Text

NRC Integrated Inspection Report Nos. 05000325/2015004 and 05000324/2015004 and Notice of Enforcement Discretion
	ML16032A467
Person / Time
Site:	Brunswick
Issue date:	02/01/2016
From:	Hopper G; NRC/RGN-II/DRP/RPB4
To:	William Gideon; Progress Energy Carolinas
References
	EA-16-015 IR 2015004
	Download: ML16032A467 (33)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION ary 1, 2016

SUBJECT:

BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2015004 AND 05000324/2015004 AND NOTICE OF ENFORCEMENT DISCRETION

Dear Mr. Gideon:

On December 31, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Brunswick Steam Electric Plant Units 1 and 2 facilities. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 21, 2016, with you and other members of your staff.

One self-revealing finding of very low safety significance (Green) was identified during this inspection. This finding was determined to involve a violation of NRC requirements. The NRC is treating this finding as a non-cited violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

The enclosed report also documents noncompliances for which the NRC is exercising enforcement discretion in accordance with Section 9.1 of the NRC Enforcement Policy, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). The noncompliances are associated with your implementation of the requirements and standards of your technical specifications, as well as 10 CFR Part 50, Appendix R, Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979. The inspectors have screened the violation and determined that it warrants enforcement discretion per the Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues, and Section 11.05.b of Inspector Manual Chapter 0305.

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, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Brunswick Steam Electric Plant.

If you disagree with the cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the Brunswick Steam Electric Plant. In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's Agencywide Documents Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62

Enclosure:

IR 05000325, 324/2015004 w/Attachment: Supplementary Information

REGION II==

Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62 Report No.: 05000325/2015004, 05000324/2015004 Licensee: Duke Energy Progress, Inc.

Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: Southport, NC Dates: October 1, 2015 through December 31, 2015 Inspectors: M. Catts, Senior Resident Inspector M. Schwieg, Resident Inspector M. Bates, Sr. Operations Engineer (Section 1R11)

W. Loo, Senior Health Physicist (Section 4OA5)

M. Singletary, Reactor Inspector (Section 4OA3)

D. Jones, Senior Reactor Inspector (Section 4OA3)

Approved by: George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY

IR 05000325/2015004, 05000324/2015004; October 1, 2015, through December 31, 2015;

Brunswick Steam Electric Plant, Units 1 and 2; Post-Maintenance Testing.

This report covered a three-month period of inspection by resident inspectors and regional inspectors. One self-revealing violation is 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 (IMC) 0609, Significance Determination Process (SDP)dated June 19, 2012. The cross-cutting aspects are determined using IMC 0310, Aspects within the Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated February 4, 2015.

The NRCs program for overseeing the safe operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Rev.

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green.

A self-revealing Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, was identified for the failure of the licensee to have an adequate procedure for the 2C residual heat removal service water (RHRSW) pump motor bearing maintenance. Specifically, licensee procedure 0CM-M503,

Maintenance Instructions for the RHRSW Booster Pump Motors, did not contain information to ensure proper sealing of the 2C RHRSW motor bearings. This finding resulted in a violation of technical specification (TS) 3.0.4, Limiting Condition for Operation (LCO)

Applicability, and TS 3.7.1, RHRSW System. As immediate corrective actions, the licensee applied sealant to the motor bearings. Additionally, the licensee revised procedure 0CM-M503 and added a detailed location for applying the sealant to the RHRSW pump motors.

The licensee entered this issue into the Corrective Action Program (CAP) as nuclear condition report (NCR) 742643.

The inspectors determined the licensees failure to have an adequate procedure for the 2C RHRSW pump motor bearing maintenance was a performance deficiency. The finding was more than minor because it was associated with the procedural quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate procedure resulted in the inoperability of the Loop A RHRSW subsystem, and the loss of safety function while the Loop B RHRSW subsystem was out for maintenance. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding screened to a more detailed risk evaluation, since the finding represented a loss of system and/or function. The regional Senior Reactor Analyst performed a detail risk review of the finding. The at-power model was conservatively used to bound the risk that would happen at the proposed time of failure, which was many days after shutdown due to the time it takes for the oil leak to cause potential bearing failure. Since the licensee had procedures for running the service water (SW) system without the RHRSW pumps energized, and the decay heat loads at the time of failure would be low, a failure rate of only 0.1 for the loss of function was assumed. This was also conservative, since the adverse conditions that would have prevented refill of the oil were LOCA assumptions, and LOCA sequences did not contribute greatly to the risk in the model.

