and 6A 480V vital
buses. Corrective actions included entering the issue into their CAP (CR-IP2-2016-
01256) and revising their procedure to add a more specific amperage restriction and the
control room indication to be used to ensure the amperage limitation was met.
Analysis. The inspectors determined that failing to maintain adequate procedural
guidance in the surveillance procedure to prevent an overcurrent condition was a
performance deficiency that was reasonably within Entergys ability to foresee and
correct and should have been prevented. The finding was more than minor because it is
associated with the procedure quality attribute of the Initiating Events cornerstone and
adversely affected the cornerstone objective to limit the likelihood of events that upset
plant stability and challenge critical safety functions during shutdown. The performance
deficiency caused a loss of normal power to the vital 480V buses which also resulted in
a loss of RHR event. The Region I SRA used IMC 0609, Appendix G, Shutdown
Operations Significance Determination Process, to assess the safety significance of this
event. The SRA determined that Worksheet 3, best represented the actual event and
associated mitigation systems available. Although not actually relied upon, steam
generators remained available and the 24 RCP remained running during the transient to
support decay heat removal if shutdown cooling had not been promptly restored. The
SRA assumed full equipment credit and operator recovery credit for this finding, resulting
in a low E-7 increase in core damage frequency. This finding was of very low safety
significance (Green).
This finding had a cross-cutting aspect in the area of Human Performance, Challenge
the Unknown, because personnel did not stop when faced with uncertain conditions.
Uncertain conditions initially presented themselves to Entergy prior to the start of the
23 EDG eight-hour load test surveillance when the switch gear 21 or 22 under-voltage
overhead alarm (SGF 4-6) was received before the first transient. Later, the operators
were provided with a load limit in the test procedure and did not know how to convert the
6.9 KV bus current loading to 480 V current loading on the vital buses. The operators
proceeded on in the test procedure in the face of uncertainty. [Challenge the Unknown
- H.11]
Enforcement. Unit 2 TS 5.4.1 requires that adequate written procedures shall be
established, implemented, and maintained for procedures referenced in Appendix A of
Regulatory Guide 1.33, Revision 2. Appendix A, Section 8.b.1(q), requires specific
procedures for emergency power surveillance tests. Contrary to the above, Entergy did
not adequately maintain surveillance procedure 2-PT-084C, 23 EDG Eight-Hour Load
Test, by failing to include specific steps or precaution detail to preclude an overcurrent
condition on the 52/3A; 3A 480V bus normal feed breaker. Corrective actions included
32
revising their procedure to add a more specific amperage restriction on the vital buses
and designating the control room indication to be used to ensure the amperage limitation
was met. Because this violation was of very low safety significance (Green) and has
been entered into their CAP (CR-IP2-2016-01256), this violation is being treated as an
NCV consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000247/2016001-
05, Failure to Provide Adequate Procedural Guidance in Order to Prevent an
Overcurrent Condition)
Subsequent Loss of 480V Vital Buses and Loss of RHR Cooling
Introduction. Following the initial loss of 480V vital buses and loss of RHR cooling, the
operating crew was taking actions to restore normal power to all 480V buses. Before the
crew was able to restore off-site power to the 6A bus, the 23 EDG tripped on overcurrent
resulting in a loss of bus 6A and the subsequent blackout/unit trip signal that stripped all
loads from the remaining 480V buses. The cause of this second trip is still under review
by Entergy, and the NRC opened an URI related to this concern to assess whether a
performance deficiency exists.
Description. 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 bus. The
operators responded by re-entering 2-AOP-480V-1, Loss of Normal Power to Any 480V
Bus, and 2-AOP-RHR-1, Loss of RHR. The RHR cooling was restored within five
minutes. Throughout the transient, 24 RCP remained in service and available for RCS
heat removal as it is powered from 6.9 kV which remained energized from offsite power.
Due to ongoing performance of restoration actions from the previous trip, the 21 EDG
was not ready to automatically start, so initially only the 2A bus loaded on the 22
EDG. The delay in the starting of 21 EDG combined with the associated loss of 23 vital
instrument bus resulted in loss of power to the C pressurizer level channel which then
caused both a loss of letdown and loss of pressurizer heaters. These conditions along
with the malfunctioning of the 24 loop pressurizer spray valve controller created
additional challenges to the operator tasked with controlling pressurizer pressure and
level. The delay in the start of the 21 EDG also affected the operator tasked with
restoring RHR as the RHR heat exchanger outlet motor operated valves associated with
21 RHR pump were powered from the 5A bus. The crew was able to restore the 3A bus
with the 22 EDG, and then start the 21 RHR pump. The 6A bus remained de-energized
until the crew restored 6A via off-site power. The 23 EDG was declared inoperable. By
1:49 p.m., all four 480V buses were restored to off-site power; and by 2:07 p.m., 21 and
