Text

NRC Integrated Inspection Report Nos. 05000325/2017002 and 05000324/2017002 and Exercise of Enforcement Discretion
	ML17212A137
Person / Time
Site:	Brunswick
Issue date:	07/31/2017
From:	Steven Rose; NRC/RGN-II/DRP/RPB4
To:	William Gideon; Duke Energy Progress
References
	EA-17-123 IR 2017002
	Download: ML17212A137 (27)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION uly 31, 2017

SUBJECT:

BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2017002 AND 05000324/2017002 AND EXERCISE OF ENFORCEMENT DISCRETION

Dear Mr. Gideon:

On June 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Brunswick Steam Electric Plant, Units 1 and 2. On July 12, 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.

A violation of Technical Specification 3.6.4.1, Secondary Containment, was identified. Because the violation was identified during the discretion period described in Enforcement Guidance Memorandum 11-003, Revision 3, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to the license amendment request which was submitted on June 29, 2017.

Further, inspectors documented a licensee-identified violation which was determined to be of very low safety significance in this report. The NRC is treating this violation as non-cited violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violation or the significance of the violation, 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 II; the Director, Office of Enforcement, and the NRC Resident Inspector at the Brunswick Steam Electric Plant. 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 at the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA/

Steven D. Rose, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62

Enclosure:

IR 05000325, 324/2017002 w/Attachment: Supplementary Information

REGION II==

Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62 Report No.: 05000325/2017002, 05000324/2017002 Licensee: Duke Energy Progress, Inc.

Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: Southport, NC Dates: April 1, 2017 through June 30, 2017 Inspectors: M. Catts, Senior Resident Inspector M. Schwieg, Resident Inspector D. Jackson, RII Project Engineer Approved by: Steven D. Rose, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY

Integrated Inspection Report 05000325/2017002, 05000324/2017002; April 1, 2017, through

June 30, 2017; Brunswick Steam Electric Plant, Units 1 and 2.

The report covered a 3-month period of inspection by resident inspectors and regional inspectors. There were no NRC-identified or self-revealing violations documented in this report.

The significance of inspection findings are 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, (SDP) dated April 29, 2015. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated November 1, 2016. The NRCs program for overseeing the safe operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 6.

One violation of very low safety significance that was identified by the licensee has been reviewed by the NRC. Corrective action taken or planned by the licensee has been entered into the licensees corrective action program (CAP). This violation and corrective action tracking number is listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power (RTP). On April 25, 2017, the unit was shut down for a forced outage to repair the 1B recirculation pump seal. On April 28, 2017, the unit was restarted and power was returned to 100 percent on May 1, 2017. On May 2, 2017, power was reduced to 66 percent for a control rod improvement and power was returned to 100 percent on May 4, 2017. On May 6, 2017, power was reduced to 80 percent for a control rod improvement and power was returned to 100 percent on May 8, 2017. On May 31, 2017, power was reduced to 98 percent due to a loss of the 1B variable frequency device controller for the 1B recirculation pump. Power was returned to 100 percent after restoration of the 1B variable frequency device controller on May 31, 2017.

On June 9, 2017, power was reduced to 70 percent for a control rod improvement and power was returned to 100 percent on June 11, 2017. The unit remained at or near 100 percent RTP for the remainder of the inspection period.

Unit 2 began the inspection period shutdown for refueling outage B223R1. On April 14, 2017, the unit was restarted and power was returned to 100 percent on April 22, 2017. On May 22, 2017, power was reduced to 70 percent to repair a steam leak on 2-MD-V16 and power was returned to 100 percent on May 22, 2017. On June 3, 2017, power was reduced to 70 percent for a control rod sequence exchange and valve testing. Power was returned to 100 percent on June 3, 2017. On June 5, 2017, power was reduced to 70 percent for a control rod sequence exchange. Power was returned to 100 percent on June 5, 2017. The unit remained at or near 100 percent RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

a. Inspection Scope

Seasonal Extreme Weather Conditions The inspectors conducted a detailed review of the stations adverse weather procedures written for extreme high temperatures. The inspectors verified that weather-related equipment deficiencies identified during the previous year had been placed into the work control process and/or corrected before the onset of seasonal extremes. The inspectors evaluated the licensees implementation of adverse weather preparation procedures and compensatory measures before the onset of seasonal extreme weather conditions.

Documents reviewed are listed in the Attachment.