The at-power models solution was more than an order of magnitude below the Green/White threshold for the SDP. Therefore, the finding was determined to be of very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance associated with the challenge the unknown attribute because the licensee did not stop when faced with uncertain conditions, and risks were not evaluated and managed before proceeding. Specifically, the licensee continued through the 2010 and 2013 2C RHRSW pump maintenance outages, even when the bearings were found without sealant.

Additionally, the licensee did not question the procedurally required location for the sealant.

H.11 (Section 1R19)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at rated thermal power (RTP). On October 17, 2015, the unit was down powered to 78 percent for a scheduled control rod improvement. The unit was returned to RTP on October 18, 2015. On November 7, 2015, the unit was shut down to replace the 1A reactor coolant recirculation pump seal. The unit was restarted on November 11, 2015 and returned to RTP on November 14, 2015. On November 28, 2015, the unit was down powered to 85 percent for a scheduled control rod improvement. The unit was returned to RTP on November 28, 2015. On December 11, 2015, the unit was down powered to 70 percent for a scheduled control rod sequence exchange. The unit was returned to RTP on December 12, 2015, and remained at or near RTP for the remainder of the inspection period.

Unit 2 began the inspection period at RTP. On November 18, 2015, the unit was down powered to 50 percent to isolate the 2B North water box and to repair the water box outlet valve. After the repairs were completed, the unit was returned to RTP on November 19, 2015. On December 18, 2015, the unit was down powered to 70 percent for a scheduled control rod sequence exchange. The unit was returned to RTP on December 19, 2015, and remained at or near 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

.1 Seasonal Extreme Weather Conditions

The inspectors conducted a detailed review of the stations seasonal preparation procedures written for winter conditions. 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 seasonal preparation procedures and compensatory measures, before the onset of and during winter weather conditions. The inspectors walked down the following buildings that are designed to protect risk-significant systems:

SW Building

Intake Structure and Circulating Water Pump Bay

Emergency Diesel Generator (EDG) Building

Control Building Documents reviewed are listed in the Attachment

.2 Impending Adverse Weather Conditions

The inspectors reviewed the licensees preparations to protect risk-significant systems from Hurricane Joaquin. The inspectors evaluated the licensees implementation of adverse weather preparation procedures and compensatory measures, including operator staffing, before the onset of and during the adverse weather conditions. The inspectors reviewed the licensees plans to address the ramifications of potentially lasting effects that may result from adverse weather conditions. The inspectors verified that operator actions specified in the licensees adverse weather procedure maintain readiness of essential systems. The inspectors verified that required surveillances were current, or were scheduled and completed, if practical, before the onset of anticipated adverse weather conditions. The inspectors also verified that the licensee implemented periodic equipment walkdowns or other measures to ensure that the condition of plant equipment met operability requirements. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Main article: IP 71111.04

a. Inspection Scope

.1 Partial Walkdown

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 2, high pressure coolant injection (HPCI) on October 5, 2015

Unit 2, nuclear service water (NSW) with 2B conventional service water (CSW) pump out of service due to planned maintenance on October 6, 2015

Units 1 and 2, EDG 1 following the maintenance outage on October 29, 2015

.2 Complete Walkdown

The inspectors verified the alignment of the Unit 1 residual heat removal (RHR) system on October 7-9, 2015. The inspectors selected this system for assessment because it is a risk-significant mitigating system. The inspectors determined the correct system lineup by reviewing plant procedures, drawings, the updated final safety analysis report, and other documents. The inspectors reviewed records related to the system outstanding design issues, maintenance work requests, and deficiencies. The inspectors verified that the selected system was correctly aligned by performing a complete walkdown of accessible components.

