IR 05000247/2017002

Integrated Inspection Report 05000247/2017002 and 05000286/2017002

ML17220A074
Person / Time
Site:	Indian Point
Issue date:	08/07/2017
From:	Jon Greives Reactor Projects Branch 2
To:	Vitale A Entergy Nuclear Operations
Greives J
References
IR 2017002
Download: ML17220A074 (40)

Text

ust 7, 2017

SUBJECT:

INDIAN POINT NUCLEAR GENERATING - INTEGRATED INSPECTION REPORT 05000247/2017002 AND 05000286/2017002

Dear Mr. Vitale:

On June 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Indian Point Nuclear Generating (Indian Point), Units 2 and 3. On July 13, 2017, the NRC inspectors discussed the results of this inspection with you and other members of your staff.

The results of this inspection are documented in the enclosed report.

The NRC inspectors documented one finding of very low safety significance (Green) in this report. This finding involved a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violation or significance of this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; and the NRC Resident Inspector at Indian Point. In addition, if you disagree with a cross-cutting aspect in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the U. S. Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC, 20555-0001; with copies to the Regional Administrator, Region I, and the NRC Resident Inspector at Indian Point. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA/

Jonathan E. Greives, Acting 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 05000247/2017002 and 05000286/2017002 w/Attachment:

Supplementary Information

REGION I==

Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64 Report Nos. 05000247/2017002 and 05000286/2017002 Licensee: Entergy Nuclear Northeast (Entergy)

Facility: Indian Point Nuclear Generating, Units 2 and 3 Location: 450 Broadway, General Services Building Buchanan, NY 10511-0249 Dates: April 1, 2017, through June 30, 2017 Inspectors: B. Haagensen, Senior Resident Inspector S. Rich, Resident Inspector A. Siwy, Resident Inspector S. Elkhiamy, Reactor Inspector J. Furia, Senior Health Physicist B. Smith, Resident Inspector, Peach Bottom Approved By: Jonathan E. Greives, Acting Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report 05000247/2017002 and 05000286/2017002; 04/01/2017 - 06/30/2017; Indian

Point Nuclear Generating (Indian Point), Units 2 and 3; Refueling and Other Outage Activities.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. The inspectors identified one finding of very low safety significance (Green), which was a non-cited violation (NCV). 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 October 28, 2016. 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 November 1, 2016. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 6.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green NCV of Technical Specification (TS) 5.4.1,

Procedures, for Entergys failure to implement procedure OAP-007, Containment Entry and Egress. Specifically, workers transiting the inner and outer crane wall sections of containment on May 14, 2017, did not maintain flow channeling gate C secured during Mode to ensure availability of the containment sumps to provide suction for the emergency core cooling system (ECCS). Entergy immediately restored gate C to an acceptable configuration, and generated condition report (CR)-IP3-2017-02737 to address this issue.

This performance deficiency was more than minor because it is associated with the configuration control (shutdown equipment lineup) attribute and adversely affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). A detailed risk assessment was conducted and the change in core damage frequency was determined to be 2E-8, therefore, this issue represents a Green finding. The inspectors determined that this finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because Entergy did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance.

Specifically, the corrective actions from the event for the prior year were ineffective at preventing this occurrence. [P.3] (Section 1R20)

REPORT DETAILS

Summary of Plant Status

Unit 2 began the inspection period at 100 percent power. On June 26, 2017, operators manually tripped the reactor in response to lowering steam generator levels caused by flow oscillations on the 22 main boiler feedwater pump. Operators returned Unit 2 to 100 percent power on June 30, 2017.

Unit 3 began the inspection period during refueling outage (RFO) 3RFO17 which lasted 65 days. Upon completion of the outage, the operators restarted Unit 3 on May 17, 2017, and increased power slowly to approximately 100 percent power on May 23, 2017. On June 12, 2017, operators shutdown the reactor to replace the reactor vessel head o-rings. Operators returned Unit 3 to approximately 100 percent power on June 23, 2017, and remained at or near 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of Entergys readiness for the onset of seasonal high temperatures. The inspectors reviewed procedure OAP-048, Seasonal Weather Preparation (Units 2 and 3). The focus areas were the auxiliary boiler feedwater pump (ABFP) buildings and the switchgear rooms. The inspectors reviewed the updated final safety analysis report (UFSAR), TSs, control room logs, and the corrective action program (CAP) to determine what temperatures or other seasonal weather could challenge the systems in these areas and to ensure Entergy had adequately prepared for these challenges. The inspectors reviewed station procedures, including Entergys seasonal weather preparation procedure and applicable operating procedures. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability of the systems during hot weather conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

.1 Partial System Walkdowns

==

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 2 22 emergency diesel generator (EDG) following a planned maintenance window on June 8, 2015 Unit 3 Component cooling water following extensive outage work on May 22, 2017 Residual heat removal while in service for shutdown cooling on June 12, 2017 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, work orders (WOs), and CRs in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether Entergy had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

.2 Full System Walkdown

a. Inspection Scope

On May 13, 2017, the inspectors performed a complete system walkdown of the Unit 3 high head recirculation 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 operability of support systems. The inspectors performed field walkdowns of the system to verify as-built system configuration matched plant documentation and that system components and support equipment remained operable. The inspectors confirmed that systems and components were 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. 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 were 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 Primary auxiliary building, 80-foot elevation (PFP-211), on June 9, 2017 Primary auxiliary building, 15-foot elevation (PFP-204), on June 29, 2017 Control building, 480 volt switchgear room (PFP-251), on June 30, 2017 Unit 3 Containment building (PFP-301, 302, and 303) on April 28, 2017 Safety injection pumps (PFP-305) on May 18, 2017 Containment spray pumps and volume control tank in the primary auxiliary building (PFP-306, 306A, and 306B) on June 30, 2017