The inspectors evaluated the following risk-significant systems:

service water system

transformer yard

b. Findings

No findings were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial Walkdown (71111.04 - 4 samples)

The inspectors verified that critical portions of the selected systems were correctly aligned by performing partial walkdowns. The inspectors selected systems for assessment because they were a redundant or backup system or train, were important for mitigating risk for the current plant conditions, had been recently realigned, or were a single-train system. The inspectors determined the correct system lineup by reviewing plant procedures and drawings. Documents reviewed are listed in the Attachment.

The inspectors selected the following systems or trains to inspect:

Unit 1, core spray (CS) train B

Unit 2, reactor core isolation cooling (RCIC)

Unit 1, nuclear service water (NSW)

Unit 2, CS train B

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

Quarterly Inspection (71111.05Q - 5 samples)

The inspectors evaluated the adequacy of selected pre-fire plans by comparing the pre-fire plans to the defined hazards and defense-in-depth features specified in the fire protection program. In evaluating the pre-fire plans, the inspectors assessed the following items:

control of transient combustibles and ignition sources

fire detection systems

water-based fire suppression systems

gaseous fire suppression systems

manual firefighting equipment and capability

passive fire protection features

compensatory measures and fire watches

issues related to fire protection contained in the licensees CAP The inspectors toured the following fire areas to assess material condition and operational status of fire protection equipment. Documents reviewed are listed in the

.

2PFP-TB2-01A, Unit 2 Turbine Building Breezeway, North 20 foot elevation

2PFP-RB2-07, Unit 2 Drywell, 20 foot elevation

1PFP-DG-05/04, Unit 1 Diesel Generator Cells 1-2, 23 foot elevation

2PFP-TB2-01M, Unit 2 Turbine Building Laydown Area, 70 foot elevation

2PFP-RB2-01T, Unit 2 Reactor Building Torus, 0 foot elevation

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Main article: IP 71111.06

a. Inspection Scope

Underground Cables The inspectors reviewed related flood analysis documents and inspected the areas listed below containing cables whose failure could disable risk-significant equipment. The inspectors directly observed the condition of cables and cable support structures and, as applicable, verified that dewatering devices and drainage systems were functioning properly. In addition, the inspectors verified the licensee was identifying and properly addressing issues using the CAP. Documents reviewed are listed in the Attachment.

Unit 2, manhole 2-MH-6NW, 2-MH-6SW

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

Main article: IP 71111.11

a. Inspection Scope

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

On June 1, 2017 the inspectors observed an evaluated simulator scenario, involving a NSW header leak and RCIC steam line break with failure to isolate, administered to an operating crew as part of the annual requalification operating test required by 10 CFR 55.59, Requalification.

The inspectors assessed the following:

licensed operator performance

the ability of the licensee to administer the scenario and evaluate the operators

the quality of the post-scenario critique

simulator performance Documents reviewed are listed in the Attachment.

.2 Resident Inspector Quarterly Review of Licensed Operator Performance in the Actual

Plant/Main Control Room The inspectors observed licensed operator performance in the main control room on April 14, 2017, during plant startup from Unit 2 refueling outage B223R1.

The inspectors assessed the following:

use of plant procedures

control board manipulations

communications between crew members

use and interpretation of instruments, indications, and alarms

use of human error prevention techniques

documentation of activities

management and supervision Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

a. Inspection Scope

The inspectors assessed the licensees treatment of the issues listed below to verify the licensee appropriately addressed equipment problems within the scope of the maintenance rule (10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants). The inspectors reviewed procedures and records to evaluate the licensees identification, assessment, and characterization of the problems as well as their corrective actions for returning the equipment to a satisfactory condition. Documents reviewed are listed in the Attachment.

WO 20132630, Unit 1 high pressure coolant injection (HPCI) auxiliary oil pump motor overload relay replacement

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

a. Inspection Scope

The inspectors reviewed the maintenance activities listed below to verify that the licensee assessed and managed plant risk as required by 10 CFR 50.65(a)(4) and licensee procedures. The inspectors assessed the adequacy of the licensees risk assessments and implementation of risk management actions. The inspectors also verified that the licensee was identifying and resolving problems with assessing and managing maintenance-related risk using the CAP. Additionally, for maintenance resulting from unforeseen situations, the inspectors assessed the effectiveness of the licensees planning and control of emergent work activities. Documents reviewed are listed in the Attachment.