22 EDGs had been shut down and returned to standby (auto start) condition.
Entergys initial review of the second electrical transient determined the most probable
cause was a spurious actuation of the A, B, or C phase voltage controlled overcurrent
relays. These relays were replaced under WO 00440073 with spare, calibrated
relays. Operator observations during the event indicated that the 23 EDG breaker
tripped while loads were still being added, including the start of the turbine auxiliary
bearing oil pump and various motor control centers, but the 23 EDG load never
exceeded the continuous load rating of 1750 kilowatt (kW). Local diesel observations
indicated approximately 1650 kW load on the 23 EDG just prior to the trip. Entergy then
concluded that all other equipment functioned as per design and that a monthly load test
surveillance would be utilized to determine operability after replacing the overcurrent
relays. On March 8, 2016, 23 EDG was declared operable following successful
completion of the monthly diesel surveillance procedure. The 23 EDG was run, closed
33
onto Bus 6A, and loaded to 2275 kW. Later, as-found bench testing of the overcurrent
relays indicated that the relay trip settings were within calibration and should have
functioned as designed.
Subsequently, on March 10, 2016, during performance of PT-R14, Automatic Safety
Injection System Electrical Load and Blackout Test, 23 EDG exhibited anomalous
behavior during the train B load sequencing. During the test, the voltage on bus 6A
dropped to approximately 200V when the 23 AFW pump was sequenced onto the bus
(CR-IP2-2016-01430). 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 found a degraded resistor
associated with the 23 EDG automatic voltage regulator. The 23 EDG voltage regulator
was replaced, and the 23 EDG was again tested satisfactorily. The low voltage issue
exhibited during PT-R14, Automatic Safety Injection System Electrical Load and
Blackout Test, was documented in CR-IP2-2016-01430 and has been closed in
CR-IP2-2016-01260 to be included in the ACE associated with the tripping of 23 EDG
breaker on March 7, 2016. Entergy was in the process of performing a failure analysis
and an ACE at the end of the inspection period. NRC review of Entergys failure
analysis and causal evaluation will be performed to evaluate if a performance deficiency
exists. The inspectors determined that the issue is an URI. (URI 05000247/2016001-
06, 23 Emergency Diesel Generator Automatic Voltage Regulator Failure)
4OA3 Follow Up of Events and Notices of Enforcement Discretion (71153 - 4 samples)
.1 Plant Events
a. Inspection Scope
For the plant events listed below, the inspectors reviewed and/or observed plant
parameters, reviewed personnel performance, and evaluated performance of mitigating
systems. The inspectors communicated the plant events 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. As applicable, the inspectors verified that Entergy made appropriate
emergency classification assessments and 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 corrective actions
commensurate with their safety significance.
Unit 2
Reverse osmosis (RO) skid leak and report of high tritium levels in monitoring wells
on February 5, 2016. A description of this event and associated URI is located in
section 4OA5 of this report
Loss of normal power to 480 VAC vital buses and shutdown cooling on March 7,
2016. A description of this event, associated Green NCV, and URI is listed in section
4OA2.4 of this report
Review of a 10 CFR 50.72 report of degraded core baffle former bolts on March 28,
2016. A description of this event and URI is located in section 1R18 of this report
34
b. Findings
No findings were identified.
4OA5 Other Activities
Groundwater Contamination
a. Inspection Scope
On February 5, 2016, Entergy notified the NRC of a significant increase in groundwater
tritium levels measured at three monitoring wells (MWs)(MW-30, MW-31, and MW-32)
located near the Unit 2 Fuel Storage Building (FSB). These samples were drawn on
January 26-27, 2016, and analyzed and confirmed on February 2-4, 2016.
The highest concentration was detected at MW-32, which increased from 12,000 pCi/l
on January 11, 2016, to 8,100,000 pCi/l on January 26, 2016, and subsequently up to
14,800,000 pCi/l on February 4, 2016. This increased tritium concentration event was
documented by Entergy in CR-IP2-2016-00564. The NRC resident inspectors began an
immediate review of this incident, and a region-based specialist inspector conducted a
walk down of associated Unit 2 radioactive waste drain systems and components on
February 11, 2016. The specialist inspector also conducted additional on-site inspection
activities on March 6-10, 2016, to review Entergys continuing investigation into the
event. Representatives of New York State Departments of Environmental Conservation
and Health and the Environmental Protection Agency, Region II, accompanied portions
of these on-site inspection activities.
b. Findings and Observations
Introduction. The inspectors identified an URI related to whether a performance
deficiency exists associated with Entergys controls to prevent the introduction of
radioactivity into the site groundwater were adequate. Specifically, Entergy obtained
increased tritium concentrations from groundwater MW 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.