To verify the licensee was identifying and resolving equipment alignment discrepancies, the inspectors reviewed corrective action documents, including NCRs and outstanding work orders (WOs). The inspectors also reviewed periodic reports containing information on the status of risk-significant systems, including maintenance rule reports and system health reports. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R05 Fire Protection

Main article: IP 71111.05Q

a. Inspection Scope

Quarterly Inspection The inspectors evaluated the adequacy of selected pre-fire plans and fire protection procedures 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

.

0PFP-RW-01B, Radwaste Building, 23 foot elevation

1PFP-CB-7/8 and 2PFP-CB-9/10, Control Building, battery rooms 1A, 1B, 2A, and 2B

0PFP-MBPA, Makeup Water Treatment Building

2PFP-RB2-01M, Reactor Building, refueling floor, 117 foot elevation

1PFP-RB1-01H, Reactor Building, 50 foot elevation

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Main article: IP 71111.06

a. Inspection Scope

Internal Flooding The inspectors reviewed related flood analysis documents and performed a walkdown of the area listed below containing risk-significant structures, systems, and components (SSCs) susceptible to flooding. The inspectors verified that plant design features and plant procedures for flood mitigation were consistent with design requirements and internal flooding analysis assumptions. The inspectors also assessed the condition of flood protection barriers and drain systems. In addition, the inspectors verified the licensee was identifying and properly addressing issues using the CAP. Documents reviewed are listed in the Attachment.

Unit 1 and Unit 2, SW Building

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 November 4, 2015, the inspectors observed a simulator scenario including seismic events and an unisolable high energy line break conducted for training of an operating crew.

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

The inspectors observed licensed operator performance in the main control room during the Unit 1 shutdown, Unit 1 startup, and Unit 2 lowering main condenser vacuum.

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.

.3 Annual Review of Licensee Requalification Examination Results

On October 23, 2015, the licensee completed the comprehensive biennial requalification written examinations and the annual requalification operating examinations required to be administered to all licensed operators in accordance with Title 10 of the Code of Federal Regulations (10 CFR) 55.59(a)(2), Requalification Requirements, of the NRCs Operators Licenses. The inspectors performed an in-office review of the overall pass/fail results of the individual operating examinations, written examinations, and the crew simulator operating examinations in accordance with Inspection Procedure (IP) 71111.11, Licensed Operator Requalification Program. These results were compared to the thresholds established in Section 3.02, Requalification Examination Results, of IP 71111.11. 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 issue 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 13502386, EDG 1 install relay surge suppression

WO 13498022, Replace 1A reactor coolant recirculation pump seal due to rising seal pressure

WO 20017615, Safety-related bus E6 1-E6-AW7-52 breaker tripped open

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.

Yellow risk condition due to the EDG 3 and Unit 2 HPCI outage on October 13, 2015

Yellow risk condition due to the Unit 1 NSW, EDG 3, and Unit 2 HPCI outage on October 15, 2015

Elevated risk condition due to Unit 1 outage to replace the 1A reactor coolant recirculation pump seal on November 7, 2015

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

Main article: IP 71111.15

a. Inspection Scope

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 1, indicated rise in stack effluent radiation levels while venting

Unit 2, EDG 3 oil leak on governor

Unit 1, hydraulic control unit 42-43 audible noise

Unit 1, radwaste cleanup isolation valve thermal overload

Unit 2, rain intrusion into reactor building

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.

Unit 2, WO 13509700, April 11, 2015, 2C RHRSW pump motor leak seal repair

Unit 1, WO 20017615, September 29, 2015, circuit breaker from bus E6 to 1CB tripped

Unit 2, WO 20026808, October 15, 2015, EDG 3 maintenance outage

Unit 2, WO 20026910, October 17, 2015, 2B NSW pump strainer shear pin failure

Units 1 and 2, WO 20030188, October 31, 2015, EDG 2 thermostat replacement

Unit 2, WO 20013933, November 19, 2015, reactor core isolation cooling (RCIC)maintenance outage

Unit 1, WO 13340921, December 15, 2015, 1A NSW pump breaker 12-year maintenance 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

Introduction:

A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the failure of the licensee to have an adequate procedure for the 2C RHRSW pump motor bearing maintenance.

Specifically, licensee procedure 0CM-M503, Maintenance Instructions for the RHRSW Booster Pump Motors, did not contain information to ensure proper sealing of the 2C RHRSW motor bearings. This finding resulted in a violation of TS 3.0.4, LCO Applicability, and TS 3.7.1, RHRSW System.

