IR 05000456/2015004

NRC Integrated Inspection Report 05000456/2015004; 05000457/2015004

ML16033A476
Person / Time
Site:	Braidwood
Issue date:	02/02/2016
From:	Jandovitz J Region 3 Branch 3
To:	Bryan Hanson Exelon Generation Co, Exelon Nuclear
References
IR 2015004
Download: ML16033A476 (49)

Text

February 2, 2016

SUBJECT:

BRAIDWOOD STATION, UNITS 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000456/2015004; 05000457/2015004

Dear Mr. Hanson:

On December 31, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Braidwood Station, Units 1 and 2. On January 11, 2016, the NRC inspectors discussed the results of this inspection with Ms. M. Marchionda, Site Vice President, and other members of your staff. The inspectors documented the results of this inspection in the enclosed inspection report.

Based on the results of this inspection, two self-revealed findings of very-low safety significance (Green) were identified. The findings were determined to involve violations of NRC requirements. However, because of their very-low safety significance, and because the issues were entered into your Corrective Action Program, the NRC is treating these violations as Non-Cited Violations (NCVs), in accordance with Section 2.3.2 of the NRCs Enforcement Policy.

If you contest the subject or severity of the NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Braidwood Station. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS)

component of the 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/

John Jandovitz, Acting Chief Branch 3 Division of Reactor Projects

Docket Nos. 50-456; 50-457 License Nos. NPF-72; NPF-77

Enclosure:

IR 05000456/2015004; 05000457/2015004

REGION III==

Docket Nos:

50-456; 50-457 License Nos:

NPF-72; NPF-77 Report No:

05000456/2015004; 05000457/2015004 Licensee:

Exelon Generation Company, LLC Facility:

Braidwood Station, Units 1 and 2 Location:

Braceville, IL Dates:

October 1 through December 31, 2015 Inspectors:

J. Benjamin, Senior Resident Inspector

D. Betancourt, Resident Inspector

T. Bilik, Senior Reactor Inspector

B. Boston, Reactor Inspector

J. Bozga, Reactor Inspector

G. Edwards, Health Physicist

M. Garza, Emergency Preparedness Inspector

T. Go, Health Physicist

C. Hunt, Reactor Inspector

D. McNeil, Senior Operations Engineer

D. Reeser, Operations Engineer Approved by:

J. Jandovitz, Acting Chief Branch 3 Division of Reactor Projects

SUMMARY

Inspection Report 05000456/2015004; 05000457/2015004; 10/01/2015 - 12/31/2015;

Braidwood Station, Units 1 & 2; Outage Activities.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were self-revealed.

The findings were considered Non-Cited Violations (NCVs) of U.S. Nuclear Regulatory Commission (NRC) regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated April 29, 2015. Cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated February 4, 2015.

The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, dated February 2014.

Cornerstone: Initiating Events

Green.

A finding of very low safety significance and an associated NCV of Technical Specification 5.4.1, Procedures, was self-revealed on October 5, 2015, due to the licensees failure to establish and maintain adequate guidance for operating the Unit 1 and Unit 2 motor driven main feedwater pump (MDFWP) during plant shutdown conditions. Specifically, on October 4, 2015, during a Unit 2 plant shutdown, the Unit 2 MDFWP was placed in service at low forward feedwater flow conditions and was manually tripped when the pumps main journal bearing temperature exceeded the procedural limit. Subsequent review, determined that the procedural limit was too low as previously recognized by historic station specific operating experience. This issue was entered into the licensees corrective action program (CAP) as Issue Report (IR) 2565486.

The inspectors determined that the performance deficiency was more than minor because the issue was associated with the Procedural Quality attribute of the Initiating Event cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the performance deficiency contributed to a loss of main feedwater event that upset plant stability and challenged the critical safety function of removing decay heat via the steam generators in Mode 3. For Unit 1, the increased potential for a loss of main feedwater event existed under similar conditions.

The inspectors determined that the finding was of very low safety significance based upon a detailed risk evaluation. The inspectors concluded that this finding did not have a cross-cutting aspect because the performance deficiency was greater than 3 years old and, therefore, not indicative of recent performance. (Section 1R20.1b(2))

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and an associated NCV of Technical Specification 5.4.1, Procedures, was self-revealed on October 5, 2015, due to the licensees failure to establish a written procedure for combating emergencies and other significant events, as required by Regulatory Guide 1.33, Quality Assurance Program Requirements. Specifically, upon a loss of feedwater in Mode 3 (Hot Standby), which is an expected design and licensing basis event, the licensee did not have a written procedure as established by the Regulatory Guide. This issue was entered into the licensees CAP as IRs 2566239 and 2565513.

The inspectors determined the finding to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," dated September 7, 2012, because, it was associated with the Mitigating Systems cornerstone Procedural Quality attribute, and adversely impacted the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the absence of a procedure(s)complicated the operator response to the loss of feedwater event in Mode 3. The inspectors determined the finding to be of very low safety significance in accordance with IMC 0609, Appendix A, The SDP for Findings at Power, dated September 7, 2012,

Exhibit 2, since the inspectors answered "No" to the Mitigating Systems questions under Section A, Mitigating Systems, Structures, and Components and Functionality. The inspectors did not identify a cross-cutting aspect associated with this finding, because it was confirmed not to be reflective of current performance due to the age of the performance deficiency. (Section 1R20.1b(3))

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power for the entire inspection period with one exception.

On November 14, 2015, reactor power was lowered to approximately 82 percent to perform main turbine valve testing. The reactor was returned to full power the following day.