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Internal Flooding Review

a. Inspection Scope

The inspectors reviewed the UFSAR, the individual plant examination for external events, design basis documents, and plant procedures to identify flooding susceptibilities for the site. The inspectors review focused on the turbine buildings for Units 2 and 3. It verified the adequacy of floor and water penetration seals, level alarms, drain paths, and removable flood barriers. It assessed the adequacy of operator actions that Entergy had identified as necessary to cope with flooding in this area and also reviewed the CAP to determine if Entergy was identifying and correcting problems associated with both flood mitigation features and site procedures for responding to flooding.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the 22 EDG jacket water and lube oil heat exchanger to determine its readiness and availability to perform its safety functions. The inspectors reviewed the design basis for the component and verified Entergys commitments to NRC Generic Letter 89-13, Service Water System Requirements Affecting Safety-Related Equipment. The inspectors observed the annual cleaning and inspection of the heat exchangers and reviewed the results of previous inspections of the Unit 2 EDG heat exchangers. The inspectors discussed the results of the most recent inspection with engineering staff. The inspectors verified that Entergy initiated appropriate corrective actions for identified deficiencies. The inspectors also verified that the number of tubes plugged within the heat exchanger did not exceed the maximum amount allowed.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

Unit 2

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on April 26, 2017. The scenario started with an earthquake that caused degradation to the main turbine and feedwater pump bearings, damage to the 23 EDG, and created a small reactor coolant system (RCS) leak inside containment. The shift manager declared an ALERT (EAL HA-1.1), activated the emergency response organization, and the crew commenced a rapid shutdown in accordance with 2-AOP-RSD-1, Rapid Shutdown.

The earthquake caused a fuel oil truck to overturn at the main gate and all access to the owner controlled area was suspended. The earthquake resulted in a buildup of debris that clogged the circulating water pump screens and resulted in high differential level alarms at the intake structure. The crew manually tripped the reactor and shut the main steam isolation valves when main turbine bearing temperatures were approaching the turbine trip set point and screen wash level alarms reached the point to trip the circulating water pumps. The operators entered E-0, Reactor Trip or Safety Injection and quickly transitioned to ES-0.1, Reactor Trip Response. A fire subsequently occurred in the 24 circulating water pump and the fire brigade was dispatched. The shift manager dispatched the emergency medical team in response to a report of an injured non-licensed operator. Finally, a large aftershock caused a loss of offsite power; and the RCS leak into containment became much larger (180 gpm). The crew actuated safety injection and stabilized the plant in E-1, Loss of Reactor or Secondary Coolant and reenergized all safety buses. The scenario ended after the safety injection and containment isolation actuation signals were reset. The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures.

The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the TS action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed and reviewed operator performance in the control room. The inspectors interviewed the senior reactor operators, control room supervisor, and shift manager 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.

Control rod exercise conducted on April 13, 2017 Reactor startup for criticality and power ascension on June 26, 2017

b. Findings

No findings were identified.

Unit 3

.3 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed operating crew performance during a Just-In-Time training drill on May 3, 2017, which included zero power physics testing, synching the main generator to the grid, and manual control of the main feedwater regulating valves. The inspectors evaluated operator performance during the simulated events and verified completion of risk significant operator actions. The inspectors assessed the clarity and effectiveness of communications 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.

.4 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed and reviewed reactor startup for initial criticality conducted on May 16 and 17, 2017. 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 crew 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.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the 22 and 32 turbine-driven ABFPs and associated components to assess the effectiveness of maintenance activities on component performance and reliability. The inspectors reviewed system health reports, 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. The inspectors verified that the components were properly scoped into the maintenance rule in accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 50.65 and verified that the (a)(2) performance criteria established by Entergy were reasonable. Additionally, the inspectors ensured that Entergy was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.

The inspectors also reviewed a selection of WOs to verify Entergy was properly applying quality controls specified in their quality assurance program. The inspectors reviewed maintenance WOs that contained quality control hold points to verify Entergy specified quality control hold points in accordance with their procedures and adequately justified deviations from those hold points. Additionally, the inspectors reviewed CRs associated with missed hold points.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

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 Part 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 Emergent risk due to high thunderstorm activity on April 17, 2017 23 ABFP out of service for planned maintenance on May 30, 2017 Unit 3 Unplanned yellow shutdown risk due to thunderstorm activity on April 17, 2017 Risk following core re-load on May 8, 2017 33 reactor coolant pump out of service in Mode 3 while 32 ABFP was inoperable for surveillance testing on May 15, 2017

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

Unit 2 Pressurizer level transmitter LT-461 failed channel check at power (CR-IP2-2017-

===00481)

Broken handle on 21 EDG overspeed trip reset (CR-IP2-2017-01492)

Containment spray pump surveillance test measuring and test equipment not in calibration and associated test methodology issues (CR-IP2-2017-01683/01687)

Socket weld leak upstream of SWN-1074 on the 22 EDG jacket water cooler (CR-IP2-2017-01870)

Unit 3 Core exit thermocouples not within acceptance criteria of post maintenance test (CR-IP3-2017-02991)

Increasing containment unidentified leak rate leading to a Unit 3 planned outage (CR-IP3-2017-03035)

Use of carbon fiber wrap on American Society of Mechanical Engineers Class III component cooling water service lines (CR-HQN-2017-00416)

The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to Entergys evaluations to determine whether the components or systems were operable.