Description:

On April 8, 2015, while performing testing on nearby equipment, the licensee noticed oil pooling under the 2C RHRSW pump motor. Based on oil additions since March 20, 2015, the licensee determined that the motor was leaking oil at a rate that would have exceeded the allowable leakage for the 2C RHRSW pump to meet the 30-day mission time. The pump was declared inoperable and the licensee entered TS 3.7.1, RHRSW System.

On April 10, 2015, a vendor technical representative inspected the 2C RHRSW pump motor for the cause of the oil leak, following disassembly of the motor bearings. The technical representative concluded that the oil leak was a result of no Permatex or equivalent sealant on the inboard and outboard bearing split lines. Sealant was applied in accordance with the General Electric (GE) technical manual and the bearings were reassembled. The 2C RHRSW pump/motor was successfully tested and declared operable on April 11, 2015.

The licensee performed a cause evaluation and determined the root cause to be a less than adequate process for identifying and updating maintenance procedures that are impacted by safety-related SSC engineering changes, and a contributing cause to be licensee procedure 0CM-M503, Maintenance Instructions for the RHRSW Booster Pump Motors, did not have sufficient detail identifying specific parts/location per vendor technical manual for applying sealant [to the motor bearings]. Licensee procedure 0CM-M503, section 7.3 step 4, directed maintenance personnel to coat the sealing surfaces of the oil shield with sealing compound No. 3 Permatex or equivalent.

However, procedure 0CM-M503, Attachment 1, Motor Cutaway Views, did not identify a part as the oil shield. The inspectors review of the GE technical manual identified that sealant was to be applied to the horizontal joints of the upper bearing cap (which is accurately labeled according to the technical manuals bearing drawing). As stated in the technical manual (FP-3207 page 21 of 222) - during bearing reassembly, The sealing surfaces of the end shield and oil deflectors should be coated with a sealing compound such as GE No. 1201 Glyptal Alkyrd resin or No. 3 Permatex to prevent oil leakage.

The licensee revised procedure 0CM-M503 under procedure revision request 750349, and added a detailed location for applying the sealant to the RHRSW pump motors. An additional contributing cause was a lack of questioning attitude by the maintenance technicians regarding the absence of sealant on the bearings during 2C RHRSW pump motor maintenance activities in 2010 and 2013, although licensee procedure 0CM-M503 directed maintenance personnel to coat the sealing surfaces of the oil shield.

Based on a review for the past three years per 10 CFR 50.73(a)(1), the inspectors determined the licensee violated TS 3.0.4, LCO Applicability, when the 2C RHRSW pump was inoperable when changing modes during the Unit 2 reactor startup on May 3, 2013, May 5, 2013, May 7, 2013, April 4, 2015, and April 5, 2015. Further, the inspectors determined the licensee violated TS 3.7.1, RHRSW System, Condition A, from when the motor was installed on July 18, 2002, to April 11, 2015, for the 2C RHRSW pump being inoperable for greater than the 14-day TS allowed outage time, without shutting down as required by Condition D. Also, the licensee violated TS 3.7.1, Conditions C and D, on July 11, 2012 and July 9, 2014, when the 2C RHRSW pump (Loop A) was inoperable while Loop B was inoperable for planned maintenance, resulting in a loss of safety function for the suppression pool cooling mode of RHR without restoring one RHRSW subsystem to operable within eight hours, without shutting down. On June 8, 2015, and revised August 5, 2015, the licensee reported the TS violations as required by 10 CFR 50.73(a)(2)(i)(B) (i.e., operation or condition prohibited by TS) and 10 CFR 50.73(a)(2)(v)(B) (event or condition that could have prevented the fulfillment of the safety function of structures or systems needed to remove residual heat), as discussed in Section 4OA3. The inspectors determined the mission time for equipment in the reactor building assumes that plant personnel will not be able to access the areas for 30 days, based on high dose rates in excess of the NRC 5 REM limit, resulting in no oil additions to the 2C RHRSW pump.