Unit 2 operated at or near full power for the entire inspection period with one exception.

On October 5, 2015, the unit was shut down for a planned refueling outage. The unit was restarted on October 23, 2015, and reached full power on October 26,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures.

Documents reviewed are listed in the Attachment. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

• intake structure trash rake and screen wash systems; and

• refueling water storage tank.

This inspection constituted one winter seasonal readiness preparations sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• Unit 2 4kV electrical bus 242 while bus 241 was out-of-service for planned maintenance;

• spent fuel pool cooling systems following Unit 2 core offload and associated refueling activities; and

• Unit 2 motor driven and diesel driven auxiliary feed water (FW) systems following plant startup to Mode 3.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), issue reports (IRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization.

Documents reviewed are listed in the Attachment.

These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Unit 2 auxiliary building electrical division 21 engineered safety feature switchgear room;

• Unit 2 auxiliary building electrical division 22 engineered safety feature switchgear room; and

• 1A emergency diesel generator and day tank rooms.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

These activities constituted three quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the

. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant area to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• diesel oil storage tank rooms and sump check valves.

This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

.2 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits, were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground bunkers/manholes subject to flooding:

• groundwater intrusion in turbine building cable vault.

Specific documents reviewed during this inspection are listed in the Attachment.

This inspection constituted one underground cable routing area sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From October 5 - 16, 2015, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant (RC) system, steam generator (SG) tubes, emergency FW systems, risk-significant piping and components, and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, R08.3, IR08.4, and 1R08.5 below constituted one ISI sample as defined in IP 71111.08.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors either observed or reviewed the following non-destructive examinations (NDEs) mandated by the American Society of Mechanical Engineers (ASME)Section XI Code, to evaluate compliance with the ASME Code Section XI, and Section V requirements, and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an U.S. Nuclear Regulatory Commission (NRC)-approved alternative requirement.

• Ultrasonic (UT) examination of auxiliary FW pipe-to-elbow welds 2AF-05-06 and 2AF-05-07;

• UT of pipe-to-elbow weld, 16 FW weld, 2FW-02-17;

• UT of elbow-to-pipe weld, 16 FW weld, 2FW-02-18;

• UT of pipe-to-elbow weld, 6 safety injection weld, 2SI-02-41;

• UT of elbow-to-pipe weld, 6 SI weld, 2SI-02-42;

• UT of elbow-to-tee weld, 12 RC weld, 2SI-02-46;

• UT of pipe-to-elbow, 6 RC weld, 2RC-11-15;

• UT of pipe-to-elbow, 6 RC weld, 2SI-02-41;

• UT of pipe-to-elbow, 16 FW weld, 2FW-04-19;

• Visual examination (VT-3) of SI strut 2SI01013R, 2SI03021R, and 2SI21001R;

• VT-3 of strut 2RH02029R;

• VT-3 of essential service water strut 2SX09119X;

• VT-3 of essential service water strut 2SX09044X; and

• VT-3 of snubber supports 2MS01074BS, 2MS01092BS and 2MS01092AS.

The inspectors reviewed the following examination completed during the previous outage with relevant/recordable conditions/indications accepted for continued service to determine if acceptance was in accordance with the ASME Code Section XI, or an NRC-approved alternative.

• Indication, radiographic examination rejected on Diverse and Flexible Coping Strategies (FLEX) piping shop weld (WO 1692238-10).

The inspectors either observed or reviewed the following pressure boundary welds completed for risk-significant systems since the beginning of the last refuelling outage to determine if the licensee applied the pre-service NDEs, and acceptance criteria required by the Construction Code and ASME Code,Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code Section IX.

• modify support of Class 2 boric acid safety 2AB23B044X per WO 1662830-07;

• FLEX mod cross connection, 8 o-let to 36 elbow, 2SX02AB, per WO 1722811-41; and

• FLEX mod installation/repair of 4 SI system piping weld #2 (2SI03AB) per WO 1692238-10.

b. Findings

No findings were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

A bare metal visual (BMV) examination was required this outage pursuant to Title 10, Code of Federal Regulations (10 CFR), Part 50.55a(g)(6)(ii)(D).

The inspectors reviewed a CD of the BMV examination conducted on the reactor vessel head at each of the penetration nozzles to determine whether the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). Specifically, to determine:

• if the required VT scope/coverage was achieved and limitations (if applicable were recorded), in accordance with the licensee procedures;

• if the licensee criteria for VT quality and instructions for resolving interference and masking issues were adequate; and

• for indications of potential through-wall leakage, that the licensee entered the condition into the corrective action system and implemented appropriate corrective actions.

A non-visual inspection of the reactor vessel head penetrations was not required this outage. Therefore, no NRC review was completed for this inspection procedure attribute.

The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors performed an independent walkdown of the RC system and related lines in the containment, which had received a recent licensee boric acid walkdown, and verified whether the licensees boric acid corrosion control VTs emphasized locations where boric acid leaks can cause degradation of safety significant components.

The inspectors reviewed the following licensee evaluations of RC system components with boric acid deposits to determine if degraded components were documented in the CAP. The inspectors also evaluated corrective actions for any degraded RC system components to determine if they met the ASME Section XI Code.

• 2CV844; boric acid at bolted connection and;

• 2PS9350B; boric acid at bolted connection.

The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.