Unit 2, April 3, 2017, elevated risk during refueling outage B223R1 fuel movement

Unit 2, April 6, 2017, elevated risk during refueling outage B223R1 electrical work window

Unit 2, April 10, 2017, elevated risk during refueling outage B223R1 vessel draindown

Unit 2, May 15, 2017, elevated risk with 2-CAC-V17, reactor building to torus vacuum breaker, unplanned inoperability

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

Main article: IP 71111.15

a. Inspection Scope

Operability and Functionality Review The inspectors selected the operability determinations or functionality evaluations listed below for review based on the risk-significance of the associated components and systems. The inspectors reviewed the technical adequacy of the determinations to ensure that TS operability was properly justified and the components or systems remained capable of performing their design functions. To verify whether components or systems were operable, the inspectors compared the operability and design criteria in the appropriate sections of the TS and updated final safety analysis report to the licensees 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. Additionally, the inspectors reviewed a sample of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the Attachment.

Unit 2, residual heat removal (RHR) valve F047B, heat exchanger 2B inlet valve, ground alarm, NCR 2113446

Unit 2, emergency diesel generators (EDG) 2 overspeed relay failure, NCR 2120738

Unit 2, RCIC high moisture content in turbine oil, NCR 2126899

Unit 2, RCIC steam leak, NCR 2127691

Unit 2, primary containment inoperable during startup, NCR 2116753

b. Findings

One licensee-identified violation was documented in Section 4OA7.

1R18 Plant Modifications

Main article: IP 71111.18

a. Inspection Scope

The inspectors verified that the plant modifications listed below did not affect the safety functions of important safety systems. The inspectors confirmed the modifications did not degrade the design bases, licensing bases, and performance capability of risk significant SSCs. The inspectors also verified modifications performed during plant configurations involving increased risk did not place the plant in an unsafe condition.

Additionally, the inspectors evaluated whether system operability and availability, configuration control, post-installation test activities, and changes to documents, such as drawings, procedures, and operator training materials, complied with licensee standards and NRC requirements. In addition, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with modifications. Documents reviewed are listed in the

.

NCR 2124497, Carabiners installed for barring gear locking pins on EDGs 1, 2 and 3

EC408181, Unit 2 RHR F047B, heat exchanger 2B inlet valve, motor replacement

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

a. Inspection Scope

The inspectors either observed post-maintenance testing or reviewed the test results for the maintenance activities listed below to verify the work performed was completed correctly and the test activities were adequate to verify system operability and functional capability.

WO 20156990, Unit 2, EDG 4 starting air pin failure, March 30, 2017

WO 20096176, Unit 2, 2-CAC-V17 reactor building to torus vacuum breaker inoperable, May 15, 2017

WO 20153997, Unit 1, service water backdraft damper lubrication, May 25, 2017

WO 20157390, Unit 2, RHR F047B, heat exchanger 2B inlet valve, motor replacement, May 30, 2017

WO 20156298 , Unit 2, HPCI planned maintenance outage, June 14, 2017

WO 13538781, Units 1, EDG 2 planned maintenance outage, June 8, 2017 The inspectors evaluated these activities for the following:

Acceptance criteria were clear and demonstrated operational readiness

Effects of testing on the plant were adequately addressed

Test instrumentation was appropriate

Tests were performed in accordance with approved procedures

Equipment was returned to its operational status following testing

Test documentation was properly evaluated Additionally, the inspectors reviewed a sample of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with post-maintenance testing. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Main article: IP 71111.20

a. Inspection Scope

.1 Unit 2 Refueling Outage B223R1

Main article: IP 71111.20

Unit 2 began the inspection period in refueling outage B223R1. The inspectors reviewed outage plans and contingency plans for the Unit 2 refueling outage, which ended with the generator synchronization to the grid on April 15, 2017, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth of key safety functions.

During the refueling outage, the inspectors monitored licensee controls over the following outage activities:

Licensee configuration management, including maintenance of defense-in-depth for key safety functions and compliance with the applicable Technical Specifications (TSs) when taking equipment out of service

Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing

Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error

Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities

Monitoring of decay heat removal processes, systems, and components

Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system

Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss

Controls over activities that could affect reactivity

Maintenance of secondary containment as required by TS

Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing

Licensee identification and resolution of problems related to refueling outage activities Documents reviewed are listed in the Attachment.