The inspectors confirmed, where appropriate, compliance with bounding limitations associated with the evaluations. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by Entergy. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Temporary Modification

a. Inspection Scope

The inspectors reviewed the temporary modification performed under Engineering Change 68441, Revision 2, to determine whether the modifications affected the safety functions of systems that are important to safety. The modification removed relay 27-3A/X1 in Unit 3, bus 3A, and spliced together the associated wiring in order to allow repairs to the relay without impacting operation of the direct current circuit. The inspectors reviewed 10 CFR Part 50.59 documentation and post-modification testing results and conducted field walkdowns of the modifications to verify that the temporary modifications did not degrade the design bases, licensing bases, and performance capability of the affected systems.

b. Findings

No findings were identified.

.2 Permanent Modification

a. Inspection Scope

The inspectors reviewed the permanent modification to replace service water temperature control valve TCV-1105 for Unit 3 to determine whether the modification affected the safety functions of systems that are important to safety. The inspectors reviewed 10 CFR Part 50.59 documentation and post-modification testing results and conducted field walkdowns of the modifications to verify that the permanent modification did not degrade the design bases, licensing bases, and performance capability of the affected systems.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that 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, 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 Appendix R diesel generator fuel tank fill valve DF-SOV-151 replacement on April 15, 2017 23 EDG load test following jacket water heat exchanger inspection and cleaning on April 25, 2017 Unit 3 3-SWN-LINE-1081 pipe repair on March 28, 2017 Rebuild of 31 EDG starting air valve DA-PCV-14-2 on April 5, 2017 Replacement of reactor protection system relay 15B on April 8, 2017 34 fan cooler unit charcoal filter dousing isolation valve troubleshooting following blown control power fuse on April 28, 2017 Repair of service water temperature control valve TCV-1105 actuator on May 1, 2017 Repair of 32 ABFP governor on May 15, 2017 BFD-FCV-417 31 steam generator feed regulating valve I/P replacement and retest, on May 18, 2017 SI-869A containment spray discharge valve local leak-rate test (containment isolation valve) following repairs on May 19, 2017 31 main transformer following repairs on May 20, 2017

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

.1 Refueling Outage

a. Inspection Scope

The inspectors reviewed the stations work schedule and outage risk plan for the Unit 3 maintenance and RFO for the period from April 1 to May 18, 2017. The outage started on March 12, 2017, and the period from March 12 to March 31, 2017, was documented in Inspection Report 05000247/2017001 and 05000286/2017001 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17131A128).

The inspectors reviewed Entergys development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the reactor startup and plant heatup processes and monitored controls associated with the following outage activities:

Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TSs when taking equipment out of service Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting Switchyard activities and other activities affecting the status and configuration of electrical systems to ensure that TSs were met Decay heat removal operations Spent fuel pool (SFP) cooling system operations Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss Activities that could affect reactivity Maintenance of containment integrity as required by TSs Refueling activities, including fuel handling Fatigue management Tracking of mode change prerequisites Closeout of containment to verify that debris had not been left which could block the ECCS suction strainers Identification and resolution of problems related to RFO activities

b. Findings

Introduction.

The inspectors identified a Green NCV of TS 5.4.1 for Entergys failure to implement procedure OAP-007, Containment Entry and Egress. Specifically, workers transiting the inner and outer crane wall sections of containment on May 14, 2017, did not maintain flow channeling gate C secured during Mode 4 to ensure availability of the containment sumps to provide suction for the ECCS.

Description.

On May 14, 2017, in Mode 4, in preparation for reactor startup, Entergy was performing residual heat removal system check valve testing in containment.

Entergy employees entered the inner crane wall via gate C (which cannot be latched from the inside), instead of via gates D and E. While inspecting the outer section of containment, the inspectors noted that gate C was closed but not secured.

In the event of a postulated loss-of-coolant accident (LOCA), Unit 3 relies on two sumps to provide a suction source for the internal recirculation pumps and residual heat removal pumps, respectively, after the injection phase of the accident. The sumps have cylindrical screens with large surface area and small holes to filter small debris and maintain adequate net positive suction head for the associated pumps. The reactor cavity sump and large intervening barriers prevent large debris generated from the accident, such as insulation, from reaching and blocking the recirculation and containment sump screens. If gate C was not latched shut and a LOCA were to occur, large pieces of debris could bypass the gate and be directly transported into the sump strainers, potentially clogging the strainer elements and blocking core recirculation flow.

Entergys procedure OAP-007, Containment Entry and Egress, precaution and limitation step 2.31.2, states, In Mode 1, 2, 3, or 4, entry inside the crane wall SHALL use the double gate entry point via gates D and E. One gate SHALL remain shut and secured at all times to maintain flow channeling and sump operability. Securing gates requires using slide latch which can be performed from inside or outside the gate. This procedure also states that prior to exiting Mode 5, verify that crane wall gate C is secured shut and the perforated cover is installed. Additionally, a sign posted on gate C states, GATE C: THIS GATE CANNOT BE USED IF THE PLANT IS IN MODE 1, 2, 3, OR 4 PER TECHNICAL SPECIFICATIONS 3.5.2 AND 3.5.3. USE GATE D AND GATE E NEAR THE ACCUMULATORS IN ACCORDANCE WITH OAP-007. The inspectors noted that the gate could be pushed open with little effort because the latch had not been set. Upon questioning by the inspectors, Entergy immediately restored gate C to an acceptable configuration. Entergy generated CR-IP3-2017-02737 to address this issue.