Description. The initial Entergy investigation focused on identifying the source of the
contamination which was preliminarily determined to originate from the reject water of
the RO skid that was in service from January 16-31, 2016. This cause 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. Entergy has yet to identify the specific leakage pathway or the root
cause for this event. An URI is initiated for further determination of whether a
performance deficiency exists following Entergys finalization of their root cause analysis.
(URI 5000247/2016001-07, January 2016 Groundwater Contamination)
Observations
Following identification of the increased groundwater tritium, Entergy promptly
assembled a dedicated project manager and investigation team that included
35
representatives of radiation protection, chemistry, operations, engineering, maintenance,
hydrogeology contractor, root cause investigation, and CAP staff. The initial Entergy
investigation focused on identifying the source of the contamination, which was
determined to originate from the reject water of the RO skid that was in service from
January 16-31, 2016. The RO skid was used to filter water from the Unit 2 refueling
water storage tank and the reject water contains the filter backwash concentrates from
that operation. The source determination was based on the timing of the groundwater
contamination event and on the unique matching of the radionuclide signature from the
groundwater samples and the RO skid reject water concentrated radioactivity. The
reject water from the RO skid has a unique radiological signature relative to other
sources of water at Unit 2, with a very high concentration of Antimony-125 (Sb-125). In
addition to the high tritium levels seen at MW-32, a high concentration of Sb-125
(5540 pCi/l) was detected, with a trace amount (27 pCi/l) of Cobalt-60. Entergy did not
report detection of any other isotopes (including Sr-90) in these MWs subsequent to this
release. Along with the timing of the RO skid operation and the unique radionuclide
comparison match up with the groundwater results, this provides reasonable confidence
that the RO skid is the source of the groundwater contamination.
This investigation identified two previous CRs (CR-IP2-2016-00264 and
CR-IP2-2016-00266), both initiated on January 17, 2016, which documented a leak and
floor ponding observed inside the Unit 2 PAB during the time of the initial operation of
the RO skid. On February 5, the resident inspectors conducted a walkdown of the
drainage path and on February 11, 2016, NRC inspectors conducted a walk-down of
various locations associated with the drainage path from operation of the RO skid, and
observed evidence of recent prior spills of water inside the radiological controlled area of
the PAB, both on the 35-foot elevation of the PAB (CR-IP2-2016-00264) and in the FSB
pump pit (CR-IP2-2016-00266).
Entergys investigation focused on examination of possible leakage pathways of the RO
skid reject water on the drainage flow path from the RO skid located on the 95-foot
elevation of the maintenance and outage building (MOB) to the Unit 2 waste hold-up
tank (WHUT). This pathway included a floor drain between the MOB and the FSB sump,
a temporary hose from the FSB sump to a floor drain, a floor drain to the 15-foot
elevation PAB sump, and a pipe from the 15-foot PAB sump to the WHUT. Based on
this investigation, Entergy initially identified: 1) at least three partial blockages in the
floor drain pathway between the MOB and the WHUT, 2) the FSB 28 sump pump was
out of service, resulting in a different drain pathway from the RO skid to the 15-foot
elevation PAB sump, and 3) two floor drains from the 51-foot elevation pipe penetration
room had been previously cut open for inspection, but not capped or sealed. This
resulted in water spilling out of the floor drain piping onto the floor of the 35-foot
elevation PAB pipe chase. The evidence of spillage on the 35-foot elevation of the PAB
would provide a leak pathway to the groundwater through a seismic gap between the
PAB and the Unit 2 containment. This spill elevation is below the elevation monitored by
MW-32 (equivalent to the 45-foot elevation), therefore, Entergy continues to investigate
an additional higher elevation leakage pathway. This additional leak pathway has not
been determined.
Entergys short-term corrective actions to preclude recurrence of this event included
review and inspection of all Unit 2 floor drains to be used during the RFO 2R22.
Seventeen partial blockages were identified and cleared prior to the commencement of
RFO 2R22. The FSB sump was repaired and placed back in service. The two open
36
floor drain pipes located above the 35-foot elevation PAB pipe chase were capped. In
addition, to reduce the tritium groundwater concentrations in the vicinity of Unit 2,
beginning on March 16, 2016, Entergy began pumping water from MW-32 and sending
the tritiated water back into the PAB for liquid radioactive waste processing. That action
is designed to lower groundwater tritium monitoring well concentrations to normal levels
in order to provide sensitivity to detect any new plant leaks.