• IR 1659448; Corrosion at Flange, 2FE-0428;

• IR 1655470; OSP-A Dry Boric Acid Leakage 2SI30D023G Flange; and

• IR 1655585; OSP-A Dry Boric Acid at the Bolted Connection to 2RE01T.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

No exams were required this outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI/SG-related problems entered into the licensees CAP, and conducted interviews with licensee staff to determine if:

• the licensee had established an appropriate threshold for identifying ISI/SG-related problems;

• the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

• the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On November 12, 2015, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training. The inspectors verified that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• the ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• the ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

Performance in these areas was compared to pre-established operator action expectations, procedural compliance, and task completion requirements.

Documents reviewed are listed in the Attachment.

This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk

(71111.11Q)

a. Inspection Scope

On October 5, 2015, the inspectors observed control room operators response to a loss of feedwater event in Mode 3. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms (if applicable);

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

Performance in these areas was compared to pre-established operator action expectations, procedural compliance, and task completion requirements.

Documents reviewed are listed in the Attachment.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• Unit 1 essential service water system;

• Maintenance Rule Periodic (a)(3) assessment; and

• Unit 2 residual heat removal (RHR) system.

The inspectors reviewed events including those in which ineffective equipment maintenance resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment.

This inspection constituted three quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Planned Yellow risk configuration: Unit 1;

• Unplanned Orange risk configuration: failure of the Unit 2 shutdown cooling heat exchanger outlet valve (2RH606) to open during reduced inventory;

• Planned Yellow risk configuration: Unit 2 reduced RCS inventory operations during head removal and installation;

• Planned Yellow risk configuration: safety-related 4kV bus 241 outage;

• emergent work: manual trip of 1B turbine drive FW pump due to flow oscillations on December 4, 2015; and

• emergent work: availability of essential service water during repair of the 0SXH2AA-6 common drain line.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4), and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Documents reviewed during this inspection are listed in the Attachment.

These maintenance risk assessments and emergent work control activities constituted six samples as defined in IP 71111.13-05.

b. Findings

Unresolved Item: Loss of Shutdown Cooling Train during Refueling Cavity Fill and Associated Reduced Inventory Operations

Introduction:

On October 8, 2015, the inspectors identified an Unresolved Item (URI)regarding the failure of valve 2RH606, which is the 2A RHR heat exchanger flow control valve. The valves failure to open caused a loss of one train of shutdown cooling, and an unplanned Orange risk configuration with Unit 2 in Mode 6, and the reactor refueling cavity level less than 23 feet above the vessel flange. At the closure of the inspection period, the licensees investigation on the cause of the failure was ongoing. Resolution of this issue will be based on the inspectors review of the licensees completed investigation.

Description:

A function of the RHR system in Mode 6 is to remove decay heat and sensible heat from the reactor coolant system (RCS). Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchangers where the heat is transferred to the component cooling water system. The coolant is then returned to the RCS via the RCS cold legs.

On October 8, 2015, valve 2RH606 became mechanically bound while in the process of filling the Unit 2 reactor refueling cavity to greater than 23 feet. This was identified when the operators attempted to open the valve from the control room. The failure of the valve to open caused Unit 2 shutdown risk to change from a planned Yellow configuration to unplanned Orange condition. Additionally, the licensee entered Limiting Condition for Operation 3.9.6, Residual Heat Removal and Coolant Recirculation-Low Water Level, Condition A, for one train of RHR cooling inoperable. This action required the licensee to initiate actions immediately to either restore the affected RHR loop to operable status or to initiate actions to establish greater than or equal to 23 feet of water above the reactor vessel flange. The licensee accomplished this action by raising water level in the cavity to greater than 23 feet.

Troubleshooting of the failed valve revealed that a shaft key sheared, which prevented the valve from opening. The valve had been previously manipulated during the outage without an issue. The malfunctioning part was sent offsite for failure analysis. The valve was repaired. At the conclusion of the inspection, an apparent cause investigation was in process. This URI will remain open until the investigation is complete and the inspectors review the report to determine whether a performance deficiency exists.

(URI 05000457/2015004-01; Loss of Shutdown Cooling Train During Refueling Cavity Fill and Associated Reduced Inventory Operations)

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Operability Evaluation 2015-005, RCS cooldown analysis with increased component cooling water temperature;

• Operability Evaluation 2015-006, excessive seat leakage through the 1A essential service water pump discharge check valve;

• diesel oil storage tank fill capability to the diesel driven auxiliary feedwater system day tank; and

• heavy external corrosion on common unit common essential service water drain line 0SXH2AA-6.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the

.

This operability inspection constituted four samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

.2 Annual Sample:

Review of Operator Workarounds

a. Inspection Scope

The inspectors reviewed the following issue:

• extraction steam valve 1ES004 packing leak.

The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of operator workarounds (OWAs)on system availability and the potential for improper operation of the system, for potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents.

The inspectors performed a review of the cumulative effects of OWAs. The documents listed in the Attachment were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their CAP and proposed or implemented appropriate and timely corrective actions which addressed each issue. Reviews were conducted to determine if any operator challenge could increase the possibility of an Initiating Event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of Mitigating Systems, impaired access to equipment, or required equipment uses for which the equipment was not designed.

Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds.

This review constituted one operator workaround annual inspection sample as defined in IP 71115-02.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification:

• Unit common essential service water 0SXH2AA-6 drain line repair.

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not adversely affect the operability or availability of the safety-related essential service water system. The inspectors observed ongoing and completed work activities to ensure that the modification was installed as directed and consistent with the design control documents; the modification was installed and operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modification did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with licensee staff to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed are listed in the

.