A similar issue was identified by Entergy on March 4, 2013, for Unit 3 (Licensee Event Report (LER) 05000286/2013-002-00). Entergy determined the apparent causes to be an inadequate radiological protection pre-job brief and inadequate procedures. They also determined the contributing causes to be lack of signage on the gate access points and the existence of knowledge gaps in radiological protection work crew members.

Another similar issue was identified by the NRC on June 11, 2016, for Unit 2 (LER 05000247/2016-007-00). Entergy determined the apparent cause to be latent organizational weakness associated with the use of OAP-007. They also determined the contributing causes to be crew unfamiliarity with detailed aspects of the task and lack of a questioning attitude during the pre-job brief. Details of these prior NCVs can be found in Inspection Reports 05000247/2013-005 and 05000286/2013-005 (ADAMS Accession No. ML14045A254) and 05000247/2016-002 and 05000286/2016-002 (ADAMS Accession No. ML17089A245), respectively.

Analysis.

The inspectors determined that Entergys failure to maintain gate C closed during Mode 4 in accordance with OAP-007 was a performance deficiency. The performance deficiency was more than minor because it is associated with the configuration control (shutdown equipment lineup) attribute and adversely affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors evaluated the finding in accordance with IMC 0609, Appendix G, Attachment 1, Exhibit 3, and determined that a detailed risk evaluation was necessary because the finding represented a loss of system safety function. This assessment was conducted conservatively assuming complete failure of the recirculation and containment sumps due to the performance deficiency. Given that Unit 3 was in Mode 4, in plant operating state 1, with a late time window, the at-power simplified plant analysis risk model for large-break LOCAs was determined to best model the degraded condition and plant response. An exposure time of one day was assumed.

No credit was assumed for the decrease in energy that would be anticipated in a release during a LOCA in Mode 4, nor the corresponding reduction in debris generation. This was also considered conservative. Utilizing Systems Analysis Program for Hands-On Integrated Reliability Evaluation, Version 8.1.5, with Indian Point Unit 3 Standardized Plant Analysis Risk Model, Version 8.50, for the assumed conditions, the change in core damage frequency was determined to be 2E-8. Therefore this issue was determined to be of very low safety significance (Green).

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because Entergy did not take effective corrective actions to address issues in a timely manner commensurate with their safety significance.

Specifically, the corrective actions from the event the prior year were ineffective at preventing this occurrence [P.3].

Enforcement.

Unit 3 TS 5.4.1.a requires that the procedures listed in Attachment A to Regulatory Guide 1.33, Quality Assurance Program Requirements, Revision 2, be established and implemented. Appendix A states that procedures for access to containment and instructions for changing modes of operation of the ECCS should be prepared, as appropriate. Entergys procedure OAP-007, Containment Entry and Egress, Step 2.31.2, states, In Mode 1, 2, 3, or 4, entry inside the crane wall SHALL use the double gate entry point via gates D and E. One gate SHALL remain shut and secured at all times to maintain flow channeling and sump operability. Securing gates requires using slide latch which can be performed from inside or outside the gate.

Contrary to the above, on May 14, 2017, Entergy used a prohibited gate (gate C) for access to the inner crane wall and did not properly maintain the gate secured at all times during Mode 4. Entergy entered this issue into the CAP as CR-IP3-2017-02737.

Because this violation was of very low safety significance (Green) and Entergy entered this performance deficiency into the CAP, the NRC is treating this as an NCV in accordance with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000286/2017002-01, Failure to Maintain Flow Channeling Gate Closed in Accordance with the Containment Procedure)

.2 Forced Outage

a. Inspection Scope

The inspectors conducted an inspection of the Unit 3 planned outage to replace the O-rings on the reactor vessel flange from June 12 to 22, 2017 (3PO17A). Prior to the outage, the inspectors reviewed the outage work schedule and outage risk assessment to verify that risk, industry operating experience, previous site-specific problems, and defense-in-depth were considered. The inspectors observed portions of the shutdown and startup to verify the unit was operating in accordance with established procedures and the TSs and that reactivity changes were made in a controlled manner in accordance with established reactivity plans. The inspectors reviewed logs of the RCS cooldown and heat-up to verify temperature and pressure limits were not exceeded.

During the outage, the inspectors reviewed:

Scheduling of maintenance activities, to verify there were no unintended impacts to the outage risk plan Tagging and clearance activities, to verify equipment was appropriately configured to safely support the associated work or testing The installation and configuration of RCS pressure, level, and temperature instruments to verify they would indicate accurately during changing plant conditions The configuration and availability of electrical systems, to verify Entergy complied with the TSs The operation of the residual heat removal system and the steam generators while they were being used for decay heat removal, to verify core cooling was maintained Vessel drain-down and vessel fill activities, to verify RCS inventory was monitored and maintained within the expected ranges Activities that affected containment, to verify Entergy was able to restore containment integrity in accordance with their risk plan

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant structure, system, and components 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 3 3-PT-R025D1, Leakage Test for SI-869A, on March 17, 2017 (containment isolation valve)3-PT-R025D3, Leakage Test for Reactor Coolant Pump Component Cooling Water Containment Isolation Valves, on March 28, 2017 (containment isolation valve)3-PT-R198, 32 ABFP Turbine Overspeed Test, on April 6 and April 15, 2017 3-PT-R003D, Safety Injection Test, on May 4, 2017 3-PT-R4, Full Length Rod Drop Time Testing, on May 16, 2017 3-PT-M079A, 31 EDG Quarterly Surveillance Test Following Overhaul, on May 25, 2017

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine Entergy emergency drill on June 28, 2017, to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the technical support center and emergency operations facility to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the facility critiques 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.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

The inspectors reviewed Entergys performance in assessing and controlling radiological hazards in the workplace. The inspectors used the requirements contained in 10 CFR Part 20, TSs, Regulatory Guide 8.38, and the procedures required by TSs as criteria for determining compliance.