Analysis:

The inspectors determined the licensees failure to have an adequate procedure for the 2C RHRSW pump motor bearing maintenance was a performance deficiency. The finding was more than minor because it was associated with the procedural quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the inadequate procedure resulted in the inoperability of the Loop A RHRSW subsystem, and the loss of safety function while the Loop B RHRSW subsystem was out for maintenance. Using IMC 0609, Appendix A, issued June 19, 2012, the SDP for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined the finding screened to a more detailed risk evaluation, since the finding represented a loss of system and/or function. The regional Senior Reactor Analyst performed a detail risk review of the finding. The at-power model was conservatively used to bound the risk that would happen at the proposed time of failure, which was many days after shutdown due to the time it takes for the oil leak to cause potential bearing failure. Since the licensee had procedures for running the service water (SW) system without the RHRSW pumps energized, and the decay heat loads at the time of failure would be low, a failure rate of only 0.1 for the loss of function was assumed. This was also conservative, since the adverse conditions that would have prevented refill of the oil were LOCA assumptions, and LOCA sequences did not contribute greatly to the risk in the model. The at-power models solution was more than an order of magnitude below the Green/White threshold for the SDP. Therefore, the finding was determined to be of very low safety significance (Green). The finding has a cross-cutting aspect in the area of human performance associated with the challenge the unknown attribute because the licensee did not stop when faced with uncertain conditions, and risks were not evaluated and managed before proceeding.

Specifically, the licensee continued through the 2010 and 2013 2C RHRSW pump maintenance outages, even when the bearings were found without sealant. Additionally, the licensee did not question the procedurally required location for the sealant. H.11

Enforcement:

Appendix B of 10 CFR Part 50, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures.

TS 3.0.4, LCO Applicability, requires, 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 or other specified condition in the Applicability for an unlimited period of time.

TS 3.7.1, RHRSW System, requires two RHRSW subsystems to be operable. The required action for Condition A was to restore the RHRSW pump to operable status within 14 days. The required action for Condition C was to restore one subsystem to operable status within eight hours. If the required actions and associated completion time for Conditions A and C are not met, the required action for Condition D was to be in Mode 3 in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4 in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

Contrary to the above, from July 18, 2002, to April 11, 2015, the licensee failed to ensure procedure OCM-M503 was appropriate for the maintenance of the RHRSW pumps.

Specifically, licensee procedure 0CM-M503, did not contain detailed information to ensure proper sealing of the 2C RHRSW motor bearings.

As a result, on at least the following instances, May 3, May 5, May 7, 2013; April 4, and April 5, 2015, Unit 2 entered a different mode or applicability condition in which the mode change did not comply with TS LCO 3.0.4.

Additionally, from when the motor was installed on July 18, 2002, to April 11, 2015, the duration of the 2C RHRSW pump inoperability exceeded the 14-day TS allowed outage time. Also, on at least the following instances, July 11, 2012, and July 9, 2014, both Loops A and B RHRSW subsystems were inoperable for greater than eight hours when the 2C RHRSW pump was inoperable in Loop A, and RHRSW Loop B was removed from service for maintenance.

As immediate corrective actions, the licensee applied sealant to the motor bearings.

Additionally, the licensee revised procedure 0CM-M503 and added a detailed location for applying the sealant to the RHRSW pump motors. Because this finding is of very low safety significance (Green) and was entered into the licensees CAP as NCR 742643, consistent with Section 2.3.2.a of the NRCs Enforcement Policy, this violation is being treated as a NCV: NCV 05000324/2015004-01, Inadequate Procedure for the 2C RHRSW Pump Motor Bearings.

1R20 Refueling and Other Outage Activities

Main article: IP 71111.20

a. Inspection Scope

For the Unit 1 maintenance outage for replacement of the 1A reactor coolant recirculation pump seal, from November 7, 2015 through November 11, 2015, the inspectors evaluated the following outage activities:

outage planning

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

containment closure The inspectors verified that the licensee:

considered risk in developing the outage schedule

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 adequately demonstrated equipment operability and met TS and licensee procedural requirements. 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

0PT-09.7, Unit 1 HPCI System Operability Test, October 17, 2015 In-Service Tests

0PT-09.2, Unit 2 HPCI Valve Operability Test, October 14, 2015

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 November 4, 2015, involving seismic events and an unisolable high energy line break.