Entergys long-term corrective action for reducing tritium levels in the groundwater is the
same as previously identified for the March 2014 tritium spike (CR-IP2-2015-03806), the
start-up and operation of recovery well 1. Following installation of equipment and
system testing, full operation of the recovery well system is scheduled by the end of the
summer 2016. This system will allow for the collection of tritiated groundwater to be
returned inside the PAB for processing. Entergys investigation of the current leak event
is still ongoing to identify the leakage pathway to groundwater as measured in MW-32
and once complete, the investigation report will be reviewed and assessed during a
future inspection.
The NRC assessment of the safety significance of this event focused on validating the
safety impact of dose to the public from the release of tritium to the site groundwater,
and ultimately to the Hudson River. Two months after detection of the leak in
groundwater MW-32, the groundwater tritium contamination from this event has not
migrated downstream to the other on-site monitoring wells indicating that the tritium
contamination has not yet reached the Hudson River. The NRC verified that Entergys
bounding public dose calculations on the groundwater contamination leak was
conservative and a maximum worst case scenario would result in a dose of 0.000112
mrem per year, which represents a very small fraction of the allowable dose (liquid
effluent dose objective of 3 millirem per year). This low value is due to groundwater at
Indian Point not being a source of any drinking water. There are no drinking water wells
on the Indian Point site, groundwater flow from the site is to the Hudson River and not to
any near site drinking water wells, and the Hudson River has no downstream drinking
water intakes as it is brackish water. Pathways to the public are therefore limited to the
consumption of fish and river invertebrates. The inspection determined that there is no
safety impact to the public as a result of this groundwater contamination event.
4OA6 Meetings, Including Exit
On April 29, 2016, the inspectors presented the inspection results to Mr. Larry Coyle,
Site Vice President, and other members of Entergy. 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
L. Coyle, Site Vice President
J. Dinelli, Plant Operations General Manager
R. Alexander, Unit 2 Shift Manager
T. Alexander, Operator at the Controls, RO
N. Azevedo, Code Programs Supervisor
J. Baker, Unit 2 Shift Manager
J. Balletta, Unit 2 Control Room Supervisor
K. Baumbach, Chemistry Supervisor
S. Bianco, Operations Fire Marshal
K. Brooks, Unit 2 Assistant Operations Manager
R. Burroni, Engineering Director
T. Chan, Engineering Supervisor
T. Cramer, Unit 3 Shift Manager
D. Dewey, Assistant Operations Manager
J. Dignam, Unit 3 Control Room Supervisor
R. Dolansky, ISI Program Manager
R. Drake, Civil Design Engineering Supervisor
B. Durr, Shift Outage Manager
P. Egan, Unit 2 Control Room Supervisor
K. Elliott, Fire Protection Engineer
J. Ferrick, Production Manager
L. Frink, ALARA Supervisor
M. Fritz, Unit 3 Reactor Operator
D. Gagnon, Security Manager
R. Gioggia, System Engineer
L. Glander, Emergency Preparedness Manager
Ed Goetchius, Instructor, Ops Sr. Staff Nuclear
J. Graham, Unit 3 Shift Manager
W. Guerrier, Unit 3 Nuclear Plant Operator
J. Hill, Supervisor, Engineering
J. Johnson, Unit 2 Control Room Supervisor
M. Johnson, Unit 3 Shift Manager
A. Kaczmarek, Engineering Supervisor, Engineering
F. Kich, Performance Improvement Manager
A. King, Senior Lead Nuclear Engineer
J. Kirkpatrick, Regulatory and Performance Improvement Director
C. Kocsis, Senior Operations Instructor
P. Labuda, Unit 2 Reactor Operator
N. Lizzo, Training Manager
G. Leveque, Maintenance Planner
M. Lewis, Assistant Operations Manager
R. Louie, 95 Hill Coordinator
D. Martin, Unit 2 Control Room Supervisor