This inspection constituted one modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• Unit 2 startup feedwater pump phase A overcurrent trip (WO 01866639);

• 2A FW pump inboard journal bearing greater than 200 degrees Fahrenheit (WO 01662678);

• 2C reactor coolant pump labyrinth seal tolerance out of spec (IR 2571030);

• 2A RC pump coupling alignment out-of-tolerance 0.001 (IR 2570482);

• Unit 2 containment isolation valve (CIV) 2FP010 failed post maintenance testing (WO 01723328);

• Unit 2 essential service water valve 2SX143B preventative maintenance (WO 01751593); and

• Unit 2 component cooling water valve 2CC9486 corrective maintenance (WO 01611951).

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

whether the effect of testing on the plant had been adequately addressed; whether testing was adequate for the maintenance performed; whether acceptance criteria were clear and demonstrated operational readiness; whether test instrumentation was appropriate; whether tests were performed as written in accordance with properly reviewed and approved procedures; whether equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and whether test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment.

This inspection constituted seven post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 2 refueling outage (RFO), conducted October 4 - 26, 2015, 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. During the RFO, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below:

• licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TS 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 RC 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 OSP 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;

• licensee fatigue management, as required by 10 CFR 26, Subpart I;

• refueling activities, including fuel handling and sipping to detect fuel assembly leakage;

• 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; and

• licensee identification and resolution of problems related to RFO activities.

Documents reviewed are listed in the Attachment.

This inspection constituted one RFO sample as defined in IP 71111.20-05.

b. Findings

(1) Failure of the Startup Feedwater Pump to Start during Unit 2 Plant Shutdown

Introduction:

The inspectors identified an URI based upon the startup feedwater pumps (SUFWPs) failure to start during a plant shutdown. In addition to being used in plant startups and shutdowns, the SUFWP is also credited in the licensees emergency operating procedure as a means to add water to the steam generators for decay heat removal if the safety-related auxiliary feedwater systems failed to function properly during an event.

Description:

On October 4, 2015, operations attempted to start the Unit 2 SUFWP at low power in Mode 1 during plant shutdown activities for a refueling outage. Upon start, the SUFWP automatically tripped. The licensee completed an apparent cause evaluation to determine the reason why the pump did not start and run.

At the end of the inspection period, the inspectors were awaiting additional information to complete their review to determine if this issue of concern constituted a performance deficiency. This URI will remain open pending this review. (URI 05000457/2015004-02, Failure of the Startup Feedwater Pump to Start During a Plant Shutdown)

(2) Failure to Establish Adequate Operational Functional Guidance for the Motor Driven Main Feedwater Pump During a Normal Plant Shutdown

Introduction:

A finding of very low safety significance and an associated Non-Cited Violation (NCV) of TS 5.4.1, Procedures, was self-revealed on October 5, 2015, due to the licensees failure to establish and maintain adequate guidance for operating the Unit 1 and Unit 2 MDFWP during plant shutdown conditions. As a result, on October 4, 2015, during a Unit 2 plant shutdown, the Unit 2 MDFWP was placed in service at low forward feedwater flow conditions and was manually tripped when the pumps main journal bearing temperature exceeded the procedural limit. Subsequent review, determined that the procedural limit was too low as previously recognized by historic station specific operating experience.

Description:

On October 4, 2015, operations attempted to start the Unit 2 SUFWP at low power in Mode 1 during plant shutdown activities for a refueling outage. Upon start, the SUFWP automatically tripped. The cause for the pump not starting is still under inspector review (Reference: Unresolved Item 05000456/2015004-02).

Operations subsequently started the Unit 2 MDFWP to provide feedwater flow to the steam generators. Operations manually tripped the MDFWP approximately forty minutes into operation due to the pumps inboard journal bearing temperature approaching the procedural limit of 200 degrees F.

Upon tripping the only available main feedwater pump, auxiliary feedwater automatically initiated on low steam generator water level conditions. (Note: Braidwood does not use the two turbine driven feedwater pumps for plant shutdowns). Both auxiliary feedwater pumps operated adequately during the transient and were able to effectively restore steam generator water level until secondary plant pressure was reduced low enough to allow the condensate/condensate booster pumps to provide water to the generators.

The licensee entered the SUFWP and MDFWP issues into the CAP and performed a common apparent cause investigation regarding the SUFWPs failure to start and the MDFWPs failure to run.

The licensee determined that the there was no apparent cause for the elevated MDFWP journal bearing temperatures when operating the pump in low forward flow conditions but, to the contrary, it was expected. Specifically, the licensee had previously determined that hotter bearing temperatures are expected to occur at low feedwater forward flow conditions based upon the effect that cooler water temperatures from higher recirculation flow has on bearing loading. The licensee had previously concluded that these cooler water temperatures resulted in a pump, gearbox, and motor alignment different than when the pump was operated at higher flow conditions. Furthermore, the licensee had determined that the elevated bearing temperatures were acceptable. The station identified that these higher bearing temperatures had been observed before during periods of low flow operations (In 1998, Braidwood Unit 2 operated for a period of time at low power, running the MDFWP on recirculation and pump journal bearing temperature reached 210 degrees F for 12 minutes and remained above 200 degrees F for 53 minutes without any adverse condition noted). Additionally, the licensees startup procedure (BwOP FW-8) permitted a maximum MDFWP journal bearing temperature of 225 degrees F.

The licensee entered this issue into the CAP as IR 2565486. Corrective action consisted of an assessment of the MDFWP bearing for bearing and journal damage, performing an apparent causal evaluation, and updating the plant shutdown procedure to reflect the allowable higher operating limit.