Inspection Planning

The inspectors reviewed the performance indicators for the occupational exposure cornerstone, radiation protection program audits, and reports of operational occurrences in occupational radiation safety since the last inspection.

Radiological Hazard Assessment ===

The inspectors conducted independent radiation measurements during walkdowns of the facility and reviewed the radiological survey program, air sampling and analysis, continuous air monitor use, recent plant radiation surveys for radiological work activities, and any changes to plant operations since the last inspection to verify survey adequacy of any new radiological hazards for onsite workers or members of the public.

Instructions to Workers (1 sample)

The inspectors reviewed high radiation area work permit controls and use and observed containers of radioactive materials and assessed whether the containers were labeled and controlled in accordance with requirements.

The inspectors reviewed several occurrences where a workers electronic personal dosimeter alarmed. The inspectors reviewed Entergys evaluation of the incidents, documentation in the CAP and whether compensatory dose evaluations were conducted when appropriate. The inspectors verified that follow-up investigations of actual radiological conditions for unexpected radiological hazards were performed.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

The inspectors assessed Entergys performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements contained in 10 CFR Part 20, Regulatory Guides 8.8 and 8.10, TSs, and procedures required by TSs as criteria for determining compliance.

Inspection Planning

The inspectors conducted a review of Indian Points collective dose history and trends, ongoing and planned radiological work activities, previous post-outage ALARA reviews, radiological source term history and trends, and ALARA dose estimating and tracking procedures.

Implementation of ALARA and Radiological Work Controls (1 sample)

The inspectors reviewed the current plant radiological source term and historical trend, plans for plant source term reduction, and contingency plans for changes in the source term as the result of changes in plant fuel performance or changes in plant primary chemistry.

The inspectors observed radiological work activities and evaluated the use of shielding and other engineering work controls based on the radiological controls and ALARA plans for those activities.

Problem Identification and Resolution (1 sample)

The inspectors evaluated whether problems associated with ALARA planning and controls were identified at an appropriate threshold and properly addressed in the CAP.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

Initiating Events Performance Indicators

a. Inspection Scope

The inspectors reviewed Entergys submittals for the following Initiating Events cornerstone performance indicators for the period April 1, 2016, through March 31, 2017:

Unit 2 Unplanned Scrams Per 7000 Critical Hours (IE01)

Unplanned Power Changes Per 7000 Critical Hours (IE03)

Unplanned Scrams with Complications (IE04)

Unit 3 Unplanned Scrams Per 7000 Critical Hours (IE01)

Unplanned Power Changes Per 7000 Critical Hours (IE03)

Unplanned Scrams with Complications (IE04)

To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7.

The inspectors reviewed Entergys operator narrative logs, CRs, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals. There were no unplanned power changes or scrams with complications during the review period.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.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 screening meetings. The inspectors also confirmed, on a sampling basis, that, as applicable, for identified defects and non-conformances, Entergy performed an evaluation in accordance with 10 CFR Part 21.

b. Findings

No findings were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 71152, Problem Identification and Resolution, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by Entergy outside of the CAP, such as trend reports, performance indicators, major equipment problem lists, system health reports, maintenance rule assessments, and maintenance or CAP backlogs. The inspectors also reviewed Entergys CAP database for the first and second quarters of 2017 to assess CRs for proper operability classification and implementation of compensatory measures, as well as individual issues identified during the NRCs daily CR review (Section 4OA2.1).

b. Findings and Observations

No findings were identified.

The inspectors evaluated CRs that had been assigned as degraded conditions with no compensatory measures assigned (DNC) and degraded conditions with compensatory measures assigned (COMP-MEAS). The inspectors concluded that there appeared to be a trend in the reduction in the assignment of compensatory measures to restore operability. Three specific examples of degraded conditions that met the criteria for compensatory measures are discussed below.

Removal of compensatory actions for Boraflex degradation in the Unit 2 SFP on January 15, 2015. CR-IP2-2014-00776 (dated February 14, 2014) reported that the Unit 2 SFP Boraflex panels had degraded at a more rapid rate than had been previously evaluated in the criticality analysis of record. SFP operability was restored by assigning several operator actions as compensatory measures. This included restrictions on SFP storage, increased soluble boron concentration in the SFP, and additional SFP monitoring actions. On January 15, 2015, the use of compensatory measures was discontinued without appropriate justification. The operability assignment was changed from OPERABLE - COMP-MEAS to OPERABLE - DNC. The previously required compensatory measures are now maintained as administrative controls in 0-NF-203, Internal Transfer of Fuel Assemblies and Inserts.

Pressurizer level channel transmitter LT-461 is indicating high but is not considered degraded. Pressurizer level channel LT-461 is currently indicating higher than actual level (CR-IP2-2017-00477). Entergy biased the control room panel indicator and the I/I converter so that indicated and actual pressurizer level are better aligned at normal operating pressure to allow the level channel to pass its channel check surveillance. This bias had no effect on the safety-related signal from LT-461, which remains high. The safety-related function of LT-461 is to provide a trip signal on high level, but two signals are required for an actual trip. Operators are required to recognize that the signal from LT-461 is indicating higher than actual pressurizer level and take actions in procedures based on this knowledge. This process would have been analyzed and controlled under the 10 CFR Part 50.59 modification process if the operator actions were considered to be compensatory actions for a degraded condition.