.2 Unit 1 Maintenance Outage B120F1

Main article: IP 71111.20

For the Unit 1 maintenance outage to replace the 1B recirculation pump seal, from April 25, 2017, through April 28, 2017, the inspectors evaluated the following outage activities:

shutdown, cooldown, heatup, and startup

reactor coolant system instrumentation and electrical power configuration

reactivity and inventory control

decay heat removal and spent fuel pool cooling system operation The inspectors verified that the licensee:

controlled plant configuration in accordance with administrative risk reduction methodologies

developed work schedules to manage fatigue

developed mitigation strategies for loss of key safety functions

adhered to operating license and TS requirements Inspectors verified that safety-related and risk-significant SSCs not accessible during power operations were maintained in an operable condition. The inspectors also reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with outage activities. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

a. Inspection Scope

The inspectors reviewed the surveillance tests listed below and either observed the test or reviewed test results to verify testing activities adequately demonstrated that the affected SSCs remained capable of performing the intended safety functions (under conditions as close as practical to design bases conditions or as required by TS) and maintained their operational readiness.

The inspectors evaluated the test activities to assess for preconditioning of equipment, procedure adherence, and equipment alignment following completion of the surveillance.

Additionally, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with surveillance testing. Documents reviewed are listed in the Attachment.

Routine Surveillance Tests

Procedure 2MST-RPS41R, RPS Logic System Functional Test, April 6, 2017

Procedure 0PT-80.1, Reactor Pressure Vessel ASME Section XI Pressure Test, May 11, 2017 In-Service Tests (IST)

Procedure 0PT-09.2, HPCI System Operability Test, May 10, 2017 Reactor Coolant System Leak Detection

Procedure 0OI-02.3, Unit 1 Drywell Leakage Control, April 25, 2017

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

Main article: IP 71114.06

a. Inspection Scope

The inspectors observed the emergency preparedness drill conducted on June 1, 2017, involving a NSW header leak and RCIC steam line break with failure to isolate. The inspectors observed licensee activities in the simulator and technical support center to evaluate implementation of the emergency plan, including event classification, notification, and protective action recommendations. The inspectors evaluated the licensees performance against criteria established in the licensees procedures.

Additionally, the inspectors attended the post-exercise critique to assess the licensees effectiveness in identifying emergency preparedness weaknesses and verified the identified weaknesses were entered in the CAP. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

Main article: IP 71151

a. Inspection Scope

The inspectors reviewed a sample of the performance indicator data, submitted by the licensee, for the Unit 1 and Unit 2 PIs listed below. The inspectors reviewed plant records compiled between April 1, 2016, through March 31, 2017, to verify the accuracy and completeness of the data reported for the station. The inspectors verified that the PI data complied with guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, and licensee procedures. The inspectors verified the accuracy of reported data that were used to calculate the value of each PI.

In addition, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with PI data. Documents reviewed are listed in the Attachment.

Cornerstone: Mitigating Systems

Units 1 and 2, safety system functional failures

Units 1 and 2, emergency AC power system

Units 1 and 2, cooling water system

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

Main article: IP 71152

.1 Routine Review

The inspectors screened items entered into the licensees corrective action program to identify repetitive equipment failures or specific human performance issues for follow-up.

The inspectors reviewed condition reports, attended screening meetings, or accessed the licensees computerized corrective action database.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors reviewed issues entered in the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on human performance trends during Unit 2 refueling outage B223R1, but also considered the results of inspector daily condition report screenings, licensee trending efforts, and licensee human performance results. The review nominally considered the 6-month period of January 1, 2017, through June 30, 2017, although some examples extended beyond those dates when the scope of the trend warranted. The inspectors compared their results with the licensees analysis of trends. Additionally, the inspectors reviewed the adequacy of corrective actions associated with a sample of the issues identified in the licensees trend reports. The inspectors also reviewed corrective action documents that were processed by the licensee to identify potential adverse trends in the condition of structures, systems, and/or components as evidenced by acceptance of long-standing non-conforming or degraded conditions. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

.3 Annual Follow-Up of Selected Issues

a. Inspection Scope

The inspectors conducted a detailed review of the following condition report:

NCR 2120423, rising trend in Unit 2 suppression pool temperature, April 30, 2017 The inspectors evaluated the following attributes of the licensees actions:

complete and accurate identification of the problem in a timely manner

evaluation and disposition of operability and reportability issues

consideration of extent of condition, generic implications, common cause, and previous occurrences

classification and prioritization of the problem

identification of root and contributing causes of the problem

identification of any additional condition reports

completion of corrective actions in a timely manner Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA3 Follow-up of Events

Main article: IP 71153

.1 (Closed) Licensee Event Report (LER) 05000324/2017-001-00, Implementation of

Enforcement Guidance Memorandum (EGM) 11-003, Revision 3

a. Inspection Scope

On March 22, 2017, Unit 2 implemented the guidance of EGM 11-003, Revision 3, Enforcement Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with TS Containment Requirements During Operations with a Potential for Draining the Reactor Vessel. Consistent with this EGM, secondary containment operability was not maintained during operations with the potential for draining the reactor vessel activities. The EGM guidance was implemented from March 22, 2017, at 1209 to March 28, 2017, at 1230. The activities are discussed in Section 4OA5.