The inspectors observed licensee activities in the simulator and/or 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 Verification

Main article: IP 71151

a. Inspection Scope

The inspectors reviewed a sample of the performance indicator (PI) data, submitted by the licensee, for the Unit 1 and Unit 2 PIs listed below. The inspectors reviewed plant records compiled between October 1, 2014, and September 30, 2015 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

Unit 1, high pressure injection system - HPCI

Unit 1, heat removal system - RCIC

Unit 2, high pressure injection system - HPCI

Unit 2, heat removal system - RCIC

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 CAP in order to identify repetitive equipment failures or specific human performance issues for follow-up. The inspectors reviewed condition reports (CRs), 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 CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on the chemistry and engineering departments, but also considered the results of inspector daily CR screenings, licensee trending efforts, and licensee human performance results. The review nominally considered the 6-month period of July 1, 2015 through December 31, 2015, 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 Attachment.

b. Findings and Observations

No findings were identified.

The inspectors evaluated a sample of CRs generated over the course of the past two quarters by the chemistry and engineering departments. The inspectors determined that, in most cases, the issues were appropriately evaluated by licensee staff for potential trends and resolved within the scope of the CAP. However, the inspectors noted on the following five occasions that shear pins on safety-related SW strainers sheared, resulting in unavailability of the SW pump.

Shear pin failures occurred on the following strainers:

o 1C CSW pump strainer on February 13, 2014, as described in NCR 668564 o 2C CSW pump strainer on April 8, 2015, as described in NCR 742444 o 2B NSW pump strainer on September 20, 2015, September 30, 2015, and October 16, 2015, as described in NCR 1966266 The inspectors had previously documented a finding for the 2C CSW pump strainer shear pin failure as FIN: FIN 05000324/2015002-03, Failure to Perform an Adequate Extent of Condition Review for the 1C Conventional Service Water Pump Strainer. The inspectors will review the 2B NSW pump strainer issue when the cause evaluation is complete. The inspectors considered that, while not a violation of regulatory requirements, this was an opportunity to identify an adverse trend in shear pin failures by the licensee. The licensee entered this issue into the CAP as NCR 1988423.

.3 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors conducted a detailed review of the following CRs:

CR 1945691, 1A reactor coolant recirculation pump #2 seal oscillations

CR 728556, Atrium-10 fuel assembly load chain failure event at Chinshan 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 CRs

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 Reports (LERs) 05000324/2015-003-00 and 2015-003-01, Oil

Leak Renders Residual Heat Removal Service Water System Pump Inoperable

a. Inspection Scope

On April 8, 2015, the licensee identified an oil leak on the motor for the 2C RHRSW pump in excess of the amount that would be acceptable for the pump to meet the 30-day mission time. This resulted in the inoperability of the Loop A RHRSW subsystem, and the loss of safety function while the Loop B RHRSW subsystem was out for maintenance. The licensee entered this issue in the CAP as NCR 742643. The inspectors reviewed the cause evaluation and the licensee event reports. Documents reviewed are listed in the Attachment.

b. Findings

A self-revealing NCV was documented in Section 1R19 of this report. No additional findings were identified during the review of these LERs. These LERs are closed.

.2 (Closed) LER 05000325;324/2015-002-01, Emergency Diesel Generator Loss of Safety

Function

a. Inspection Scope

On April 23, 2015, the licensee determined that during a period of 12 minutes on March 21, 2015, EDGs 3 and 4 could potentially have been unable to tie to their respective emergency busses. This was due to relays in breaker control logic that were susceptible to electrical noise that could have prevented the output breakers from closing under certain conditions. This was considered a loss of safety function of the onsite standby alternating current power source. The root cause was determined to be a procedural inadequacy in the commercial grade dedication process that allowed an unauthorized component modification to go unrecognized. The licensees corrective actions included installing a transient voltage suppressor across the RCR-X relays in all four EDGs. The inspectors reviewed the cause evaluation and the LER. Documents reviewed are listed in the Attachment.

b. Findings

One NRC-identified NCV was previously documented in NRC Inspection Report 05000325;324/2015007. No additional findings were identified. This LER is closed.