A through-wall leak on the 31 service water pump discharge line had no compensatory measures. On April 27, 2016, Entergy reported a through-wall leak on the 31 service water pump discharge line (CR-IP3-2016-01113). Entergy verified the structural integrity of the line and installed a non-safety related patch to minimize service water leakage into the Zurn Pit. On January 13, 2017, the non-safety related patch had to be removed to facilitate the required 90-day ultrasonic testing inspection to verify structural integrity. The leak rate increased to an estimated 30 to 50 gpm when the non-safety related patch was removed. The increased leak rate required Entergy to rely on operator manual actions to remove the water to prevent internal flooding. However, neither these actions, nor the patch itself, were classified as compensatory measures as part of the operability determination. The through-wall leak was repaired during 3R19.

Each example above relies on operator manual actions to restore a degraded or nonconforming condition. These are defined as compensatory measures according to Entergys procedure, EN-OP-104, Operability Determination Process, yet Entergy did not classify them as such in their CAP. The lack of formal control and rigorous assessment of the changes reduces the level of effectiveness and confidence that these operator manual actions wont adversely affect other systems. Additionally, the aggregate impact of these compensatory measures is potentially not considered since they are not formally documented, tracked, and analyzed with each previous/subsequent compensatory measure.

Many of the actions relied upon to maintain operability had been either pre-staged or informally implemented as administrative controls, although the controls were not reviewed under 10 CFR Part 50.59. However, none of these actions or modifications would likely have required NRC approval, so this performance deficiency is minor in accordance with the Enforcement Policy, Section 6.1, Violation Examples - Reactor Operations. Entergy documented each item in their CAP, as referenced above. This failure to comply with 10 CFR Part 50.59 constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. Inspectors determined that maintaining the actions as described above for the first two examples was sufficient to ensure there was no immediate safety concern while final corrective actions to restore compliance were being considered. For the third example, the compensatory measures are no longer required because the degraded condition was repaired The inspectors analyzed the corrective action system to validate their perception of the recent trend. From 2011 until 2015, the station averaged 6.2 CRs per year that had compensatory measures. From mid-2016 to mid-2017, the station had only two CRs that were assigned with compensatory measures. During the first six months of 2017, there were zero CRs that relied on compensatory actions. The standard deviation of the distribution of COMP-MEAS CRs from 2011 to 2015 was 2.6 per year. The variation from 6.2 to 2 was statistically significant (more than one standard deviation). This statistical analysis supported the inspectors observation that there appeared to be a trend in the reduction in the assignment of compensatory measures over the last six months.

.3 Annual Sample: Control Rod G-3 Misalignment

a. Inspection Scope

The inspectors performed an in-depth review of Entergys evaluation, extent of condition, and associated corrective actions associated with shutdown bank B rod G-3 misalignment documented in CR-IP2-2014-04905 and CR-IP2-2016-06171. The inspectors assessed Entergys problem identification threshold, problem analysis, extent of condition reviews, compensatory actions, and the prioritization and timeliness of Entergy's 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 Entergy's CAP and 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action.

The inspectors reviewed a sample of the traces from the rod misalignments documented in WOs, rod testing completed during startup activities, rod exercise surveillances, core performance data, operator response, and TS compliance. The inspectors conducted interviews with Entergy technical engineering staff and operations staff, reviewed system performance and health reports, cause evaluations, operability determinations, corrective actions, WOs, core performance, and flux map reports. The inspectors observed and reviewed a control rod exercise conducted on April 13, 2017. 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 and Observations

No findings were identified.

The control rod drive system moves both the shutdown and control banks based on demands from the system. They control reactor temperature and power distribution within the reactor core. Each control assembly is connected to a drive shaft with many grooves along their length for the working components of the control rod drive mechanism (CRDM) to engage and carry their weight. The CRDM keeps the control rods suspended and moves them based on system commands. Each drive shaft has three coils: stationary, movable, and lift. These coils generate magnetic flux to operate their components based on their function for rod movement. These rods are tested on a periodic basis to ensure they meet their design and safety function and move as expected. Entergy has had a history dating back to September 2014 under CR-IP2-2014-04905, associated with shutdown bank B rod G-3 ratcheting into the core approximately 23 steps during 2-PT-Q89, Quarterly TS Surveillances, resulting in rod misalignment. The inspectors verified that Entergy took appropriate immediate corrective actions and realigned shutdown bank B per procedure and evaluated via apparent cause evaluation.

The initial apparent cause evaluation determined the cause to be crud related and resulted in a TS amendment to prevent control rod exercise testing on G-3 until corrective actions could be taken in 2RFO22. The inspectors verified that actions taken in 2RFO22 were, in general, appropriately identified and dispositioned with an adequate technical basis including time domain reflectometry and electrical testing of cables, visual inspections of cables, drive shaft visual inspection and replacement, and video inspections of guide tubes. The inspectors verified that all rods had operated properly during shutdown into 2RFO22. Inspectors noted, however, that actions taken during 2RFO22 have not prevented the condition from happening again. There was no evidence of crud during inspections or in any chemistry analysis. Furthermore, crud induced type behavior is normally seen in the first few steps of rod movement, contrary to a 23-step movement seen in 2014.