Inspectors verified compliance with the guidelines of EGM 11-003 prior to and during these activities. The licensee has submitted a license amendment request to adopt TS Task Force traveler associated with generic resolution of this issue. The licensee entered this issue into the CAP as NCR 2110409. Documents reviewed are listed in the

.

b. Findings

The enforcement actions associated with this LER are documented in Sections 4OA5.

No findings were identified during the review of this LER. This LER is closed.

.2 (Closed) LER 05000324/2017-002-00, Plant Mode Change with Primary Containment

Inoperable

a. Inspection Scope

On April 13, 2017, Unit 2 was in Mode 4 preparing to exit refueling outage B223R1. The primary containment was being vented to ensure habitability during maintenance in the drywell. At 2347, the reactor was taken to Mode 2 with the primary containment still aligned for venting. In this condition, the drywell ventilation makes the primary containment inoperable due to the drywell and the suppression chamber being in communication to each other. With primary containment inoperable during startup, the plant violated Limiting Condition for Operation (LCO) 3.0.4, which requires all LCOs to be met for the plant condition prior to entry into the applicable mode.

The licensee reported this event in accordance with 10 CFR 50.72(b)(3)(v)(D), a non-emergency 8-hour report. The licensee also reported this event in accordance with 10 CFR 50.73(a)(2)(i)(B), for entering a condition prohibited by TSs, and 10 CFR 50.73(a)(2)(v)(D), for a loss of safety function. The cause of the event was the failure of operations personnel to initiate a tracking LCO for primary containment being inoperable in accordance with licensee procedure 0OI-01.01, BNP Conduct of Operations Supplement. The licensee determined a tracking LCO should have been initiated to ensure the primary containment was restored to operable prior to entering Mode 2. As immediate corrective actions, the licensee restored containment to operable on April 14, 2017, at 0030, and the Shift Manager and Control Room Supervisor were removed from shift. Further, a remediation plan was developed and implemented to assess the Shift Manager and Control Room Supervisor for watch standing and reinstatement. The licensee entered this issue into CAP as NCR 2116753. Documents reviewed are listed in the Attachment.

b. Findings

The enforcement actions associated with this LER are documented in Section 4OA7.

No findings were identified during the review of this LER. This LER is closed.

.3 (Closed) LER 05000325;324/2016-006-01, Control Room AC Units Inoperable Due to

Corroded Supports

a. Inspection Scope

On December 14, 2016, the 2D control room AC unit was declared inoperable due to corrosion on the support channels, and Units 1 and 2 entered TS 3.7.4, Condition A. On January 30, 2017, the 1D control room AC unit was declared inoperable for corrosion on the support channels. The corrosion was due to trapped moisture in contact with steel supports exposed to a local marine environment. The corrosion degraded the supports to the point that the safety function of the AC unit would be lost during a seismic event.

Since the degradation was due to corrosion, both units were determined to be inoperable at the same time. The conditions were determined to have existed longer than the TS 3.7.4 allowed outage time. The licensee entered this issue into the CAP as NCRs 2113799 and 2113800. As corrective actions, the licensee replaced both AC units supports, declared the units operable, and inspected the 2E control room AC unit for corrosion.

b. Findings

The inspectors identified the licensee failed to recognize the 1D AC unit was inoperable on December 1, 2016, during the periodic inspection. The inspectors documented an NRC-identified Green NCV in Inspection Report 05000325;324/2017001, Section 4OA2.

No additional findings were identified during the review of this LER. This LER is closed.

.4 (Closed) LER 05000325;324/2017-002, Foreign Material in Switch Results in Unplanned

Automatic Start of Emergency Diesel Generators

a. Inspection Scope

On April 17, 2017, Unit 2 was in Mode 1 at approximately 22 percent of rated power and was starting up from a refueling outage. Operators manually tripped the Unit 2 main turbine to halt increasing bearing vibration. The power circuit breakers for the Unit 2 main generator did not open as expected on the turbine trip, but subsequently opened when main generator reverse power relays actuated. This resulted in the automatic start of all four EDGs. The EDGs did not tie to emergency busses because offsite power was still available. This event was caused by a turbine stop valve limit switch failing to open due to foreign material intrusion. There was no safety impact of the failed limit switch.