Analysis:

The inspectors determined that the failure to have adequate operational guidance for the MDFWP during a normal plant shutdown was a violation of TS 5.4.1 and a performance deficiency. Specifically, the licensee had historically understood that higher journal bearing temperatures could be expected during low MDFWP forward flow conditions but had failed to retain this knowledge and capture it within the appropriate procedures used for shutting down the plant.

The inspectors determined that the performance deficiency was more than minor and associated with both Unit 1 and Unit 2 in accordance with Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, dated September 7, 2012 because the issue was associated with the Procedural Quality attribute of the Initiating Event cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the performance deficiency contributed to a loss of main feedwater event that upset plant stability and challenge the critical safety function of removing decay heat via the SGs in Mode 3. For Unit 1, the increased potential for a loss of main feedwater event existed under similar conditions.

The inspectors determined that the safety consequences for the performance deficiency could be evaluated using IMC 0609, Significant Determination Process, and IMC 0609 Appendix A, Significance Determination Process for at Power Findings, dated June 19, 2012. The inspectors determined that the finding required a detailed risk evaluation because the finding was associated with post reactor trip conditions and resulted in a loss of main feedwater to the steam generators.

To evaluate the risk significance of the finding, the Senior Reactor Analyst used the Braidwood Standardized Plant Analysis Risk model version 8.24 and the Systems Analysis Programs for Hands-on Integrated Reliability Evaluations version 8.1.2 software.

A Transient initiating event was used to model a Reactor Trip. The initiating event frequency (IEF) of a Transient initiating event is 6.9E-1/yr per the Standardized Plant Analysis Risk model. For the Degraded Case, the Conditional Core Damage Probability (CCDP) of a Transient initiating event with a failure-to-run of the MDFWP while the reactor is in Mode 3 (i.e., a non-Anticipated Transient Without Scram event is 4.16E-7.

For the Base Case, the CCDP of a Transient initiating event while the reactor is in Mode 3 is 3.64E-7. The delta CCDP (CCDP) is the difference between the CCDP for the Degraded Case and the CCDP for the Base Case or 5.2E-8 (i.e., CCDP = 4.16E-7 - 3.64E-7 = 5.2E-8).

An estimate of the delta core damage frequency (CDF) due to the performance deficiency is obtained by multiplying the IEF of the event (6.9E-1/yr) times the CCDP if the initiating event were to occur (5.2E-8). The result is an estimated CDF of 3.6E-8/yr.

The dominant sequence was a transient initiating event with the failure of the auxiliary FW system, failure of main FW, and the failure of feed and bleed.

Based on the detailed risk evaluation, the inspectors determined that the finding was of very low safety-significance (Green).

The inspectors concluded that this finding did not have a cross-cutting aspect because the performance deficiency was greater than three years old and, therefore, not indicative of recent performance.

Enforcement:

Technical Specification 5.4.1 requires, in part, that written procedures shall be established, implemented, and maintained covering the activities in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, dated February 1978. RG 1.33, Appendix A, dated February 1978, Section 4, specifies procedures startup, operation, and shutdown for systems including the feedwater water systems (i.e. Section 4.k).

Contrary to the above, prior to October 4, 2015, the licensee had not established, implemented, and maintained procedures for operation of the MDFWP during plant shutdown conditions and associated changes in modes of operations. Specifically, station procedures were determined to be the direct cause or the MDFWP failure to run during a plant shutdown which resulted in an unnecessary start of the engineered safeguard featured auxiliary feedwater system to maintain core decay heat removal capability. This violation was determined to be applicable to both Braidwood Unit 1 and Unit 2 because the violation existed in both units. Because this violation was of very low safety significance, and was entered into the licensees CAP, as IR 2565442, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000456/2015004-03; 05000457/2015004-03, Failure to Establish Adequate Feedwater Pump Operational Guidance during a Normal Plant Shutdown).

(3) Failure to Establish a Written Procedure for a Loss of Feedwater Event in Mode 3

Introduction:

A finding of very low safety significance and an associated NCV of Technical Specification 5.4.1 Procedures, was self-revealed on October 5, 2015, due to the licensees failure to establish a written procedure for combating emergencies and other significant events, as required by RG 1.33 Quality Assurance Program Requirements. Specifically, upon a loss of feedwater in Mode 3 (Hot Standby), which is an expected design and licensing basis event, the licensee did not have a written procedure for combating the event as established by the RG.

Description:

During the planned down power for entry into refueling outage A2R18, on October 4, 2015, the Unit 2 SUFWP pump failed to start at approximately low power.

The SUFWP is a 5300 gallons per minute (gpm) non-safety pump, which is the normal source of feedwater during unit startup and shutdown. As a result of the unavailability of the SUFWP, the 2A MDFWP was manually started to supply feedwater to the Unit 2 steam generators for decay heat removal and cooldown.

Unit 2 entered Mode 3 at midnight [CDT], on October 5, 2015. At 12:38 a.m. [CDT],

the 2A MDFWP was manually secured due to pump inboard journal bearing temperature exceeding its 200 degree°F operating limit listed in the shutdown procedure.

Consequently, a loss of feedwater event occurred in Mode 3. As operators responded, they referenced 2BwOA SEC-1, Secondary Pump Trip, and BwOP AF-11, Filling the Steam Generators Utilizing the Motor Driven Auxiliary Feedwater Pump A. However, 2BwOA SEC-1 did not contain steps that adequately covered a total loss of a feedwater while the reactor was non-critical and in Mode 3. Additionally, BwOP AF-11 outlined the steps necessary to fill the SGs utilizing the MDFWP when in Modes 4, 5, 6, or defueled, but did not cover Mode 3 operation.