Entergy has experienced two repeat conditions since taking corrective action in 2RFO22. During startup activities and low power physics testing, Entergy experienced erratic indication on G-3 during dynamic rod worth test measurement. Additionally, on October 13, 2016, during 2PT-Q89, shutdown bank B rod G-3 once again ratcheted into the core. Entergy once again took appropriate immediate corrective actions and realigned shutdown bank B per procedure and evaluated via apparent cause evaluation.

The repeat occurrence of ratcheting also further disproves crud buildup theory, based on a reactor disassembly/reassembly during most recent outage where crud was most likely to have been dislodged.

The inspectors noted that although procedures were followed correctly, there is no procedural guidance currently written to address a misaligned rod for greater than a one-hour timeframe. This is not an immediate safety concern however could help alleviate operator burden in this type of scenario.

Entergy performed another apparent cause evaluation under CR-IP2-2016-06171 and revised causes and corrective actions to include revision of rod exercise test procedure, 2-PT-Q89, to exercise G-3 independently and in one step intervals, evaluate stationary/movable gripper traces during test performance, and longer term corrective actions to replace CRDM assembly in 2R23. The rod exercise test has been successfully performed twice since the procedure revision.

The inspectors determined that, in general, Entergys overall response to the rod control system misalignment was commensurate with the safety significance and included appropriate compensatory actions. The inspectors concluded that although the condition was not corrected following initial occurrence in 2014 and subsequent 2RFO22 actions, Entergy took reasonable measures to determine causes that were not reasonably foreseeable or predictable. The inspectors concluded that completed and planned actions were reasonable to correct the ratcheting and misalignment of shutdown bank B rod G-3.

4OA3 Follow Up of Events and Notices of Enforcement Discretion

.1 Plant Event

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 manual reactor trip on June 26, 2017, when flow oscillations on the 22 main boiler feed pump caused steam generator water level to approach the low limit

b. Findings

No findings were identified.

.2 (Closed) LER 05000247/2016-001-00: TS Prohibited Condition Caused by a Main

Steam Safety Valve (MSSV) Outside Its Required As-Found Lift Setpoint Range

a. Inspection Scope

On March 4, 2016, Entergy identified the failure of Unit 2 MSSV MS-45B during surveillance testing and reported this condition under 10 CFR Part 50.73 in LER 05000247/2016-001-00, TS Prohibited Condition Caused by an MSSV Outside Its Required As-Found Lift Setpoint Range. The inspectors reviewed this LER and determined that this test failure was a violation of TS 3.7.1. The inspectors did not identify any new issues during the review of the LER. This LER is closed.

b. Findings and Observations

The MSSVs at Indian Point are safety-related, ASME Section XI, Class 2, seismically qualified components. There are a total of 20 MSSVs at Unit 2 of the same design (which are of the same design as the MSSVs in Unit 3). Five safety valves are installed on each of the four main steam lines upstream of the main steam isolation valves from the steam generators. MSSV surveillance testing is performed in accordance with Entergys procedure 2-PT-R006, MSSV Setpoint Determination.

On March 4, 2016, MSSV MS-45B was tested just prior to entering 2RFO22 while still in Mode 1. On its initial attempt, MS-45B lifted at 1125 psig or 5.7 percent above its required setpoint of 1065 psig. TS SR 3.7.1.1 requires the MSSVs to lift within three percent of their lift setpoint during this test. CR-IP2-2016-01204 was generated to document the failure. Two additional subsequent tests produced satisfactory lift results. Further inspection revealed that the MS-45B valve operating spindle had areas of wear along its length and circumference in the form of small steps which was indicative of side loading and excessive vibration wear while at power. Entergy immediately repaired MS-4B by replacing the worn valve spindle, determined that this wear pattern was firm evidence that the valve had failed during Mode 1 operations, and reported the failure under 10 CFR Part 50.73 by submitting LER 05000247/

2016-001-00.

Prior inspections from 2010 had indicated that MSSVs at both Units 2 and 3 were susceptible to this failure mechanism. In 2012, both the valve vendor (Crosby) and an independent assessor (Lucius Pitkin, Inc.) recommended to Entergy that they install sacrificial bronze bushings between the spindle and the lifting spring to prevent galling of the valve stem. In January 2013, Unit 2 established a repair plan under EC-39376 to install bronze wearing sleeves in all the MSSVs to prevent this failure mechanism from occurring. MS-45B had been scheduled to have the bronze sleeve modification installed in the RFO in March 2016. The Inspectors determined that this repair schedule was reasonable and was in accordance with Entergy CAP procedures.

This violation constitutes an additional example of a previous licensee-identified violation of TS 3.7.1 that was previously documented in Section 4OA7 of Inspection Report 05000247/2015-002 and 05000286/2015-002 (ADAMS Accession No. ML15222A186)and is not being documented in this report as allowed by Part 1, Section 1.3.6 of the NRCs Enforcement Manual. Corrective actions for this additional example have already been implemented in conjunction with corrective actions for the previously documented violation and no additional corrective actions are required.

.3 (Closed) LER 05000247/2016-002-00 and 05000247/2016-002-01: Automatic Actuation

of EDGs Due to 480 VAC Bus Undervoltage Condition and Loss of Residual Heat Removal While in Cold Shutdown 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 480 volt safety bus. The 6A bus remained de-energized for approximately one hour until the crew restored the 6A bus via off-site power. The 23 EDG was declared inoperable. All four 480 volt safety buses were restored to off-site power. Entergy replaced the overcurrent relays and retested the 23 EDG satisfactorily on March 8, 2016. However, bench testing of the overcurrent relays demonstrated that they were accurately calibrated.