The licensee entered this issue into the CAP as NCR 2117033. As corrective actions, the licensee will inspect similar switches during the next scheduled refueling outage on each unit (i.e., spring 2018 for Unit 1 and spring 2019 for Unit 2).

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Implementation of EGM 11-003, Revision 3, Enforcement Guidance Memorandum on

Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel

a. Inspection Scope

The inspectors reviewed the plants implementation of NRC EGM 11-003, Revision 3, during Unit 2 maintenance activities for operations with a potential for draining the reactor vessel (OPDRVs), during the Unit 2 refueling outage. Inspectors verified that for all dates, all other TS requirements were met during OPDRVs with secondary containment inoperable. Documents reviewed are listed in the Attachment.

b. Findings

Description.

During the Unit 2 refueling outage, the OPDRVs activities are listed below:

March 21, 2017: 6 gallons per minute leakage for maintenance associated with the 2B recirculation pump seal rebuild

March 23, 2017: 48 gallons per minute leakage for hydraulic control unit draining to support rod maintenance

March 24, 2017: 65 gallons per minute leakage to close the excess flow check valve and cap the drain line

March 27, 2017: 71.2 gallons per minute leakage to replace the low power range monitors and intermediate power range monitors These activities took place without secondary containment being operable.

Enforcement.

TS 3.6.4.1, Secondary Containment, requires that secondary containment be operable and is applicable during OPDRVs. The required action if secondary containment is inoperable in this condition is to initiate actions to suspend OPDRVs immediately. Contrary to the above, on March 21, 2017, March 23, 2017, March 24, 2017, and March 27, 2017, the licensee failed to maintain secondary containment operable while performing OPDRVs.

However, because the violations were identified during the discretion period described in EGM 11-003, Revision 3, and the licensee met the criteria established in the EGM prior to and during these activities, the NRC exercised enforcement discretion (Enforcement Action-17-123) for the dates of March 21, 2017, March 23, 2017, March 24, 2017, and March 27, 2017, in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation. The inspectors observed that Brunswick has already submitted a license amendment request (BSEP 17-0060) on June 29, 2017 which was accepted for review by the NRC on July 18, 2017. The licensee entered this issue into the CAP as NCR 2110409.

4OA6 Meetings, Including Exit

On July 12, 2017, the resident inspectors presented the inspection results to Mr. Gideon and other members of the licensees staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

4OA7 Licensee Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as a non-cited violation.

LCO 3.0.4 states, in part, when an LCO is not met, entry into a MODE or other specified condition in the applicability shall only be made when the associated ACTIONS to be entered permit continued operation in the MODE for an unlimited period of time.

Contrary to the above, on April 13, 2017, at 2347, the licensee changed modes on Unit 2 from Mode 4 to Mode 2 with the primary containment inoperable. Specifically, TS 3.6.1.1, Primary Containment, requires primary containment to be operable in Modes 1, 2, and 3, however, the reactor was taken to Mode 2 with the primary containment still aligned for venting. In this condition, the drywell ventilation makes the primary containment inoperable due to the drywell and the suppression chamber being in communication to each other. This condition is allowed for two hours before the required action to shutdown to Mode 4 is required. Since the required action is not permitted for continued operation, a violation of LCO 3.0.4 occurred. The cause of the event was the failure of operations personnel to initiate a tracking LCO for primary containment being inoperable in accordance with licensee procedure 0OI-01.01, BNP Conduct of Operations Supplement. The licensee determined a tracking LCO should have been initiated to ensure the primary containment was restored to operable prior to entering Mode 2. As immediate corrective actions, the licensee restored containment to operable on April 14, 2017, at 0030, and the Shift Manager and Control Room Supervisor were removed from shift. Further, a remediation plan was developed and implemented to assess the Shift Manager and Control Room Supervisor for watch standing and reinstatement.

This finding is associated with the Barrier Integrity Cornerstone. Using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, 1, Exhibit 4, Barrier Integrity Screening Questions, the finding screened to Green because it did not degrade the ability to close or isolate the containment, it did not degrade the physical integrity of reactor containment, and it did not involve an actual reduction in function of hydrogen control. This issue was documented in the licensees CAP as NCR 2116753.

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