Using the above mentioned procedures as reference, the operators responded to this event by reducing steam generator blowdown and attempting to raise condensate booster system discharge flow in an effort to provide flow into the steam generators.

Additionally, the operators established a critical parameter of 40 percent steam generator level to establish flow to the generators from the auxiliary feedwater pumps.

However, at the time of the event the operators did not immediately recognize that the ongoing plant cooldown had not sufficiently reduced pressure such that the condensate booster pumps had the ability to feed the steam generators before the SG low-2 water level (36.3 percent) was reached. Additionally, it was not recognized that the critical parameter of 40 percent steam generator level was too close to the SG low-2 level, and, with the 1 percent per minute inventory loss in the steam generator, did not allow for the manual start of the 2A or 2B auxiliary feedwater pump prior to the emergency signal initiation.

At 1:05 a.m. [CDT], an automatic auxiliary feedwater safety actuation signal was generated on SG low-2 level (36.3 percent) and both the 2A and 2B auxiliary feedwater pumps auto-started. An additional reactor protection system reactor trip signal was received due to the SG low-2 level (36.3 percent) with the reactor not critical. Both auxiliary feedwater trains operated as designed.

Based on the information presented above, the licensees investigation concluded that there were two apparent causes for the event. The first apparent cause was that the critical parameter initially selected was not appropriate given the plant conditions and it was not revised, reevaluated, or challenged as the event progressed to ensure that the actions necessary to start the auxiliary feedwater pump could be completed in the available time. The second apparent cause was that the absence of procedure guidance delayed the crews response by requiring the crew to operate in knowledge space and adapt procedures while responding to the event. The inspectors reviewed the results of the investigation and did not identify any further concerns.

The licensee entered this issue into the CAP as IRs 2566239, and 2565513. Corrective actions for this event included revising procedures to include guidance in existing procedures for a loss of a feed pump and/or a complete loss of feed when the reactor is not critical.

Analysis:

The inspectors determined that the failure to establish a procedure for combating a loss of feedwater event in Mode 3, as required by RG 1.33, Section 6, was a performance deficiency that warranted a significance determination. Specifically, on October 4, 2015, the licensee experienced a loss of feedwater event while in Mode 3, which was not covered by a written procedure as specified in RG 1.33, Section 6.j.

The performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," dated September 7, 2012, because it was associated with the Mitigating Systems cornerstone Procedural Quality attribute, and adversely impacted the cornerstones objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the absence of a procedure(s) complicated the operator response to the loss of feedwater event in Mode 3. The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609 Appendix A, The Significance Determination Process for Findings at Power, Exhibit 2 for the Mitigating Systems Cornerstone, dated June 19, 2012. The inspectors answered "No" to the Mitigating Systems questions under Section A, Mitigating Systems, Structures, and Components and Functionality and screened the finding as having very low safety significance (Green).

The inspectors did not identify a cross-cutting aspect associated with this finding because it was confirmed not to be reflective of current performance due to the age of the performance deficiency.

Enforcement:

Technical Specification 5.4.1 requires that written procedures shall be established, implemented, and maintained covering the activities in RG 1.33, Revision 2, Appendix A, dated February 1978. Regulatory Guide 1.33, Appendix A, Section 6, specifies procedures for combating emergencies and other significant events, including a loss of feedwater or feedwater system failure.

Contrary to the above, prior to October 5, 2015, the licensee did not have a procedure to cover the loss of feedwater event during Mode 3. Specifically, the design and licensing basis of the plant was the loss of feedwater event in Modes 1, 2 and 3. Conversely, the operators had to reference two separate procedures to address the loss of feedwater event that occurred on October 4, 2015, which complicated and impacted the operations crews response to changing plant conditions during this transient. Because this violation was of very low safety significance, and was entered into the licensees CAP as IRs 2566239 and 2565513, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000456/2015004-04; 05000457/

2015004-04, Failure to Establish a Written Procedure for a Loss of Feedwater Event in Mode 3).

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• Unit 2 main steam safety valve testing (Routine);

• Unit 2 auxiliary feedwater full flow testing (Routine);

• Unit 1 residual heat removal train A quarterly valve stroke (Routine); and

• Unit 2 instrument air CIV local leak rate test.

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• were acceptance criteria clearly stated, sufficient to demonstrate operational readiness, and consistent with the system design basis;

• was plant equipment calibration correct, accurate, and properly documented;

• were as-left setpoints within required ranges; and was the calibration frequency in accordance with TSs, the UFSAR, plant procedures, and applicable commitments;

• was measuring and test equipment calibration current;

• was the test equipment used within the required range and accuracy and were applicable prerequisites described in the test procedures satisfied;

• did test frequencies meet TS requirements to demonstrate operability and reliability;

• were tests performed in accordance with the test procedures and other applicable procedures;

• were jumpers and lifted leads controlled and restored where used;

• were test data and results accurate, complete, within limits, and valid;

• was test equipment removed following testing;

• where applicable for inservice testing activities, was testing performed in accordance with the applicable version of Section XI of the ASME Code, and were reference values consistent with the system design basis;

• was the unavailability of the tested equipment appropriately considered in the performance indicator data;

• where applicable, were test results not meeting acceptance criteria addressed with an adequate operability evaluation, or was the system or component declared inoperable;

• where applicable for safety-related instrument control surveillance tests, was the reference setting data accurately incorporated into the test procedure;

• was equipment returned to a position or status required to support the performance of its safety function following testing;

• were all problems identified during the testing appropriately documented and dispositioned in the licensees CAP;

• where applicable, were annunciators and other alarms demonstrated to be functional and were annunciator and alarm setpoints consistent with design documents; and

• where applicable, were alarm response procedure entry points and actions consistent with the plant design and licensing documents.