.3 (Closed) LER 05000325;324/2013-002-00, Fire Related Unanalyzed Condition that

Could Impact Equipment Credited in Safe Shutdown Analysis

a. Inspection Scope

On September 27, 2013, the licensee submitted an LER documenting the discovery of conditions of non-compliance with the sites fire protection program. These conditions could adversely affect components relied on to achieve safe shutdown condition during postulated fire events.

The inspectors reviewed documents, performed walk-downs, interviewed plant personnel, and assessed the licensees compensatory measures and corrective actions to determine their adequacy. The completion of the LER review was performed in the Region II office.

The initial review of the LER was documented in NRC Inspection Report 05000325;324/2014008. Documents reviewed are listed in the Attachment.

b. Findings

One finding was identified. This LER is closed.

Introduction:

The licensee identified a noncompliance of Units 1 and 2 TS 5.4.1, for failing to maintain adequate written procedures for combating plant fires in the reactor building north, reactor building south, and switchgear rooms located in the diesel generator building.

Description:

On July 29, 2013, the licensee identified credited fire safe shutdown equipment that could be adversely affected during postulated fire events. The deficiencies were identified while performing a circuit analysis review for the sites transition to the National Fire Protection Association Standard 805 (NFPA 805),

Performance-Based Standard for Fire Protection for Light-Water Reactor Electric Generating Plants. The licensee determined that the existing fire safe shutdown procedures were inadequate to mitigate the adverse consequences caused by a plant fire. These issues were applicable to Units 1 and 2, documented in LER 2013-002-00, dated September 27, 2013, and entered into the licensees CAP as NCRs 619341 and 93692. Upon discovery, the licensee implemented, or continued, hourly roving fire watches for the affected fire areas as compensatory measures.

The licensee identified that a fire event in the reactor building north (fire area RB-N) and reactor building south (fire area RB-S) for Units 1 and 2, could affect emergency bus control power circuits such that the under-voltage scheme would be adversely impacted.

A fire could prevent certain breakers from opening during load shedding. If the required breakers failed to open, this would prevent the emergency diesel generator load sequencing timer from being reset, which is necessary for powering certain safety-related loads from the emergency buses. The affected equipment included the residual heat removal pumps, which are credited for inventory control and decay heat removal, and the nuclear service water (NSW) and conventional service water (CSW)pumps, which are credited for cooling vital equipment. For an interim corrective action, the licensee proceduralized actions to ensure that applicable breakers were manually tripped to allow the emergency bus to be re-energized.

Additionally, the licensee identified that a fire event in the diesel generator building switchgear rooms (fire areas DG-07 and DG-08E) would result in the closure of fire dampers that would inhibit the operation of the ventilation system for adjoining spaces.

A fire in DG-07 would affect ventilation to DG-06 which includes the E5 switchgear room; and a fire in DG-08 would affect ventilation to DG-09 which includes the E8 switchgear room. The loss of ventilation would result in elevated room temperatures and potentially affect the availability and reliability of the credited emergency distribution bus. As a result, the licensee determined that proceduralized actions were required to direct the opening of exterior doors to ensure that environmental limits would not be exceeded.

Analysis:

The licensees failure to develop and maintain adequate fire safe shutdown procedures was a performance deficiency. This finding was more than minor because it was associated with the protection against external events (i.e., fire) attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because this issue relates to fire protection and this non-compliance was identified as a part of the sites transition to NFPA 805, this issue is being dispositioned in accordance with Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48), of the NRCs Enforcement Policy.

To verify that this non-compliance was not associated with a finding of high safety significance (Red), the following two SDP evaluations were performed by the inspectors and reviewed by a Region II senior risk analyst. The inspectors used guidance from NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process, and associated attachments.

(1) Concerning the diesel generator building switchgear room fire scenarios that could result in the loss of room ventilation, the inspectors qualitatively determined the risk significance to be Green (i.e., less than Red) because the plant would have been able to reach and maintain a stable plant condition within the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of a fire event (Phase 1 Worksheet, step 1.4.5.b). It was determined that the loss of room ventilation would not adversely affect the functionality of an emergency distribution bus during the initial stages of a fire event.