Subsequently, on March 10, 2016, during performance of PT-R14, Automatic Safety Injection System Electrical Load and Blackout Test, the 23 EDG exhibited anomalous behavior during the train B load sequencing. During this test, the voltage on safety bus 6A dropped to approximately 200V when the 23 auxiliary feedwater pump was sequenced onto the bus (CR-IP2-2016-01430) and the sequencer failed to complete the first two sequences. The 23 EDG was again declared inoperable and the period of inoperability was backdated to March 7, 2016, when it originally tripped. Further troubleshooting and additional failure modes analysis by Entergy initially determined that the cause of both events may have been a degraded resistor (R25) on the 23 EDG automatic voltage regulator (AVR) card.

The 23 EDG AVR card was replaced, and the 23 EDG was again tested satisfactorily.

The voltage anomaly issues exhibited during the March 10, 2016, test were documented in CR-IP2-2016-01430 which was closed in CR-IP2-2016-01260 to be included in the causal assessment associated with the tripping of 23 EDG breaker on March 7, 2016.

Entergy assigned a vendor to perform laboratory bench testing and failure analysis of the 23 EDG AVR card. The NRC opened an unresolved item pending the outcome of laboratory bench testing for the AVR card. The vendor report attributed the cause of the March 10, 2016, loss of voltage control to a degraded solder joint on the AVR card.

However, the vendor report explicitly did not attribute the event on March 7, 2016, to the same cause. Entergy assigned a corrective action in CR-IP2-2016-01260 to review the cause of the 23 EDG overcurrent trip on March 7, 2016, in light of the vendor report.

On February 28, 2017, Entergy concluded that the degraded AVR card solder joint was the probable cause for both loss of power events on March 7 and March 10, 2016.

Entergy amended the LER to add this conclusion. The inspectors reviewed both the original version of the LER as well as the revision to the LER.

This event had no significant effect on the public health and safety as the electrical buses were promptly repowered from off-site power and vital loads restored. The inspector observed Entergys actions during the event and later reviewed the corrective actions listed in CR-IP2-2016-01260. The inspectors closed out the above referenced unresolved item with Green NCV 05000247/2016003-02, Missed Inspections on AVR Cards Results in EDG Failure to Run at the time of the event. The inspectors did not identify any new issues during the review of the LER. This LER is closed.

4OA6 Meetings, Including Exit

On July 13, 2017, the inspectors presented the inspection results to Mr. Anthony Vitale, 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

KEY POINTS OF CONTACT

Entergy Personnel

Senior Managers

A. Vitale, Site Vice President

J. Kirkpatrick, General Manager of Plant Operations

G. Bouderau, Senior Manager, Site Projects and Maintenance Services

R. Burroni, Director of Special Projects

D. Dewy, Senior Manager, Production

J. Ferrick, Director of Engineering

M. Kempski, Senior Manager, Maintenance

M. Lewis, Senior Manager, Operations

B. McCarthy, Director, Regulatory Assurance and Performance Improvement Director

Other Personnel

R. Alexander, Shift Manager, Unit 2

V. Andreozzi, Manager, Systems and Components

N. Azevedo, Supervisor, Engineering

S. Bianco, Fire Marshall

J. Bretti, Design Engineer

T. Chan, Supervisor, Engineering

T. Cramer, Manager, Assistant Operations Support

P. Daigle, Supervisor, Engineering

G. Delfini, Supervisor, Reactor Engineering

J. Dignam, Supervisor, Control Room

R. Dolansky, Manager, ISI Program

J. Dorsey, Senior Nuclear Health Physics Technician

L. Glander, Manager, Emergency Preparedness

T. Gnadt, Supervisor, Unit 3 Field Support

E. Goetchius, Senior Operations Instructor

L. Hedges, Shift Manager, Unit 2

S. Irwin, Supervisor, Electrical

C. James, Supervisor, Unit 2 Control Room

M. Johnson, Manager, Unit 3 Assistant Operations

F. Kich, Manager, Performance Improvement

J. Lafferty, Coordinator, Equipment Reliability

M. Lewis, Senior Manager, Operations

N. Lizzo, Manager, Training

B. Lucas, Unit 2 Control Room Operator

N. Markovich, Senior Operations Instructor

N. Martinez, Supervisor, Unit 2 Shift Technical Advisor/Control Room

W. Martino, Unit 2 Control Room Operator

K. McKenna, Manager, Unit 2 Assistant Operations

R. Montross, Shift Manager, Unit 2

R. Motko, Reactor Engineer

T. Oggeri, Supervisor, Unit 3 Control Room

E. Primrose, Shift Manager, Unit 2

S. Stevens, Manager, Radiation Protection

M. Tesoriero, Manager, System Engineering

M. Troy, Manager, Nuclear Oversight

R. Walpole, Manager, Regulatory Assurance

W. Wittic, Supervisor, Engineering

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000286/2017002-01 NCV Failure to Maintain Flow Channeling Gate Closed in Accordance with the Containment Procedure (Section 1R20)

Closed

05000247/2016-001-00 LER TS Prohibited Condition Caused by an MSSV Outside Its Required As-Found Lift Setpoint Range (Section 4OA3)

05000247/2016-002-00 LER Automatic Actuation of EDGs Due to 480 VAC Bus and

05000247/2016-002-01 Undervoltage Condition and Loss of Residual Heat Removal While in Cold Shutdown (Section 4OA3)