Documents reviewed are listed in the Attachment.

This inspection constituted three routine surveillance testing samples, and one CIV as defined in IP 71111.22, Sections -02 and -05.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The regional inspectors performed an in-office review of the latest revisions to the Emergency Plan, Emergency Action Levels and Emergency Action Level Bases document to determine if these changes decreased the effectiveness of the Emergency Plan. The inspectors also performed a review of the licensees 10 CFR 50.54(q) change process, and Emergency Plan change documentation to ensure proper implementation for maintaining Emergency Plan integrity.

The NRC review was not documented in a Safety Evaluation Report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment.

This Emergency Action Level and Emergency Plan Change inspection constituted one sample as defined in IP 71114.04-06.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on November 12, 2015, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the technical support center and main control room to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the Corrective Action Program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

The inspection activities supplement those documented in IR 05000456/2015002; IR 05000457/2015002, and constitute one complete sample as defined in IP 71124.01-05.

.1 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors selected several sealed sources from the licensees inventory records, and assessed whether the sources were accounted for and verified to be intact.

The inspectors evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b. Findings

No findings were identified.

.2 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients.

The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials (i.e., nonfuel) stored within spent fuel and other storage pools. The inspectors assessed whether appropriate controls (i.e., administrative and physical controls) were in place to preclude inadvertent removal of these materials from the pool.

b. Findings

No findings were identified.

2RS2 Occupational As-Low-As-Reasonably-Achievable Planning and Controls

The inspection activities supplement those documented in IR 05000456/2014003; IR 05000457/2014003 and IR 05000456/2015002; IR 05000457/2015002, and constitute one complete sample as defined in IP 71124.02-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed pertinent information regarding plant collective exposure history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants 3-year rolling average collective exposure.

b. Findings

No findings were identified.

.2 Radiological Work Planning (02.02)

a. Inspection Scope

The inspectors selected the following work activities of the highest exposure significance.

• Radiation Work Permit (RWP)-10017293; A2R18 Radiography on Fukushima Flex Mod. Piping in the Auxiliary Building;

• RWP-10017333; A2R18 Reactor Cavity Decontamination with Added Controls;

• RWP-10017801; A2R18 SG Bowl Drain Replacement Project; and

• RWP-10017322; A2R18 Reactor Head Disassembly and Reassembly.

The inspectors compared the results achieved (dose rate reductions and person-rem used) with the intended dose established in the licensees as-low-as-reasonably achievable (ALARA) planning for these work activities. The inspectors compared the person-hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements, and evaluated the accuracy of these time estimates. The inspectors assessed the reasons (e.g., failure to adequately plan the activity and failure to provide sufficient work controls) for any inconsistencies between intended and actual work activity doses.

The inspectors determined whether post-job reviews were conducted and if identified problems were entered into the licensees CAP.

b. Findings

No findings were identified.

.3 Problem Identification and Resolution (02.06)

a. Inspection Scope

The inspectors evaluated whether problems associated with ALARA planning and controls are being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security

4OA1 Performance Indicator Verification

.1 Unplanned Transients per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients per 7000 Critical Hours (1E03) performance for Braidwood Unit 1 and Unit 2 for the period from the 1st quarter 2015 through the 4th quarter 2015. To determine the accuracy of the Performance Indicator (PI) data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, IRs, maintenance rule records, event reports and NRC Integrated Inspection Reports for the period of January 1 through December 31, 2015, to validate the accuracy of the submittals. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment.

This inspection constituted two unplanned transients per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system (RCS)

Leakage (B102) performance for Braidwood Unit 1 and Unit 2 for the period from the 3rd quarter 2014 through the 3rd quarter 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, RCS leakage tracking data, IRs, event reports and NRC Integrated Inspection Reports for the period of July 1, 2014 through September 30, 2015, to validate the accuracy of the submittals. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment.

This inspection constituted two RCS leakage samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue.

The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of July 1, 2015, through December 5, 2015, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Follow-Up Inspection: Essential Service Water System Leaks

a. Inspection Scope

On May 29, 2015, the licensee documented in IR 2507433 that recent issues with through wall leaks have resulted in numerous limited condition of operation (LCO)entries, equipment unavailability, and emergent repairs. Examples of the leaks included two pinhole leaks from the essential service water system raw water piping that resulted in LCO entries, which affected the 1A emergency diesel generator, and the Unit 1 component cooling water heat exchanger. Additionally, a pinhole leak occurred in the essential service water supply to the auxiliary feedwater system. As a results of these issues, the licensee developed a plan to review susceptible areas of the system to ensure piping required for the repairs was available.

During this inspection period, the inspectors reviewed the licensees plan to address essential service water pipe leaks, reviewed applicable IRs, and conducted meetings with engineering personnel.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

No findings were identified. As described above, due, in part, to three essential service water system leaks occurring since May 2014, the licensee documented in IR 2507433 the licensees corrective action to develop an action plan to address mitigating actions for potential future leaks. The causes for the leaks that had been recently identified included: localized corrosion downstream of throttle valves, and microbiological induced corrosion.

The action plan developed by the licensee included:

(1) identifying all butterfly valves in the essential service water system that are used to throttle flow, and create plans to inspect piping or fittings downstream of the essential service water throttle valves; (2)reviewing the list of essential service water throttle valves to determine susceptibility to cavitation and develop an inspection plan to identify if cavitation is occurring;

(3) create IRs to inspect flanges where cavitation may be occurring to determine if the areas are degrading;

(4) develop a list of piping that is not isolable from the main essential service water system that would result in a short term unplanned LCO action statement entry;

(5) review the list of piping areas that are not isolable from the main essential service water system for which code cases would not be applicable if a leak were to occur; and

(6) plan for contingency material to be available for non-isolable essential service water piping.

Based on all the information previously provided the inspectors were concerned that, even though the licensee had been preparing on how to deal with leaks once they developed, the inspectors were not aware of preventive measures. The inspectors shared these concerns with licensee personnel. The licensee provided the inspectors their planned actions to inspect piping or fittings downstream of the essential service water throttle valves using either guided wave or UT.

On November 19, 2015 planned inspections on the 0SX165A valve pit revealed heavy general corrosion on a drain line. The line is part of the common essential service water train A return line to the essential service water pond. Based on this discovery the licensee started a root cause evaluation to investigate the reason behind the heavy corrosion. At the conclusion of this inspection the investigation was still in progress.

Once completed, the inspectors will review the report to assess the licensee planned actions to mitigate/prevent future leaks.

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000456/2014003-01; 05000457/2014003-01, Issues that

Could Adversely Affect the Ultimate Heat Sink

a. Inspection Scope

As discussed in NRC Inspection Report 05000456/2014003; 05000457/2014003, this URI was opened to evaluate four issues of concern identified by the inspectors after the licensee discovered that station procedures to address a failure of the Braidwood cooling lake dike did not include steps to secure nonsafety-related pumps that could deplete the ultimate heat sink volume over time. Issues of concern #1, #2, and #3 of the URI had been previously reviewed by the inspectors and discussed in NRC Inspection Report 05000456/2014004; 05000457/2014004. One Green NCV was documented as a result of this review,05000456/2014004-02; 05000457/2014004-02, Multiple Failures to Follow Operability Evaluation Process Following Discovery of a Non-Conforming Condition in the Ultimate Heat Sink.

Issue of concern #4, Safety Category II Structure, Systems, and Component Interaction with the Ultimate Heat Sink was reviewed during this inspection period.

All issues of concern related to this URI have been reviewed by the inspectors. This URI is closed.

b. Findings

No findings were identified.

4OA6 Management Meetings

Exit Meeting Summary

The inspectors presented the inspection results to Ms. M. Marchionda, Site Vice President, and other members of the licensee staff on January 11, 2016. The inspectors confirmed proprietary material received during the inspection period that was no longer under review, was returned to the licensee and none of the potential input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of the ISI inspection were discussed with Mr. M. Kanavos on October 16, 2015.

• On October 19, 2015, the inspectors presented the inspection results regarding radiological hazard assessment and exposure controls, and occupational ALARA planning and controls with Mr. M. Kanavos, and other members of the licensee staff.

• The annual review of Emergency Action Levels and Emergency Plan changes with the licensee's Emergency Preparedness Coordinator, Ms. D. Poi, via telephone on December 11, 2015.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Marchionda, Site Vice President

A. Ferko, Plant Manager

J. Bashor, Engineering Manager

J. Cady, Radiation Protection Manager

B. Casey, ISI Program Owner

K. Dovas, Training Director

B. Finlay, Site Security Manager

G. Golwitzer, Regulatory Assurance Manager

R. Hall, Chemistry Manager

C. Ingold, Maintenance Manager

J. Miller, NDES Level III

D. Poi, Emergency Preparedness Manager

P. Raush, Operations Manager

S. Reynolds, Nuclear Oversight Manager

M. Shue, Welding Administrator

M. Struck, Maintenance Program Manager

R. Schliessmann, NRC Coordinator

U.S. Nuclear Regulatory Commission

J. Jandovitz, Acting Chief, Reactor Projects Branch 3

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000457/2015004-01 URI Loss of Shutdown Cooling Train During Refueling Cavity Fill and Associated Reduced Inventory Operations (Section 1R13.1b)

05000457/2015004-02 URI Failure of Startup Feedwater Pump to Start During Plant Shutdown (Section 1R20.1b(1))

05000456/2015004-03;

05000457/2015004-03 NCV Failure to Establish Adequate Feedwater Pump Operational Guidance During a Normal Plant Shutdown (Section 1R20.1b(2))

05000456/2015004-04;

05000457/2015004-04 NCV Failure to Establish a Written Procedure for a Loss of Feedwater Event in Mode 3 (Section 1R20.1b(3))

Closed

05000456/2015004-03;

05000457/2015004-03 NCV Failure to Establish Adequate Feedwater Pump Operational Guidance During Plant Shutdown (Section 1R20.1b(2))

05000456/2015004-04;

05000457/2015004-04 NCV Failure to Establish a Written Procedure for a Loss of Feedwater Event in Mode 3 (Section 1R20.1b(3))

05000456/2014003-01;

05000457/2014003-01 URI Issues that Could Adversely Affect the UHS (Section 4OA5)

Discussed

05000456/2014004-02;

05000457/2014004-02 NCV Multiple Failures to Follow Operability Evaluation Process Following Discovery of a Non-Conforming Condition in the Ultimate Heat Sink (Section 4OA5)