ML16133A448

Integrated Inspection Report 05000247/2016001 and 05000286/2016001, 01/01/2016 - 03/31/2016

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

ML16133A448

SUNSI Review

Non-Sensitive

Sensitive

Publicly Available

Non-Publicly Available

OFFICE

RI/DRP

RI/DRP

RI/DRP

NAME

BHaagensen/GTD for

per discussion w/BH

CLally/CL

GDentel/GTD

DATE

05/12/16

05/12/16

05/12/16

1

Enclosure

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

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

5

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

8

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

11

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,

18

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)

Temporary Modification

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)

28

.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

Attachment

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

D. Caffery, BOP Operator, RO

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

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

WO 52685544

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

WO 52429303

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

DRN-14-01173

DRN-14-01174

DRN-14-01175

DRN-14-01221

DRN-14-01222

DRN-14-01223

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

TST-PT-R93

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

LO-IP3LO-2016-00085

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

AFW

auxiliary feedwater

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

ECT

eddy current testing

EDG

emergency diesel generator

FRV

feedwater regulating valve

FSB

Fuel Storage Building

FWIV

feedwater isolation valve

HRA

high radiation area

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

RCS

reactor coolant system

RFO

refueling outage

RHR

residual heat removal

RO

reverse osmosis

RPS

reactor protection system

RPV

reactor pressure vessel

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