G. Martin, Unit 2 Reactor Operator
R. Martin, Senior Project Manager
D. Mayer, Unit 1 Director
Attachment
A-2
B. McCarthy, Operations Manager
K. McKenna, Unit 2 Shift Manager
F. Mitchell, Radiation Protection Manager
R. Montross, Unit 2 Shift Manager
E. Mullek, Maintenance Manager
G. Norton, Instructor, Operations Senior Staff
T. Oggeri, Unit 3 Control Room Supervisor
J. Ready, Unit 2 Field Support Supervisor
K. Robinson, Lead Controller, Senior Emergency Planner
S. Ryan, Unit 2 Control Room Supervisor
T. Salentino, Vapor Containment Coordinator
C. Smyers, Manager, Chemistry
T. Soohoo, Junior Nuclear Electrical Technician
D. Sparozic, System Engineer
S. Stevens, Radiation Protection Operations Superintendent
C. Stuart, Unit 3 Nuclear Plant Operator
M. Tesoriero, System Engineering Manager
M. Troy, Nuclear Oversight Manager
B. Ulrich, Unit 2 Control Room Supervisor
J. Varga, Reactor Operator
R. Walpole, Regulatory Assurance Manager
A-3
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened
05000247/2016001-01 URI Baffle-Former Bolts with Identified Anomalies
(Section 1R08)05000286/2016001-03 URI Inadequate Screening of Reactor Protection
System Test Method Change (Section 1R18)05000247/2016001-06 URI 23 Emergency Diesel Generator Automatic Voltage
Regulator Failure (Section 4OA2)05000247/2016001-07 URI January 2016 Groundwater Contamination
(Section 4OA5)
Opened/Closed
05000247/05000286/ NCV Failure to Adequately Implement Risk
2016001-02 Management Actions for the Containment Key
Safety Function (Section 1R13)05000247/2016001-04 NCV Failure to Implement Surveillance Requirement for
Main Boiler Feed Pump Trip Function
(Section 4OA2)05000247/2016001-05 NCV Failure to Provide Adequate Procedural
Guidance in Order to Prevent an Overcurrent
Condition (Section 4OA2)
LIST OF DOCUMENTS REVIEWED
Common Documents Used
Indian Point Unit 2, Updated Final Safety Analysis Report
Indian Point Unit 2, Individual Plant Examination
Indian Point Unit 2, Individual Plant Examination of External Events
Indian Point Unit 2, Technical Specifications and Bases
Indian Point Unit 2, Technical Requirements Manual
Indian Point Unit 2, Control Room Narrative Logs
Indian Point Unit 2, Plan of the Day
A-4
Section 1R01: Adverse Weather Protection
Procedures
OAP-008, Severe Weather Preparations, Revision 23
OAP-048, Seasonal Weather Preparation, Revision 17
Condition Reports (CR-IP2-)
2016-00383 2016-00387 2016-00388
Condition Reports (CR-IP3-)
2016-00243 2016-00246 2016-00247
Section 1R04: Equipment Alignment
Procedures
3-PT-R007A, 31 & 33 ABFPs Full Flow Test, Revision 20
3-PT-R007B, 32 ABFP Full Flow Test, Revision 17
3-SOP-AFW-001, Auxiliary Feedwater System Operation, Revision 9
3-SOP-AFW-002, Auxiliary Feedwater System Support Procedure, Revision 4
Condition Reports (CR-IP3-)
2014-02289 2014-02667 2015-02765 2015-02766 2015-02843 2015-02844
2015-03119 2016-00748
Maintenance Orders/Work Orders
WO 00257935 WO 00297321 WO 00306381 WO 00374110
WO 00395789 WO 00397634 WO 00405016 WO 00413164
WO 00413977 WO 00413979 WO 51421683 WO 52422135
WO 52479901
Drawings
9321-F-20183, Flow Diagram Condensate & Boiler Feed Pump Suction, Revision 64
9321-F-20173, Flow Diagram Main Steam, Revision 72
9321-F-20193, Flow Diagram Boiler Feedwater, Revision 63
Section 1R05: Fire Protection
Condition Reports (CR-IP2-)
2016-02117
Condition Reports (CR-IP3-)
2016-00825
Miscellaneous
PFP 306A, Component Cooling Pumps - Primary Auxiliary Building, Revision 0
PFP-345, Auxiliary Feedwater Pump Room - Auxiliary Feedwater Building, Revision 15
PFP-366, Chemical Additive Room - Auxiliary Feedwater Building, Revision 13
PFP-304, General Floor Plan - Primary Auxiliary Building, Revision 11
A-5
Section 1R06: Flood Protection Measures
Procedures
0-ELC-418-GEN, Manhole Inspections, Revision 5
2-AOP-FLOOD-1, Flooding
Maintenance Orders/Work Orders
Section 1R08: Inservice Inspection Activities
Procedures
2-PT-R156, RCS Boric Acid Leakage and Corrosion Inspection, Revision 4
2-PT-R203, Visual Examination of Reactor Vessel Head Penetrations and Head Surface for
Leakage, Revision 5
CEP-NDE-0255, Radiographic Examination for ASME Welds and Components, ASME XI,
Revision 8
CEP-NDE-0404, (PDI UT-1), Manual UT of Ferritic Piping Welds (ASME XI), Revision 5
CEP-NDE-0407, Straight Beam Ultrasonic Examination of Bolts and Studs, Revision 4
CEP-NDE-0423, (PDI UT-2), Manual Ultrasonic Examination of Austenitic Piping Welds
(ASME XI), Revision 7
CEP-NDE-0485, Manual Ultrasonic Examination of Vessel Nozzle, Inside Radius
(Non-App. VIII), Revision 12
CEP-NDE-0497, Manual UT Examination of Welds in Vessels (Non-APP. VIII), Revision 5
CEP-NDE-0504, Ultrasonic Examination of Small Bore Diameter Piping for Thermal Fatigue
Damage, Revision 4
CEP-NDE-0641, Liquid Penetrant Examination for ASME,Section XI, Revision 7
CEP-NDE-0731, Magnetic Particle Examination for ASME,Section XI, Revision 5
CEP-WR-WIIR-1, Weld In-Process Inspection Requirements, Revision 3
PDI-ISI-254-NZ, Remote Inservice Examination (UT) of Reactor Vessel Nozzle to Shell Welds,
Revision 1
SEP-BAC-IPC-001, Boric Acid Corrosion Control Program, Revision 2
WDI-STD-1040, Ultrasonic Examination of Reactor Vessel Head Penetrations, Revision 12
WDI-STD-1073, Ultrasonic Examination of Baffle-Former Bolts with Welded Lock Bars,
Revision 4
Condition Reports (CR-IP2-)
2015-00167 2015-03550 2015-04170 2015-05358 215-05755
2016-01328 2016-01341 2016-01719
Maintenance Orders/Work Orders
WO 00402460 WO 00422552 WO 00424961 WO 00431643
Drawings
A206914-2, ISI Identification Drawing for Steam Generator 21R, Revision 2
B206715, ISI Isometric, Chemical and Volume Control Line 81, Welds 3 and 4, Revision 5
B206699, ISI Isometric, Safety Injection Line 56, Welds 139,140,141,142,143, and 144,
Revision 5
Miscellaneous
AREVA Document 51-9213207-001. IP Unit 2, 2R21 Steam Generator Degradation
Assessment - 10/21/2013.
A-6
WDI-PJF-1315507-EPP-001, IP Unit 2, 2016-Reactor Vessel 10-year Examinations including
Vessel Visuals, Examination Program Plan (Scan Plan), Revision 1
WDI-PJF-1315504-EPP-001, Indian Point Nuclear Power Plant MRP-227A, Reactor Vessel
Internals Examination Program Plan
NRC (11/10/1998) Safety Evaluation of Topical Report WCAP-15029 Westinghouse
Methodology for Evaluating the Acceptability of Baffle-Former-Barrel Bolting distributions
Under Faulted Load Conditions
Drawing, D207780-0. Details of Weld 21-14 and the Cold Leg 182 DM weld, Safe End to RPV
Nozzle
MRP-227-A, Materials Reliability Program: PWR Internals Inspection and Evaluation Guidelines,
1022863
MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals, 1016609
ASME Code Case N-729-1, Examination of PWR upper head to CRDM welds
NRC Information Notice No. 98-11: Cracking of Reactor Vessel Internal Baffle Former bolts in
Foreign Plants
Section 1R11: Licensed Operator Requalification Program
Procedures
2-E-0, Reactor Trip or Safety Injection, Revision 6
2-ES-0.1, Reactor Trip Response, Revision 5
2-POP-2.1, Operation at Greater than 45% Power, Revision 62
2-POP-3.1, Shutdown from 45 Percent Power, Revision 57
2-POP-3.2, Plant Recovery from Trip, Hot Standby, Revision 40
2-POP-3.3, Plant Cooldown - Hot to Cold Shutdown, Revision 79
3-ARP-003, Panel SAF - Reactor Coolant System, Revision 49
2-POP-1.3, Plant Startup from Zero to 45% Power, Revision 88
2-AOP-UC-1, Uncontrolled Cooldown, Revision 6
2-AOP-LOAD-1, Excessive Load Increase or Decrease, Revision 6
2-AOP-INST-1, Instrumentation/Controller Failures, Revision 8
2-AOP-FW-1, Loss of Main Feedwater, Revision 13
Condition Reports (CR-IP3-)
2016-00746
Section 1R12: Maintenance Effectiveness
Condition Reports (CR-IP2-)
2014-00397 2014-04458 2015-01939 2016-00064 2016-00109
Maintenance Orders/Work Orders
WO 00326236 WO 00412920 WO 00433939 WO 52596628
Miscellaneous
Maintenance Rule (a)(1) Evaluation dated February 24, 2016
Section 1R13: Maintenance Risk Assessments and Emergent Work Control
Procedures
IP-SMM-00-104, Attachment 9.2, Shiftly Outage Shutdown Safety Assessment Guidelines,
Revision 14
0-CON-401-EQH, Removal and Replacement of 16-Foot Diameter Equipment Hatch Assembly,
Revision 10
A-7
Condition Reports (CR-IP2-)
2016-01251 2016-01503
Maintenance Orders/Work Orders
Miscellaneous
EC 17512, Installation of IP2 Equipment Hatch Closure Plug Requirement
ORAT Report, Revision 1
Section 1R15: Operability Determinations and Functionality Assessments
Procedures
2-PT-R084C, Revision 16, 23 EDG 8 Hour Load Test
2-PT-R084C, Revision 17, 23 EDG 8 Hour Load Test
EN-LI-102, Corrective Action Program
EN-OP-104, Operability Determination Process
Condition Reports (CR-IP2-)
2015-05358 2016-01430 2016-01256 2016-01259 2016-01260 2016-01266
2016-01355 2016-01430 2016-01500
Drawings
Drawing 9321-F-2735-141, Flow Diagram Safety Injection System
Drawing B206725-06, Indian Point Unit 2 Inservice Inspection Isometric of Safety Injection Line
Number 155
Miscellaneous
IP-CALC-15-00098
IP-CALC-16-00030
IP-UT-15-045, UT Erosion/Corrosion Examination Service Water 21 Component Cooling Water
Heat Exchanger, dated December 1, 2015
EC 61758, Evaluation of Through-Wall Leak at 21 Component Cooling Water Heat Exchanger
Inlet Weld, Revision 0
Section 1R18: Plant Modifications
Procedures
3-POP-3.1, Plant Shutdown from 45 Percent Power, Revision 48
EN-OP-112, Night and Standing Orders, Revision 2
Condition Reports (CR-IP3-)
2014-01903 2016-00664 2016-00665 2016-00667 2016-00683 2016-00716
Maintenance Orders/Work Orders
WO 52630783 WO 52630629 WO 52630784
Drawings
113E301, Sheet 2, Reactor Protection System Schematic Diagram, Revision 13
113E301, Sheet 3, Reactor Protection System Schematic Diagram, Revision 10
Miscellaneous
EC 63282, Temporary Modification to Crab in the Failed 15-B Relay
A-8
Standing Order 16-04
Section 1R19: Post-Maintenance Testing
Procedures
EN-OP-104, Operability Evaluation, Revision 10
EN-FAP-LI-001 Attachment 7.8
PC-OLO3C, Pressurizer Level Loops L-461 and L-462 Channel Calibration, Revision 3
Condition Reports (CR-IP2-)
2015-03550 2015-05728 2015-05764 2015-05755 2016-00435
Maintenance Orders/Work Orders
WO 00431643-11 WO 52658166 WO 52658168 WO 52571893
WO 52521379 WO 00367766
Drawings
A236318
Miscellaneous
E-mail from T. Schaefer to J. Kosack; Subject: NUS Module Receipt, dated January 14, 2016
FI5565-R-001, LPI Failure Analysis Report, Revision 1
Scientech Bill of Lading #5564 Curtis Wright Certificate of Compliance PO#1045804
Section 1R22: Surveillance Testing
Procedures
2-PT-R094C, 23 EDG 8-Hour Load Test, Revision 16
2-PT-R094C, 23 EDG 8-Hour Load Test, Revision 18
3-PT-Q120B, 32 Auxiliary Boiler Feedwater Pump (Turbine Driven) Surveillance and Inservice
Test, Revision 25
2-PT-R006, Main Steam Safety Valve Setpoint Determination, Revision 31
Condition Reports (CR-IP2-)
2015-00237 2016-01204
Condition Reports (CR-IP3-)
2015-06004 2016-00257
Maintenance Orders/Work Orders
WO 52568432 WO 52575711 WO 52646946 WO 52667347
WO 52668028-01
A-9
Section 1EP6: Drill Evaluation
Procedures
3-E-0, Reactor Trip or Safety Injection, Revision 6
3-E-1, Loss of Reactor or Secondary Coolant, Revision 4
3-ES-1.3, Transfer to Cold Leg Recirculation, Revision 9
3-FR-P.1, Response to Imminent Pressurized Thermal Shock, Revision 4
Emergency Action Level, Revision 15-2
EN-EP-306, Drills and Exercises, Revision 7
EN-EP-308, Emergency Planning Critiques, Revision 3
Condition Reports (CR-IP3-)
2015-03588 2016-00218 2016-00231 2016-00232 2016-00233 2016-00252
Miscellaneous
All ENS notification forms created during the exercise
All press releases created during the exercise
Exercise Report, dated March 3, 2016
Exercise Scenario, dated February 20, 2016
Section 4OA1: Performance Indicator Verification
Procedures
0-SOP-LEAKRATE-001
3-CY-2325, Radioactive Sampling Schedule, Revision 14
3-CY-2765, Coolant Activity Limits - Dose Equivalent Iodine/Xenon, Revision 5
Condition Reports (CR-IP3-)
2016-00823
Section 4OA2: Problem Identification and Resolution
Procedures
2-PT-R084C, 23 EDG Eight-Hour Load Test, Revision 16
2-PT-R084C, 23 EDG Eight-Hour Load Test, Revision 17
2-AOP-480V-1, Loss of Normal Power to Any 480V Bus
2-AOP-RHR-1, Loss of RHR
EN-LI-102, Corrective Action Program
EN-OP-104, Operability Determination Process
2-PT-V024-DS060, Valve BFD-2-21 Inservice Test Data Sheet, Revision 10
Condition Reports (CR-IP2-)
2015-05459 2016-01256 2016-01259 2016-01260 2016-01266 2016-01355
2016-01430 2016-01500 2016-02247*
Condition Reports (CR-IP3-)
2011-04339 2015-02755 2015-02913 2015-02916 2016-00626*
- Denotes CR initiated as a result of the inspection
Maintenance Orders/Work Orders
00305415-03, 2Y Electrical Test 31 Main Transformer, completed on March 10, 2013
A-10
524885-6-01, 1Y Inspection of Transformer IAW 3-XFR-010-ELC, completed on May 6, 2014
52502455-01, 4Y Transformer CT Testing, completed on March 16, 2015
52507155-01, 4Y Transformer Heat Exchanger Inspection, completed on March 19, 2015
Drawings
250907-35
9321-3140 Sheet 12, Boiler Feed Pump #22 Turbine Trip and Reset, Revision 34
IP2_SOD_013, Feedwater System, Revision 2
Miscellaneous
IP3-2012-00402, Operational Decision Making Issue Process for 31 Main Transformer Gassing,
Revision 3
IP3-2014-00524, Operational Decision Making Issue Process for 31 Main Transformer Gassing,
Revision 1
IP3-2015-02913, Root Cause Evaluation for IP3 Turbine Trip / Reactor Trip Due to 31 Main
Transformer Fault, Revision 2
System Health Report Unit 3 345 Kilovolt, Second Quarter 2014
System Health Report Unit 3 345 Kilovolt, Fourth Quarter 2015
Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion
Procedures
2-PT-R084C, 23 EDG Eight-Hour Load Test, Revision 16
2-PT-R084C, 23 EDG Eight-Hour Load Test, Revision 17
2-AOP-480V-1, Loss of Normal Power to Any 480V Bus
2-AOP-RHR-1, Loss of RHR
EN-LI-102, Corrective Action Program
EN-OP-104, Operability Determination Process
Condition Reports (CR-IP2-)
2016-01256 2016-01259 2016-01260 2016-01266 2016-01355 2016-01430
2016-01500
Drawings
250907-35
Section 4OA5: Other Activities
Procedures
2-AOP-480V-1, Loss of Normal Power to Any 480V Bus
2-AOP-RHR-1, Loss of RHR
2-PT-R084C, 23 EDG Eight-Hour Load Test, Revision 16
2-PT-R084C, 23 EDG Eight-Hour Load Test, Revision 17
EN-LI-102, Corrective Action Program
EN-OP-104, Operability Determination Process
Condition Reports (CR-IP2-)
2016-00264 2016-00266 2016-00564 2016-01256 2016-01259 2016-01260
2016-01266 2016-01355 2016-01430 2016-01500
Drawings
250907-35
A-11
LIST OF ACRONYMS
10 CFR Title 10 of the Code of Federal Regulations
ADAMS Agencywide Document Access and Management System
ABFP auxiliary boiler feedwater pump
ACE apparent cause evaluation
ALARA as low as is reasonably achievable
AOT allowable outage time
ASME American Society of Mechanical Engineers
CAP corrective action program
CR condition report
CRDM control rod drive mechanism
EDG emergency diesel generator
FRV feedwater regulating valve
FSB Fuel Storage Building
FWIV feedwater isolation valve
IMC Inspection Manual Chapter
ISI Inservice Inspection
LCO limiting condition of operation
MBFP main boiler feed pump
MOB maintenance and outage building
MRP materials reliability project
NCV non-cited violation
NDE non-destructive examination
NRC Nuclear Regulatory Commission, U.S.
ORAT outage risk assessment team
OTDT over-temperature delta temperature
PAB primary auxiliary building
PFP pre-fire plan
RFO refueling outage
RO reverse osmosis
RWP radiation work permit
SR surveillance requirement
SRA senior risk analyst
SSC structure, system, and component
TS technical specification
UFSAR Updated Final Safety Analysis Report
URI unresolved item
UT ultrasonic examination
VT visual examination
WHUT waste hold-up tank
WO work order