(2) Concerning reactor building fire scenarios that could damage control power cables such that residual heat removal pumps and/or NSW and CSW pumps would not be available, the inspectors determined that the finding required a Phase 2 Quantitative Screening at Question 1.4.5.B (IMC 0609, Appendix F, Attachment 1). The dominant sequence was a self-ignited cable fire.

Analysis assumptions included:

a) no credible fixed fire scenario identified during walk-downs b) no credible transient combustible fire scenario identified during walk-downs c) a one-year exposure period d) thermoplastic cable damage criteria e) conditional core damage probability of 1.0 with no recovery considered f) probability of non-suppression of 1.0 with no recovery considered g) medium probability of likelihood rating of 4.8E-4 for a self-ignited cable fire with a critical ignition zone weighting factor of 0.01 (IMC 0609, Appendix F, Attachment 4)

The bounding phase 2 analysis, at step 2.3.5 of the Phase 2 Worksheet, determined that the finding represented an increase in core damage frequency of less than 1E-4 (Red).

The inspectors determined that a cross-cutting aspect was not applicable to this noncompliance and that it met the criteria for enforcement discretion in accordance with Section 9.1 of the NRC Enforcement Policy.

Enforcement:

TS 5.4.1, states, in part, that written procedures shall be established, implemented, and maintained covering activities in Regulatory Guide 1.33 [Safety Guide 33], Appendix A, dated November 1972. Safety Guide 33, Section F.23, included plant fires as a listed procedure for combating emergencies and other significant events.

Contrary to the above, on July 29, 2013, the licensee identified that the site failed to adequately maintain written procedures for combating plant fires. Specifically, fire safe shutdown procedures did not include appropriate guidance to ensure the availability of credited equipment during fire events. This issue was entered into the licensees CAP as NCRs 619341 and 93692, and the licensee implemented hourly roving fire watches.

Because the licensee committed to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, Section 9.1, Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, this issue was identified and will be addressed during the licensees transition to NFPA 805, was entered into the licensees CAP, immediate corrective action and compensatory measures were taken. Additionally, this issue was not likely to have been previously identified by routine licensee efforts, was not willful, and was not associated with a finding of high safety significance (i.e., Red).

4OA5 Other Activities

.1 (Closed) Unresolved ltem (URl)05000324/2015002-04, 2C Residual Heat Removal

Service Water Pump Oil Leak

a. Inspection Scope

The inspectors completed a review of URI 05000324/2015002-04, 2C Residual Heat Removal Service Water Pump Oil Leak. On April 8, 2015, the licensee identified an oil leak on the motor for the 2C RHRSW pump in excess of the amount that would be acceptable for the pump to meet the 30-day mission time. This resulted in the inoperability of the Loop A RHRSW subsystem, and the loss of safety function while the Loop B RHRSW subsystem was out for maintenance. The licensee entered this issue in the CAP as NCR 742643. The licensees immediate corrective actions were to apply sealant to the mechanical joints of the bearing housings. The inspectors reviewed the cause evaluation. Documents reviewed are listed in the Attachment.

b. Findings

A self-revealing violation was documented in Section 1R19 of this report. This URI is closed.

.2 Groundwater Monitoring Program

On October 08, 2015, the inspectors held a teleconference with licensee staff to discuss the status of the groundwater monitoring program. The licensee provided an update on tritium concentrations in water collected from onsite and offsite groundwater and surface water sampling locations and discussed ongoing remediation efforts associated with the storm drain stabilization pond and areas near a Unit 1 condensate storage tank underground pipe leak. The licensee has installed a network of sub-surface pumping wells that continuously remove water from the affected areas; thereby reducing the overall tritium concentration in groundwater and limiting plume migration. Publicly available information regarding onsite groundwater monitoring and radionuclide concentrations in the environment near Brunswick Steam Electric Plant can be found in the Annual Radiological Environmental Operating Report. Recently issued reports can be found on the NRCs public website: http://www.nrc.gov/reactors/operating/ops-experience/tritium/plant-specific-reports/bru1-2.html.

4OA6 Meetings, Including Exit

On January 21, 2016, the resident inspectors presented the inspection results to Mr. William R. 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.

ATTACHMENT: