IR 05000456/2012002

IR0 5000456-12-002, 05000457-12-002; Exelon Generation Company, LLC; 01/01/2012 ?03/31/2012; Braidwood Station, Units 1 & 2, Fire Protection, Flood Protection Measures Maintenance Effectiveness, Operability Determinations and Functional Ass

ML12130A123
Person / Time
Site:	Braidwood
Issue date:	05/08/2012
From:	Eric Duncan Region 3 Branch 3
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-12-002
Download: ML12130A123 (53)

Text

UNITED STATES May 8, 2012

SUBJECT:

BRAIDWOOD STATION, UNITS 1 AND 2, NUCLEAR REGULATORY COMMISSION INTEGRATED INSPECTION REPORT 05000456/2012002; 05000457/2012002

Dear Mr. Pacilio:

On March 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Braidwood Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on April 4, 2012, with Mr. M. Kanavos and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Four NRC-identified findings of very low safety significance (Green) were identified during this inspection period. All of the findings were determined to involve violations of NRC requirements. The NRC is treating these violations as Non-Cited Violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these 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 a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and to the Senior Resident Inspector Office at the Braidwood Station.

If you disagree with a 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 III, and to the Senior Resident Inspector at the Braidwood Station. In accordance with 10 CFR 2.390 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 NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's Agencywide Document Access System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Eric R. Duncan, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-456 and 50-457 License Nos. NPF-72 and NPF-77

Enclosure:

Inspection Report 05000456/2012002; 05000457/2012002 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-456; 50-457 License Nos: NPF-72; NPF-77 Report No: 05000456/2012002; 05000457/2012002 Licensee: Exelon Generation Company, LLC Facility: Braidwood Station, Units 1 and 2 Location: Braceville, IL Dates: January 1, 2012, through March 31, 2012 Inspectors: J. Benjamin, Senior Resident Inspector A. Garmoe, Resident Inspector B. Jose, Senior Reactor Engineer J. Gilliam, Reactor Engineer M. Holmberg, Reactor Engineer M. Perry, Resident Inspector Illinois Emergency Management Agency Approved by: E. Duncan, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000456/2012002, 05000457/2012002; 01/01/2012 - 03/31/2012;

Braidwood Station, Units 1 & 2; Fire Protection; Flood Protection Measures; Maintenance Effectiveness; Operability Determinations and Functional Assessments.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Four Green findings were identified by the inspectors. The findings were considered Non-Cited Violations (NCVs) of NRC regulations.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Assigned cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of License Condition 2.E when licensee personnel failed to adequately maintain the approved fire protection program after receiving information that adversely affected the qualification of fire dampers credited in the safe shutdown analysis.

Specifically, the licensee inadvertently removed an action to secure ventilation upon the confirmation of a fire following a revision to the stations Pre-Fire Plans in 2010. This action was established after the licensee received NRC Information Notice (IN) 89-52,

Potential Fire Damper Operational Problems, which notified the licensee that these dampers were not qualified to shut with air flow through them. A significant contributor to this error was a failure of the licensee to adequately incorporate this action into the appropriate procedures and clearly document this requirement and basis for this requirement into the approved fire protection program. The licensee entered this issue into their corrective action program (CAP) as IR 1309949. Corrective actions included the implementation of Operations Standing Order 11-027 requiring manual operator action until a procedure change to the Fire Hazardous Materials Spill and/or Injury procedure (BwAP 1100-16), and Fire Response Guidelines (BwOP FP-100) was performed. Additionally, the licensee created an assignment to provide training to the fire brigade leaders for these planned procedure revisions.

The finding was determined to be more than minor because it was associated with the Design Control 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 (i.e., core damage). Specifically, the failure to ensure that ventilation systems were secured upon the confirmation of a fire could affect the ability of fire dampers to shut and perform their safety function. The inspectors evaluated this finding using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase I - Initial Screening and Characterization of Findings, Table 3b for the Mitigating Systems Cornerstone, which directed this finding be reviewed using IMC 0609, Appendix F, Fire

Protection Significance Determination Process, since the finding affected fire barriers.

The inspectors assigned this issue a low degradation rating based upon the high likelihood that ventilation would be secured upon the onset of a fire due to numerous ionization detectors that automatically trip ventilation systems upon the detection of smoke. Based on this assigned rating, the inspectors determined that this finding was of very low safety significance (Green). The inspectors determined that the most significant causal factor related to this finding was a failure to adequately incorporate the requirement into the current licensing basis (CLB) in 1989, and therefore this finding was not indicative of current performance and a cross-cutting aspect was not assigned.

(Section 1R05.1.b)

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, when licensee personnel failed to promptly correct conditions adverse to quality.

Specifically, from 2006 to 2011, licensee personnel failed to correct a poor material condition in the auxiliary building ventilation (VA) intake plenums that resulted in clogging of floor drains and water leakage into electrical penetration and cable spreading room areas; and from 2010 to 2012, the licensee failed to correct a degraded floor drain in the Unit 2 miscellaneous electrical equipment room (MEER) that was next to a safety shower adjacent to a safety-related direct current (DC) bus. The licensee entered this issue into their CAP as IRs 1291696 and 1332289. Corrective actions included cleaning and re-coating the VA intake plenums and routing out the floor drains in the MEERs.

The finding was determined to be more than minor because it was associated with the Design Control and Protection Against External Events attributes 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 (i.e., core damage.). Specifically, the licensee failed to promptly correct degraded and clogged auxiliary building floor drains or the poor material condition in the VA intake plenum. The inspectors evaluated this finding using the SDP in accordance with IMC 0609, Significance Determination Process,

Attachment 0609.04, Phase I - Initial Screening and Characterization of Findings, and determined that the finding affected the Flood Protection Degraded Function of the Mitigating Systems Cornerstone, per Table 2. The inspectors answered Yes to Question 5 in Table 4a, which directed the inspectors to Table 4b since the issue was related to flood protection. The inspectors answered No to Question 2 of Table 4b because the floor drains were degraded, but the pooling water in the VA plenums or MEERs would not have likely resulted in a plant trip or transient. As a result, the issue screened as having very low safety significance (Green). This finding had a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area because the licensee failed to properly classify, prioritize, or evaluate conditions adverse to quality associated with auxiliary building floor drains and VA intake plenum such that the conditions were promptly corrected P.1(c). (Section 1R06.1.b)

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR 50.65(a)(1), 10 CFR 50.65(a)(2), and 10 CFR 50.65(b)when licensee personnel failed to scope numerous high energy line break (HELB)hazard barrier dampers into the maintenance rule, as required. The function of these barriers was to protect safety-related equipment such as the emergency diesel generators (EDGs) and safety-related alternating current (AC) and DC buses and cables from credited HELB sources in the turbine building. The licensee entered this issue into their CAP as IR 1310448. Corrective actions included scoping the dampers into the maintenance rule and assigning preventative maintenance performance monitoring criteria.

The finding was determined to be more than minor because it was associated with the Equipment Performance 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 (i.e., core damage). Specifically, the failure to monitor damper performance and establish performance goals could adversely affect the availability, reliability, and capability of safety-related structures, systems and components protected by the hazard barrier. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 4, Phase I - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone. The finding screened as having very low safety significance since it was not a design or qualification deficiency confirmed not to result in a loss of operability or functionality. This finding was not indicative of current performance since the scoping aspects were determined prior to the rules effective date of July 10, 1996. As a result, a cross-cutting aspect was not assigned to this finding. (Section 1R12.1.b.1)

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR 50.49(e) when licensee personnel failed to correctly classify the EDGs, essential switchgear (ESG), and MEERs containing electrical equipment important to safety. Specifically, the licensees environmental qualification (EQ) program did not take into consideration the temperature and humidity changes expected for these rooms following a turbine building HELB and improperly classified these rooms as mild environments subjected to abnormal conditions instead of harsh environments. The licensee entered this issue into their CAP as IR 1288474. Corrective actions included an assignment for Corporate Engineering to provide a recommended environmental classification for the rooms where the abnormal conditions, due to a turbine building HELB event, were expected to occur.

The finding was determined to be more than minor because it was associated with the Equipment Performance 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 (i.e., core damage). The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 4,

Phase I - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone. The finding screened as having very low safety significance since it was not a design or qualification deficiency confirmed not to result in a loss of operability or functionality. This finding was not indicative of current performance and therefore was not assigned a cross-cutting aspect because the EQ classification of the rooms was completed in 1992. (Section 1R15.1.b.1)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power for the duration of the inspection period.

Unit 2 operated at or near full power for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather - Heavy Snowfall Conditions

a. Inspection Scope

On February 23, 2012, a Winter Weather Advisory was issued by the National Weather Service for expected heavy wet snow and strong winds. The inspectors observed the licensees preparations and planning for the significant winter weather potential. The inspectors reviewed licensee procedures and discussed potential compensatory measures with control room personnel. The inspectors focused on plant managements actions for implementing the stations procedures for ensuring adequate personnel for safe plant operation and emergency response would be available. The inspectors conducted a site walkdown that included plant structures and systems to check for maintenance or other apparent deficiencies that could affect system operations during the predicted adverse weather. The inspectors also reviewed 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.

This inspection constituted one readiness for impending adverse weather condition 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:

• Auxiliary Feedwater Safety-Related Suction Piping Voided Section;

• 1B Residual Heat Removal (RH) During 1A RH Work Window;

• 2A EDG with 2B EDG Out of Service for Maintenance; and

• 2B EDG with 2A EDG Out of Service for Maintenance.

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, the Updated Final Safety analysis Report (UFSAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, 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 four partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

.2 Semiannual Complete System Walkdown

a. Inspection Scope

On March 19, 2012, the inspectors performed a complete system alignment inspection of the Unit 1 Auxiliary Power system to verify the functional capability of the system.

This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review electrical equipment line-ups, electrical power availability, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment.

These activities constituted one complete system walkdown sample 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:

• Fire Protection Dampers Along Turbine and Auxiliary Building L-Wall;

• Work Execution Center Office Spaces Near Main Control Room Entrance;

• Main Control Room and Lower Cable Spreading Room Penetration Area;

• Unit 1 Auxiliary Electrical Equipment Room;

• Unit 2 Auxiliary Electrical Equipment Room; and

• Diesel Driven Fire Pump Room.

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 with later additional insights, 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. Documents reviewed are listed in the Attachment.

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

.1 Failure to Scope Safety-Related High Energy Line Break Barriers Into the Maintenance

Rule

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of License Condition 2.E when licensee personnel failed to adequately maintain the approved fire protection program after receiving information that adversely affected the qualification of fire dampers credited in the safe shutdown analysis. Specifically, the licensee inadvertently removed an action to secure ventilation upon the confirmation of a fire following a revision to the stations Pre-Fire Plans in 2010.

This action was established after the licensee received NRC Information Notice (IN) 89-52, Potential Fire Damper Operational Problems, which notified the licensee that these dampers were not qualified to shut with air flow through them.

Description:

NRC IN 89-52, Potential Fire Damper Operational Problems, notified the licensee of potential problems affecting the closing reliability of Ruskin Manufacturing curtain-type fire dampers under ventilation system operational air flow conditions. This concern was based on a 10 CFR Part 21 notification provided by the manufacturer along with a number of instances in which multiple licensees reported various failures of the dampers to shut upon demand.

The IN notified the licensee that the industry standard governing the design, fabrication, and testing of fire dampers was Underwriters Laboratories, Inc. (UL) Standard 555, Fire Damper and Ceiling Dampers. In the 1979 edition, the standard stated that the closing reliability of the fire dampers was evaluated on the basis that the ventilation systems were shutdown when a fire occurred. The standard, however, did not evaluate whether or not fire dampers would close under air flow conditions. Therefore, the UL fire damper rating only indicated whether a fire damper in the closed position would maintain its integrity under fire conditions for a specific time period. The IN informed the licensee that they should be aware that fire damper testing methods that did not simulate the actual total differential pressure at the damper (i.e., visual inspection or drop testing with duct access panels open) may not demonstrate operability under air flow conditions.

Furthermore, if the licensee depended on the UL product listing and did not sufficiently model air flow during surveillance testing they could not be sure that the dampers would close fully when required unless air flow was first secured. The IN discussed that licensees who had adequately addressed this issue had either

(1) type-tested worse-case air flow conditions of plant-specific fire damper configurations;

(2) tested all dampers installed in required fire barriers; or

(3) administratively shut down the ventilation systems to an area upon confirmation of a fire, through the addition of steps in plant emergency procedures.

The station reviewed IN 89-52 and identified numerous dampers applicable to the issue (NTS 456-103-89-052-00). The station responded to this information by updating the Pre-Fire plans to include a note which stated, Fire dampers may not close in the presence of air flow. Therefore, fixed ventilation systems may need to be shut down to ensure closure of fire dampers. This note was added to the beginning of each detection and suppression section of the Pre-Fire plans.

The inspectors identified that the precautionary note had been removed from the station Pre-Fire plans in 2010 during a major revision to the plans in order to improve overall quality and establish consistency throughout the Exelon fleet. The note had not been relocated in a separate procedure (e.g., Alarm Response or Fire Response procedures.)

The licensee performed a causal evaluation in the form of a work group evaluation (Issue Report (IR) 1343862). This evaluation concluded that the cause for this issue was that the stations actions to address IN 89-52 was not well documented in 1990 when it was added to the Braidwood Pre-Fire plans and, as a result, it was not transferred to the revised Pre-Fire plans in 2010. The licensees basis for this conclusion, in part, was that prior to the revision, the Pre-Fire plans were contained in an electronic file that was controlled by the Fire Marshall in response to errors or improvements identified. The licensee concluded that the front portion of the Pre-Fire plans (where this noted was located) contained additional information that enhanced fire response, but was not relied upon to execute the Braidwood Pre-Fire plans. The licensee provided other examples to illustrate this conclusion (purpose of a fire brigade, fire brigade leader, brigade members, expected response to a fire for particular areas, interfacing with offsite fire departments, and types of fires and preferred extinguishing agents). The Pre-Fire Plan also has a less stringent revision review process.

The inspectors reviewed the licensees causal evaluation and concluded that the licensee had not adequately maintained the approved fire protection program in a manner that ensured the current licensing basis (CLB) was clearly documented in appropriate procedures and programs. The inspectors concluded that although the note should not have been removed from the Pre-Fire plans without the licensee understanding the notes origin and potential consequences, the most significant cause of the performance deficiency was related to how IN 89-52 was incorporated into the approved fire protection program and appropriate program procedures. The licensee entered this issue into their CAP as IR 1309949. Corrective actions included implementing Operations Standing Order 11-027 requiring actions to ensure ventilation was secured upon the confirmation of a fire until a change to the Fire Hazardous Materials Spill and/or Injury procedure (BwAP 1100-16), and the Fire Response Guidelines (BwOP FP-100) was performed. Additionally, the licensee created an assignment to provide training to the fire brigade leaders for these procedural revisions.

Analysis:

The failure to maintain the approved fire protection program CLB regarding the qualification of fire dampers was a performance deficiency. Specifically, the licensee did not ensure that fire dampers credited in the safe shutdown analysis were adequately qualified since part of that qualification was to ensure that ventilation systems were secured upon the confirmation of a fire. The inspectors reviewed Inspection Manual Chapter (IMC) 0612, Appendix E, Examples of Minor Issues, and could not reasonably conclude whether the issue was more than minor. Thus, the inspectors reviewed the minor questions in IMC 0612, Appendix B, Issue Screening, and concluded that the finding was more than minor because it was associated with the Design Control 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 (i.e., core damage.) Specifically, the failure to ensure that fire dampers credited in the safe shutdown analysis were adequately qualified could affect the dampers ability to shut and perform its safety function. The inspectors evaluated this finding using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase I - Initial Screening and Characterization of Findings, Table 3b for the Mitigating Systems Cornerstone, which directed this finding be reviewed using IMC 0609, Appendix F, Fire Protection Significance Determination Process, since the finding affected fire barriers.

The inspectors assigned this issue a low degradation rating based upon the high likelihood that ventilation would be secured upon the onset of a fire due to numerous ionization detectors that automatically trip ventilation systems upon the detection of smoke. Based on this assigned rating, the inspectors determined that this finding was of very low safety significance (Green).

The inspectors determined that the most significant causal factor related to this finding was a failure to adequately incorporate the requirement into the CLB in 1989, and therefore this finding was not indicative of current performance and a cross-cutting aspect was not assigned.

Enforcement:

Braidwood License Condition 2.E requires that, The licensee shall implement and maintain in effect, all provisions of the approved fire protection program as described in the UFSAR, as supplemented and amended.

Contrary to the above, upon the receipt of NRC Information Notice 89-52, Potential Fire Damper Operational Problems in 1989, and identification that Ruskin Manufacturing curtain-type fire dampers at the station were not qualified with nominal ventilation air flow conditions through them, the licensee failed to adequately maintain the approved fire protection program in a manner that adequately documented the method for how the dampers would be qualified during a licensing basis fire event. Corrective actions included implementing Operations Standing Order 11-027 requiring actions to ensure ventilation was secured upon the confirmation of a fire until a change to the Fire Hazardous Materials Spill and/or Injury procedure (BwAP 1100-16), and the Fire Response Guidelines (BwOP FP-100) was performed. Additionally, the licensee created an assignment to provide training to the fire brigade leaders for these procedural revisions. Because this violation was of very low safety significance and because this issue was entered into the licensees CAP as IR 1309949, this violation is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000456/2012002-01; 05000457/2012002-01, Failure to Maintain Approved Fire Protection Program Regarding Safe Shutdown Fire Damper Qualification)

1R06 Flood Protection Measures

.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. 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 corrective action program 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:

• Miscellaneous Electrical Equipment Rooms.

Specific documents reviewed are listed in the Attachment. This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

(Closed) Unresolved Item 05000456/2011004-02; 05000457/2011004-02, Use of Mesh Strainer Bags in Auxiliary Building Floor Drains

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, when licensee personnel failed to correct conditions adverse to quality.

Specifically, from 2006 to 2011 licensee personnel failed to correct poor material condition in the auxiliary building ventilation system (VA) intake plenums that led to clogging of floor drains and water leakage into electrical penetration and cable spreading room areas, and from 2010 to 2012 licensee personnel failed to correct a degraded floor drain in the Unit 2 miscellaneous electrical equipment room (MEER) that was next to a safety shower adjacent to a safety-related Direct Current (DC) bus.

Description of Example 1: Through a routine review of CAP documents during summer 2011, the inspectors noted the following IRs documenting the pooling of water in the VA intake plenum areas:

• IR 1230829; Water in VA Inlet Plenum Following Storm; June 20, 2011;

• IR 1249503; Operations - Auxiliary Building Floor Drain Overflowing; August 9, 2011;

• IR 1259300; Area Evaluation Required After Water Exposure; September 4, 2011; and

• IR 1260053; Clogged Floor Drain Basket in 0VA01CC/CD Supply Plenum; September 7, 2011.

Water accumulates in the intake plenums when warm outside air passes over the chilled water coils, which results in condensation. By design, the condensation falls to the floor of the plenums and is removed through floor drains. The inspectors discussed the issue with the licensee and reviewed historical CAP documents regarding water accumulation in the VA intake plenums. The issue was initially identified by a vendor in 2006 (IRs 469055 and 469058) who questioned the material condition of the VA intake plenums with the system engineer, who recommended verifying the floor drains were functional, cleaning loose debris, and recoating the plenum surfaces. In total, the inspectors noted over 20 IRs related to the effects of poor material condition in the VA intake plenums, including the following:

• IR 0577835; Engineering Change Request to Address Water in VA Plenums During Summer; January 11, 2007;

• IR 0652030; Water Present in U2 LCSR [Lower Cable Spreading Room]; July 20, 2007;

• IR 0657432; U-2 Lower Cable Spreading Room Floor Drains Plugged, Water on Floor, Safety Issue; August 5, 2007; and

• IR 1076410; Backed Up Floor Drain Causes Water to Enter Electrical Cable Tray; June 3, 2010.

WOs 0907365 and 0910190 were created in March 2006 to improve the material condition of the Unit 1 and Unit 2 VA intake plenums. In June 2007 the licensee attempted to clean the Unit 1 VA intake plenum, but was unable to complete the work due to poor material condition and standing water in the plenum. Despite the work not being completed, WO 0910190 was revised to a completed status. This was later recognized and WO 1045973 was generated in its place. The open WOs were scheduled for fall 2009 but were then rescheduled to March 2010, January 2011, and December 2011, despite clear documentation in the CAP that these WOs were scheduled to support summer readiness in both 2010 and 2011.

The inspectors reviewed the licensees CAP procedures and concluded that the conditions in the VA plenums and the resulting pooling and leakage of water into other plant areas met the procedure LS-AA-125 definition of a deficiency, which was, a condition or concern that does not meet specific requirements of procedures, policies, management expectations, or accepted industry standards. Procedure LS-AA-125 included deficiencies in the definition of a condition adverse to quality. The definitions in procedure LS-AA-125 also stated that a Corrective Action assignment type was an action taken or planned that restores a condition adverse to quality to an acceptable condition or capability.

The inspectors concluded that in accordance with procedure LS-AA-125, the ongoing poor material condition of the VA intake plenum, such that water pooled in the plenums and leaked into lower elevations met the definition of a condition adverse to quality, and was not corrected in a timely manner.

Description of Example 2: While reviewing concerns regarding the material condition of the VA plenum described above, the inspectors identified that IR 1057855, which was generated by the licensee on April 17, 2010, documented concerns regarding clogged or undersized floor drains near safety showers in the Unit 1 and Unit 2 MEERs.

Specifically, during routine safety shower testing, the equipment operator noticed that the floor drains did an extremely poor job draining water and the room would begin to flood if the shower was run for the minimum of 15 minutes if it were needed. The MEERs contained safety-related DC power busses that were located within 6 feet of the safety shower and 8 feet of the floor drain. Licensee Procedure 0BwOS TW-W1, Emergency Eyewash Shower and Functional Surveillance, Revision 23, referenced American National Standards Institute (ANSI) Code Z358.1-1990, which required safety showers to provide at least 30 gallons per minute (gpm) at 30 pounds per square inch (psi) for 15 minutes; therefore the safety shower was anticipated to discharge greater than 450 gallons of water into the MEER upon activation. The IR was assigned a Significance Level 4 and a work request was created to check the floor drains and perform repairs as needed. However, the inspectors noted that the work request had been extended numerous times, had not been completed as of February 2012, and was currently due on June 28, 2012. The inspectors questioned the timeliness of investigating the condition of the floor drains. As a result, the licensee generated IR 1332289, MEER Safety Shower Floor Drain Corrective Action Timeliness, and IR 332293, Safety Shower Impact on AB [Auxiliary Building] Flooding Calculation, and the work request to clean the MEER floor drains was completed.

The inspectors reviewed the licensees CAP procedures and concluded that degraded floor drains near safety-related equipment and a 450 gallon water source met the procedure LS-AA-125 definition of a deficiency.

The inspectors concluded that in accordance with LS-AA-125, the report in IR 1057855 of a degraded floor drain near safety-related equipment and a 450 gallon water source met the definition of a condition adverse to quality, which was not corrected in a timely manner.

Analysis:

The inspectors determined that the failure to correct conditions adverse to quality in a prompt or timely manner was a performance deficiency. The inspectors reviewed IMC 0612, Appendix E, Examples of Minor Issues, and could not reasonably conclude whether the issue was more than minor. Thus, the inspectors reviewed the minor questions in IMC 0612, Appendix B, Issue Screening, and concluded that the finding was more than minor because it was associated with both the Design Control and Protection Against External Events attributes 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 (i.e., core damage.) Specifically, the licensee failed to correct the poor material condition of the VA plenum and the issues associated with floor drains near safety showers that resulted in actual and potential pooling and leakage of water near safety-related equipment. The inspectors evaluated this finding using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase I - Initial Screening and Characterization of Findings, and determined that the finding affected the Flood Protection Degraded Function of the Mitigating Systems Cornerstone, per Table 2. The inspectors answered No to the first four Mitigating Systems questions in Table 4a but answered Yes to Question 5, which directed the inspectors to Table 4b since the issue was related to flood protection. The inspectors answered Yes to Question 1 and No to Question 2 of Table 4b because the floor drains were degraded, but the pooling water in the VA plenums or MEERs would not have likely resulted in a plant trip or transient. As a result, the issue screened as having very low safety significance (Green).

This finding had a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area because the licensee failed to properly classify, prioritize, or evaluate conditions adverse to quality associated with auxiliary building floor drains such that the conditions were promptly corrected P.1(c).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, since 2006, the licensee failed to correct ongoing material condition issues associated with the VA intake plenum or degraded auxiliary floor drains, which were conditions adverse to quality. Specifically, from 2006 to 2011, the licensee failed to correct poor material conditions in the VA intake plenums that resulted in clogging of floor drains and water leakage to electrical penetration and cable spreading room areas, and from 2010 to 2012, the licensee failed to correct a degraded floor drain in the Unit 2 MEER that was a safety shower drain adjacent to a safety-related DC Bus. Corrective actions included cleaning and re-coating the VA intake plenums and routing out the floor drains in the MEERs. Because this violation was of very low safety significance and because this issue was entered into the licensees CAP as IRs 1291696 and 1332289, this violation is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000456/2012002-02; 05000457/2012002-02, Failure to Promptly Correct Conditions Adverse to Quality)

URI 05000456/2011004-02; 05000457/2011004-02 is closed.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On March 23, 2012, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify 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;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

The crews performance in these areas was compared to pre-established operator action expectations and successful critical 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.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On January 18, 2012, the inspectors observed activities in the main control room during an unplanned 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> TS Action Statement (AS) due to the inoperability of the Unit 2 refueling water storage tank. Specifically, the heat trace circuit for the refueling water storage tank vent line failed and the vent line temperature indication dropped below 35 degrees Fahrenheit (F). As a result, TS AS 3.5.4, Condition B, required the refueling water storage tank to be operable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or Unit 2 must be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The licensee was able to repair the heat trace circuit prior to shutting down the unit. 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;

• correct use and implementation of procedures;

• control board and equipment manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions.

The 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.

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:

• HELB Barrier Dampers; and

• Refueling Water Storage Tank Temperature Monitoring.

The inspectors reviewed events including those that involved ineffective equipment maintenance that resulted in valid or invalid automatic actuations of engineered safety feature (ESF) 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 (SSCs)/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 two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

.1 Failure to Scope Safety-Related High Energy Line Break Barriers Into the Maintenance

Rule

Introduction:

The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(1), 10 CFR 50.65(a)(2), and 10 CFR 50.65(b) when licensee personnel failed to scope safety-related HELB hazard barrier dampers into the maintenance rule, as required. The function of these barriers was to protect safety-related equipment such as the EDGs and safety-related AC and DC buses and cables from HELB sources in the turbine building.

Description:

Sections 3.11 and 9.4.5 of the Braidwood UFSAR stated that fire dampers penetrating the fire wall between the ESF switchgear rooms, MEERs, and EDG rooms would close during a HELB. The station calculations of record that determined the peak and equilibrium room temperatures within the safety-related spaces credited these dampers to shut within a specific period of time.

The inspectors identified that HELB dampers separating various safety-related equipment rooms from postulated steam line breaks within the turbine building were not scoped within the licensees maintenance rule program, as required.

The licensee entered this issue into their CAP as IR 1310448. On February 24, 2012, the licensee presented this issue to their maintenance rule expert panel and identified three ventilation systems that required new scoping criteria in accordance with maintenance rule requirements. On March 8, 2012, the licensee added these new functions to their respective systems to the maintenance rule program.

The systems affected by the inspectors issue included the following:

• Diesel Generator Room Ventilation System (VD);

• Miscellaneous Electrical Equipment Room Ventilation System (VE); and

• ESF Switchgear Room Ventilation System (VX).

The new functional area created for these systems was categorized by the licensee as a safety-related function of safety-related SSCs that were needed to ensure the capability to shutdown the reactor and maintain it in a safe shutdown condition.

Analysis:

The inspectors identified that the failure to scope safety-related HELB hazard barrier dampers that met the 10 CFR 50.65 maintenance rule scoping requirements was a performance deficiency. The inspectors reviewed IMC 0612, Appendix E, Examples of Minor Issues, and could not reasonably conclude whether the issue was more than minor. Thus, the inspectors reviewed the minor questions in IMC 0612, Appendix B, Issue Screening, and concluded that the finding was more than minor because it was associated with the Design Control 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 (i.e., core damage.) Specifically, the failure to monitor damper performance and establish performance goals could adversely affect the availability, reliability, and capability of safety-related SSCs protected by the hazard barrier. The inspectors evaluated this finding using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 4, Phase I - Initial Screening and Characterization of Findings, Table 4a, Phase I Worksheet. This issue was of very low safety significance (Green) because it did not result in a loss of operability or functionality.

This finding was not indicative of current performance since the scoping aspects were determined prior to the maintenance rules effective date of July 10, 1996. Therefore, a cross-cutting aspect was not assigned to this finding.

Enforcement:

10 CFR Part 50.65(a)(1) requires, in part, that licensees. . . shall monitor the performance or condition of structures, systems, and components [SSCs], against licensee-established goals, in a manner to provide reasonable assurance that these structures, systems, and components. . . are capable of fulfilling their intended functions.

10 CFR Part 50.65(a)(2) requires, in part, monitoring as specified in paragraph (a)(1) of this section is not required when it has been demonstrated that the performance or condition of a structure, system, or component is being effectively controlled through the performance of appropriate preventive maintenance.

10 CFR Part 50.65(b) requires, in part, that the scope of the monitoring program specified in paragraph (a)(1) of this section shall include safety-related and nonsafety-related SSCs, as follows:

(1) safety-related SSCs that are relied upon to remain functional during and following design basis events to ensure the integrity of the reactor coolant pressure boundary, the capability to shutdown the reactor and maintain it in a safe shutdown condition, or the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposure comparable to the guidelines in 10 CFR 50.34(a)(1), 50.67(b)(2), or 100.11 of this chapter, as applicable.

Contrary to the above, from initial maintenance rule scoping in 1996, the L-Wall HELB barrier dampers for the Diesel Generator Room Ventilation, Miscellaneous Electrical Equipment Room Ventilation, and ESF Switchgear Room Ventilation systems were not included in the scope of the (a)(1) or (a)(2) monitoring program specified in the maintenance rule. The inclusion of these barrier devices within the rule was required because failure of these dampers to function adequately could prevent multiple safety-related systems from fulfilling their safety-related functions.

Corrective actions included scoping the HELB barrier function for the Diesel Generator Room Ventilation, Miscellaneous Electrical Equipment Room Ventilation, and ESF Switchgear Room Ventilation systems into the maintenance rule program, and performing a review of past inspection results. Because this violation was of very low safety significance and because this issue was entered into the licensees CAP as IR 1326237, this violation is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 5000456/2012002-03; 05000457/2012002-03, Failure to Scope Safety-Related HELB Barriers into the Maintenance Rule)

.2 Unresolved Item 05000456/2012002-04; 05000457/2012002-04, Maintenance Rule

Performance Monitoring of HELB Dampers

Introduction:

The inspectors reviewed the licensees performance monitoring criteria for the dampers identified in NCV 0500456/2012002-03; 05000457/2012002-03 and identified an Unresolved Item (URI) pertaining to the licensees decision to monitor HELB damper preventative maintenance performance by conducting a periodic 18-month visual inspection activity. Specifically, the inspectors questioned if it was appropriate and adequate to rely only on the visual inspection activities absent some level of periodic demand testing to provide reasonable assurance that HELB dampers would shut within required time limits.

Description:

10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, required, in part:

• 10 CFR 50.65(a)(1), Each holder of an operating license for a nuclear power plant under this part. . .shall monitor the performance or condition of structures, systems, or components against licensee-established goals, in a manner sufficient to provide reasonable assurance that the SSCs, as defined in paragraph

(b) of this section, are capable of fulfilling their intended functions.

• 10 CFR 50.65(a)(2), Monitoring as specified in (a)(1) of this section is not required where it has been demonstrated that the performance or condition of a structure, system, or component is being effectively controlled through the performance of appropriate preventative maintenance, such that the structure system, or component remains capable of performing its intended function.

For the associated HELB barrier dampers, the licensee selected performance criteria related to attributes of a periodic 18-month inspection activity. The inspection activity inspected the material condition of the damper, damper frame, and fusible links.

The inspectors questioned whether the licensees performance criteria based only on conducting visual inspection preventative maintenance activities was acceptable based upon the following:

• The concern that the inspection activity may not have the capability to detect failures that were not visually observable (e.g., the amount the spring utilized in the dynamic dampers relax over time);

• The inability to inspect the dampers entire surface area in the closed position, and;

• The use of past damper performance reliability that was based in large part upon past inspections and not upon actual demand testing since the licensee had discontinued damper testing based upon a review of the stations Fire Protection program licensing requirements.

This URI will remain open pending the inspectors review of the licensees performance monitoring criteria against the 10 CFR 50.65 maintenance rule requirements.

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:

• 1A RH Work Window - Planned Online Risk Yellow;

• 1B RH Work Window - Planned Online Risk Yellow;

• Unit 0 Component Cooling Heat Exchanger - Planned Online Risk Yellow for Both Units

• Switchyard Bus 7 Maintenance - Operational Risk Activity;

• 1B Essential Service Water Pump Work Window - Planned Online Risk Yellow;

• Switchyard Bus 1 Work with Impending Winter Weather - Operational Risk Activity; and

• High Wind Conditions with 2A EDG Out of Service for Planned Maintenance -

Unplanned Online Risk Orange.

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 are listed in the Attachment.

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

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Non-Conservative Gaseous Effluent Radiation Monitor Setpoints;

• Generic Letter 96-06 Response Credits Air Operated Valves for Relief Function;

• Identification of White Substance in 2C and 2D Reactor Containment Fan Coolers;

• Safety-Related 4 kilovolt (kV) Undervoltage Protection Scheme; and

• Fuel Thermal Conductivity Analysis Errors.

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 five samples as defined in IP 71111.15-05.

.1 Incorrect Classification of Environmental Qualification Zones

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR 50.49(e) when licensee personnel failed to correctly classify the EDG, essential switchgear (ESG), and MEERs containing electrical equipment important to safety. Specifically, the licensees EQ Program did not take into consideration the temperature and humidity changes experienced by these rooms during a turbine building HELB and incorrectly classified these rooms as mild environments subjected to abnormal conditions, instead of harsh environments.

Description:

During a review of the licensees turbine building HELB analysis, the inspectors noted that various rooms housed important to safety electrical equipment that would potentially be affected by a turbine building HELB. These rooms included the EDG rooms (EQ Zone A6), ESG rooms (EQ Zone A3), and the MEERs (EQ Zone A3).

According to the Braidwood UFSAR, Table 3.11-2, the normal maximum temperatures of these rooms were 132 degrees Fahrenheit (ºF), 108ºF, and 108 ºF, respectively, and the normal relative humidity for all of the rooms was 8-70 percent. A turbine building HELB causes temporary failure of the ventilation systems in the EDG rooms, ESG rooms, and MEERs, which was expected to be restored within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The turbine building HELB analysis evaluated the conditions of these rooms and showed maximum peak temperatures in the rooms of 167ºF, 160ºF, and 175ºF, respectively, with 100 percent relative humidity. The licensee classified these rooms as mild environments that were subject to abnormal conditions in 1992, following discovery that these rooms would experience higher than normal temperatures and humidity due to a turbine building HELB. This classification was based upon the determination that the effects of a turbine building HELB on these rooms would be short term.

Based on the analyzed changes in temperature and humidity in these rooms during a turbine building HELB, the inspectors questioned whether the rooms should have been classified as harsh environments. Additionally, the licensees transient analysis assumed that the elevated temperature and humidity levels lasted for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, rather than for a short time period.

Title 10 CFR Part 50.49, Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants, defined a mild environment as an environment that would at no time be significantly more severe than the environment that would occur during normal plant operation, including anticipated operational occurrences. Licensee EQ Programs were required by 10 CFR 50.49(e) to consider temperature, pressure, humidity, chemical effects, radiation, aging, submergence, and synergistic effects when classifying EQ Zones. The environment in the EDG rooms (EQ Zone A6), ESG rooms (EQ Zone A3), and MEERs (EQ Zone A3) all become more severe during a turbine building HELB with respect to humidity and temperature. Therefore, the important to safety equipment in these EQ Zones should have been evaluated under 10 CFR 50.49 and the licensees EQ Program.

The licensees EQ Program ensured electrical equipment was qualified to perform its function during and following design basis events. Title 10 CFR Part 50.49(f) states, Each item of electric equipment important to safety must be qualified by one of the following methods:

(1) Testing an identical item of equipment under identical conditions or under similar conditions with a supporting analysis to show that the equipment to be qualified is acceptable;

(2) Testing a similar item of equipment with a supporting analysis to show that the equipment to be qualified is acceptable;

(3) Experience with identical or similar equipment under similar conditions with a supporting analysis to show that the equipment to be qualified is acceptable; and

(4) Analysis in combination with partial type test data that supports the analytical assumptions and conclusions. Since the equipment in the EDG rooms, ESG rooms, and MEERs were not placed in the EQ program, they were not qualified for the harsh environment that the rooms would be subjected to during a turbine building HELB.

The licensee generated IR 1288474 on November 8, 2011, for Corporate Engineering to provide a recommended environmental classification for the rooms where the abnormal conditions, due to a turbine building HELB event, were expected to occur.

Analysis:

The inspectors determined that the incorrect classification of the EDG rooms, ESG rooms, and MEERs was contrary to the requirements of 10 CFR 50.49(e) and was a performance deficiency. Specifically, the licensee did not consider the adverse effects of a turbine building HELB on temperature and humidity in the subject rooms when classifying these EQ Zones and qualifying important to safety electrical equipment. The inspectors reviewed IMC 0612, Appendix E, Examples of Minor Issues, and could not reasonably conclude whether the issue was more than minor. Thus, the inspectors reviewed the minor questions in IMC 0612, Appendix B, Issue Screening, and concluded that the finding was more than minor because it was associated with the Equipment Performance 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 (i.e., core damage.) Specifically, the incorrect classification of these rooms led to the EQ zones not being included in the licensees EQ Program, which resulted in unqualified important to safety equipment that would be subjected to a harsh environment during a turbine building HELB. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 4, Phase I - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone. This finding was determined to be of very low safety significance (Green) because it did not result in a loss of operability or functionality for the electrical equipment housed in the rooms identified.

This finding was not associated with a cross-cutting aspect because the EQ classification of the rooms was completed in 1992 and was not representative of current licensee performance.

Enforcement:

Title 10 CFR Part 50.49(e), requires, in part, that the electric equipment qualification program must include and be based on the following:

(1) Temperature and pressure;

(2) Humidity;

(3) Chemical effects;

(4) Radiation;

(5) Aging;

(6) Submergence;

(7) Synergistic effects; and

(8) Margins. This qualification was based upon the environmental conditions at the location where the equipment must perform its function.

Contrary to the above, from 1992 until January 26, 2012, the licensees electric equipment EQ Program did not include important to safety equipment in the EDG rooms, ESG rooms, and MEERs. Specifically, the licensees EQ Program did not take into consideration the temperature and humidity changes experienced by these rooms during a turbine building HELB. Instead, the licensee classified the rooms as mild environments subjected to abnormal conditions instead of harsh environments.

Corrective actions at the end of the inspection were indeterminate, but included a plan to evaluate this issue along with other related HELB L-Wall issues to ensure regulatory compliance. Because this violation was of very low safety significance and because this issue was entered into the licensees CAP as IR 1288474, this violation is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000456/2012002-05; 05000457/2012002-05: Incorrect Classification of Environmental Qualification Zones)

.2 Unresolved Item 05000456/2012-06; 05000457/2012-06, Inadequate Safety-Related

4kV Undervoltage Protection

Introduction:

On January 30, 2012, Byron Unit 2 automatically tripped after a 345kV insulator failed in the station switchyard. The failed insulator resulted in an open C phase supplying a TS preferred power source to both safety-related 4kV buses. The open circuit, at Byron Unit 2, prevented safety-related equipment from operating due to an undervoltage condition experienced at the equipment. Additionally, the undervoltage protection scheme did not generate an automatic bus undervoltage signal due to the design of the protection logic. This design issue also existed at Braidwood Unit 1 and Unit 2. The inspectors identified a URI to determine whether the undervoltage and degraded voltage protection design vulnerability was within Braidwoods CLB.

Description:

TS 3.3.5, Loss of Power Diesel Generator Start Instrumentation, required that in Modes 1-4 two channels per bus of the loss of voltage (undervoltage) function and two channels per bus of the degraded voltage function shall be operable. In addition, TS Surveillance Requirement 3.3.5.2 stated that the acceptable channel calibration values for the undervoltage setpoint was greater than 2730 volts with a time delay of less than or equal to 1.9 seconds; and for the degraded voltage setpoint, the value was greater than 3930 volts with a time delay of 310 plus or minus 30 seconds.

Upon actuation of the undervoltage or degraded voltage function, the EDGs were designed to start and provide power to all engineered safety feature loads.

However, because the engineered safety feature undervoltage and degraded voltage protection schemes was comprised of two contacts in series that monitored differential voltages between the A-B and B-C phases, upon the loss of only the A or C phase, only one protective relay was actuated and therefore did not satisfy the coincidence logic necessary to initiate an undervoltage or degraded voltage protection signal.

The Byron and Braidwood licensee concluded that this event was not within the facilitys CLB and that because the NRC had reviewed and approved the design, that the undervoltage protection design inadequacies did not impact operability and that the requirements of TS 3.3.5 were met. The licensee implemented compensatory actions consisting of a dedicated operator station for each operating unit in the main control room to ensure that manual action would be taken to separate the TS preferred power source following a loss of A or C phase to the station auxiliary transformers (SATs).

At the end of this inspection, a detailed review of the CLB was in progress. This URI will remain open pending the completion of this review and a determination of whether the undervoltage and degraded voltage protection design vulnerability was within the stations CLB. (URI 05000456/2012002-06, 05000457/2012002-06, Inadequate Safety Related 4kV Undervoltage Protection)

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modifications:

• Unit 2 Refueling Water Storage Tank Vent Path Heating Temporary Modification; and;

• Essential Service Water Makeup to Component Cooling Water Surge Tanks Permanent Modification.

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 affect the operability or availability of the affected systems. The inspectors observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications 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 operations, engineering, and training personnel 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 Attachment.

This inspection constituted two plant modification samples 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:

• 1B RH Pump Following Work Window;

• 1A Safety Injection Pump Following Oil Replacement;

• 1A Containment Spray Pump Following Work Window;

• 2B EDG Following Work Window; and

• 2A EDG Following Work Window.

These activities were selected based upon the potential impact on risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and 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 testing 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 five post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

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 1 Main Turbine Stop Valve and Intercept Valve Testing (Routine);

• Bus 142 Undervoltage and Degraded Voltage Surveillance (Routine);

• 1B EDG Monthly Surveillance (Routine)

• 1A Containment Spray Pump Quarterly Surveillance (Inservice Test);

• Reactor Coolant System (RCS) Unidentified Leakrate (RCS Leakrate);

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, demonstrated operational readiness, and consistent with the system design basis;

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

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

• measuring and test equipment calibration was current;

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

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

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

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;

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

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

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

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

Documents reviewed are listed in the Attachment.

This inspection constituted three routine surveillance testing samples, one inservice testing sample, and one reactor coolant system leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on February 1, 2012, 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 to determine whether the event classifications, 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 to evaluate the critique and to verify whether licensee staff was properly identifying weaknesses and entering them into the CAP. 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 71114.06-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

4OA1 Performance Indicator Verification

.1 Unplanned Scrams Per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams Per 7000 Critical Hours Performance Indicator (PI) for Braidwood Unit 1 and Unit 2. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports and NRC Integrated Inspection Reports from January through December 2011, to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report 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 scrams per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI for Braidwood Unit 1 and Unit 2. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports and NRC Integrated Inspection Reports from January 1 through December 2011, to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report 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 scrams with complications samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Emergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power System PI for Braidwood Unit 1 and Unit 2. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, was used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, issue reports, event reports and NRC Integrated Inspection Reports for the period from January 1 through December 2011 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, whether the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report 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 MSPI emergency AC power system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

.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 that 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 whether identification of the problem was complete and accurate; whether timeliness was commensurate with the safety significance; whether 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 whether 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 followup, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily issue 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 Selected Issue Followup Inspection: Implementation of the Operability/Functionality

Process

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized several corrective action items documenting conditions that appeared to represent degraded or non-conforming conditions, as defined in Part 9900 of the NRC Inspection Manual, Operability Determinations & Functionality Assessments For Resolution Of Degraded Or Nonconforming Conditions Adverse To Quality Or Safety. Licensee procedure OP-AA-108-115, Operability Determinations, used the same definitions.

One of the conditions reviewed was air-operated containment isolation valves that were credited for penetration overpressure relief to address issues communicated in Generic Letter 96-06, Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions (IR 1257969). The licensee noted that although the credited pressure relief function of the valves was not tested, a calculation was performed to validate the function. Because the valve was not tested for the credited relief function, as required by the licensees inservice testing program, the inspectors questioned whether this represented a non-conforming condition. The licensee subsequently entered this issue into their CAP as IR 1322584. The licensee reviewed the issue and agreed with the inspectors that not testing the credited relief function of the air-operated valves did, in fact, represent a non-conforming condition. The inspectors noted that, while the issue had not been tracked as a non-conforming condition, appropriate corrective actions were planned.

The second condition reviewed was the failure of the Unit 2 refueling water storage tank vent line heat trace circuitry, which rendered the Unit 2 refueling water storage tank inoperable due to vent line temperature indication dropping below 35 F. The licensee installed temporary heating blankets to maintain the vent line temperature above the minimum TS limits. The inspectors questioned whether the blankets should be formally tracked as a compensatory action to address a non-conforming condition. Based on discussions with the licensee, the licensee planned to monitor the installation of the temporary blankets and pursue a permanent resolution formally through the temporary change process.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.4 Selected Issue Followup Inspection: Transformer Secured Material Zone Review

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized several corrective action items documenting loose material that was identified within the Unit 1 and Unit 2 transformer exclusion areas and secured material zones. The inspectors reviewed the licensees corrective actions to prior NCVs related to loose material in these areas. The licensee had revised procedures and standards, planned to increase physical markings of the areas, and increased their attentiveness to material in the areas. The inspectors concluded that the licensee has been applying additional rigor in identifying and removing material from these areas, but continued to struggle with preventing materials from being staged in these areas. The inspectors planned to continue to monitor the effectiveness of existing and any additional corrective actions in preventing loose material in these areas, especially during times when adverse weather conditions were forecast or were imminent.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.5 Selected Issue Followup Inspection: Braidwood Response to Byron Undervoltage

Condition

a. Inspection Scope

The inspectors became aware of an issue concerning electrical bus undervoltage protection based on an event that occurred at Byron on January 30, 2012.

Additional information about the Byron event is available in Byron Inspection Report 05000455/2012008. The inspectors and licensee concluded that the Braidwood undervoltage protection scheme was of the same design as Byron and would operate in the same manner under the same conditions. The inspectors reviewed compensatory actions that were put in place at Braidwood to mitigate the undervoltage protection scheme vulnerability. These actions included assigning designated control room operators to monitor for undervoltage conditions and manually separate the electrical safety buses from the power grid, if necessary, and a temporary modification to control room annunciator logic that resulted in more conservative logic for the Loss of Offsite Power annunciators. The inspectors also reviewed the licensees progress in developing a permanent modification to the undervoltage protection scheme. At the end of the inspection period the licensee was continuing to evaluate design options in an effort to find a successful modification. This issue is related to the Unresolved Item opened in Section 1R15.1.b.3 of this inspection report.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed)(Withdrawal) Licensee Event Report 05000457/2010-004-00, Unplanned

Limiting Condition for Operation Entry Due to Low Header Pressure on the 2B Essential Service Water Pump This Licensee Event Report (LER) was initially reported on October 25, 2010, and was reviewed by the inspectors in Section 4OA3 of Inspection Report 05000456/2011002; 05000457/2011002. Specifically, due to monitoring an incorrect flow instrument during valve adjustments, the licensee operated the essential service water system outside of its analyzed design. Subsequent analysis and flow modeling provided additional information which revealed that, while low essential service water flow would have been provided to multiple pieces of safety-related equipment, sufficient essential service water flow would have been provided to allow safety-related equipment to perform its safety function. Therefore, the licensee withdrew this LER.

Documents reviewed are listed in the Attachment. This LER is closed. This event followup review constituted one sample as defined in IP 71153-05.

.2 (Closed) Licensee Event Report 05000456/2011-001-00, Through Wall Crack on 1A

Safety Injection Pump Discharge Line Due to Outside Diameter (Transgranular) Stress Corrosion Cracking Initiated at External Diameter of Pipe This LER, which was reported on April 6, 2011, documented pressure boundary leakage due to stress corrosion cracking on the discharge piping of the 1A safety injection pump.

The leakage was identified through observation of boric acid residue on February 25, 2011. The licensee declared the 1A safety injection train inoperable and entered the 7-day allowed outage time (AOT) in accordance with TS 3.5.2. The line was repaired and returned to service within the AOT. However, it was unknown when the pressure boundary leakage began and, thus, it may have existed for greater than the TS required 7-day AOT. As a result, the licensee conservatively submitted this LER in accordance with 10 CFR 50.73(a)(2)(i)(B). Because the duration of the condition was not known and because the licensee entered the applicable TS AOT upon discovery, the inspectors did not identify a violation of regulatory requirements.

Documents reviewed are listed in the Attachment. This LER is closed. This event followup review constituted one sample as defined in IP 71153-05.

.3 (Closed) Licensee Event Report 05000456/2011-004-00; 05000457/2011-004-00,

Historic Input Errors Identified in High Energy Line Break Analyses for Turbine Building Resulted in Potential Unanalyzed Condition This LER, which was reported on December 22, 2011, documented potential consequences of identified non-conservatisms in the licensees turbine building HELB analyses. The inspectors have previously reviewed other aspects of the non-conservative turbine building HELB analyses as documented in Section 1R15.1.b.2 of Braidwood Inspection Report 05000456/2011004; 05000457/2011004, and Sections 1R15.1.b, 1R15.2, and 4OA7 of Braidwood Inspection Report 05000456/2011005; 05000457/2011005.

This LER specifically documented instances where the roll-up doors to the Division 11 and Division 21 MEER rooms, which constituted turbine building HELB barriers, were opened for up to 18 minutes. Because the roll-up doors could not close fast enough upon a turbine building HELB to ensure protection of equipment in the MEER rooms, Instrument Busses 111 and 113, which were both part of ESF Division 11, and Instrument Busses 211 and 213, which were both part of ESF Division 21, were rendered inoperable during the time the roll-up doors were open. This resulted in two independent channels in a single system being rendered inoperable, which was reportable per 10 CFR 50.73(a)(2)(vii).

The inspectors previously documented a licensee-identified violation of the technical issue discussed in this LER in Section 4OA7 of Braidwood Inspection Report 05000456/2011005; 05000457/2011005. Documents reviewed are listed in the Attachment. This LER is closed.

This event followup review constituted one sample as defined in IP 71153-05.

4OA5 Other Activities

.1 World Association of Nuclear Operators Plant Assessment Report Review

a. Inspection Scope

The inspectors reviewed the results of a World Association of Nuclear Operators (WANO) evaluation and inspection completed on December 6, 2011. The inspection and evaluation activities did not identify any additional safety-significant or risk-significant issues not previously identified by the NRC or the licensee.

b. Findings

No findings were identified.

.2 Temporary Instruction 2515/182 - Review of the Industry Initiative to Control Degradation

of Underground Piping and Tanks

a. Inspection Scope

Leakage from buried and underground piping has resulted in ground water contamination incidents with associated heightened NRC and public interest. The industry issued a guidance document, NEI 09-14, Guideline for the Management of Buried Piping Integrity, (ADAMS Accession No. ML1030901420) to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, NEI issued Revision 1 to NEI 09-14, Guidance for the Management of Underground Piping and Tank Integrity, (ADAMS Accession No. ML110700122), with an expanded scope of components which included underground piping that was not in direct contact with the soil and underground tanks. On November 17, 2011, the NRC issued Temporary Instruction (TI) 2515/182, Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to gather information related to the industrys implementation of this initiative.

The inspectors reviewed the licensees programs for buried piping, underground piping and tanks in accordance with TI 2515/182 to determine if the program attributes and completion dates identified in Sections 3.3 A and 3.3 B of NEI 09-14, Revision 1, were contained in the licensees program and implementing procedures. For the buried piping and underground piping program attributes with completion dates that had passed, the inspectors reviewed records to determine if the attribute was, in fact, complete and to determine if the attribute was accomplished in a manner which reflected good or poor practices in program management.

Based upon the scope of the review described above, Phase I of TI-2515/182 was completed.

b. Observations The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraphs 03.01.a through 03.01.c of TI-2515/182 and was found to meet all applicable aspects of NEI 09-14, Revision 1, as set forth in Table 1 of the TI.

c. Findings

No findings were identified.

.3 (Update) Verification of Margin-to-Overfill Backfit Corrective Actions and Extent of

Condition Review: (VIOLATION 05000456/2011010-01; 05000457/2011010-01, Restoring Compliance with Respect to Single Failures)

On February 1, 2011, the NRC issued IR 05000456/2011009; 05000457/2011009, and notified the licensee of the agencys decision to issue a compliance backfit in order to address the Steam Generator Tube Rupture (SGTR) Margin-to-Overfill (MTO) issue documented in URI 05000456/2011009-01; 05000457/2011009-01. The report listed the licensees initial corrective actions and requested the licensee provide a written response within 30 days of their assessment of the issue and a description of their intended actions to address the non-compliance, including a proposed schedule to complete those actions and an assessment of the extent of condition of this issue.

As documented in IR 05000456/2011010; 05000457/2011010, the licensee responded by letter dated March 2, 2011, and committed to the following:

The power supplies to the Steam Generators Power-Operated Relief Valves (PORVs) will be modified with a safety-related battery backup.

The licensee will issue a supplement to their March 2, 2011, response letter, in order to communicate any revisions to the modification installation schedule based on the online/outage determination.

An extent of condition review will be conducted of other transients and accidents outlined in Chapter 15 of the Braidwood UFSAR to identify similar discrepancies with respect to the inappropriate reliance or assumption of single active failure.

The identified discrepancies, if any, would be resolved within the CAP and communicated to the NRC Region III Regional Administrator.

The technical issue was considered open pending completion of the corrective actions.

During this inspection, the inspectors reviewed the licensees extent of condition review, UFSAR Chapter 15 accident analysis and Reactor Protection System (RPS) description, logic diagrams, and schematic and wiring drawings. The inspectors determined the extent of condition was adequately scoped and involved a multi-discipline review.

Concerns identified during the effort were entered into the CAP. No additional single failure vulnerabilities were identified. The inspectors had no concerns with the extent of condition review. The inspectors also performed an independent review of the RPS system because the term, single active failure was used several times in the UFSAR and other licensing documents. The inspectors did not identify any concerns with single failure vulnerabilities during this review.

Based on the above review, the inspectors concluded the licensees extent of condition review appeared to be adequate. This issue will remain open pending verification that the proposed PORV power supply modifications were successfully completed (VIO 05000456/2011010-01; 05000457/2011010-01, Restoring Compliance with Respect to Single Failures).

Documents reviewed are listed in the Attachment.

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 4, 2012, the inspectors presented the inspection results to the Plant Manager, Mr. M. Kanavos, and other members of the licensees staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of TI 2515/182, Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, with the Site Vice President, Mr. Dan Enright, and other members of the licensees staff on February 29, 2012; and

• The results of the Verification of Margin-to-Overfill Backfit Corrective Actions and Extent of Condition Review with Mr. Dan Enright and other members of the licensees staff on April 13, 2012.

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

D. Enright, Site Vice President

M. Kanavos, Plant Manager

P. Boyle, Maintenance Director

A. Ferko, Engineering Director

B. Finlay, Security Manager

J. Gerrity, Emergency Preparedness Manager

M. Kramer, Business Manager

R. Leasure, Radiation Protection Manager

M. Marchionda-Palmer, Operations Director

J. Odeen, Project Management Manager

D. Palmer, Radiation Protection Superintendent

J. Rappeport, Chemistry Manager

D. Stiles, Operations Training Manager

M. Trusheim, Outage Manager

C. VanDenburg, Regulatory Assurance Manager

R. Radulovich, Acting Regulatory Assurance Manager

Nuclear Regulatory Commission

E. Duncan, Chief, Reactor Projects Branch 3

Attachment

LIST OF ITEMS

Opened and Closed

05000456/2012002-01 NCV Failure to Maintain Approved Fire Protection Program

05000457/2012002-01 Regarding Safe Shutdown Fire Damper Qualification (Section 1R05.1.b)

05000456/2012002-02 NCV Failure to Promptly Correct Conditions Adverse to Quality

05000457/2012002-02 (Section 1R06.1.b)

05000456/2012002-03 NCV Failure to Scope Safety-Related HELB Barriers Into the

05000457/2012002-03 Maintenance Rule (Section 1R12.1.b.1)

05000456/2012002-05 NCV Incorrect Classification of Environmental Qualification Zones

05000457/2012002-05 (Section 1R15.1.b.1)

Opened

05000456/2012002-04 URI Maintenance Rule Performance Monitoring of HELB

05000457/2012002-04 Dampers (Section 1R12.1.b.2)

05000456/2012002-06 URI Inadequate Safety-Related 4kV Undervoltage Protection

05000457/2012002-06 (Section 1R15.1.b.2)

Closed

05000456/2011004-02 URI Use of Mesh Strainer Bags in Auxiliary Building Floor Drains

05000457/2011004-02 (Section 1R06.1.b)

05000457/2010-004-00 LER Unplanned Limiting Condition for Operation Entry Due to Low Header Pressure on the 2B Essential Service Water Pump (Section 4OA3.1)

05000456/2011-001-00 LER Through Wall Crack on 1A Safety Injection Pump Discharge Line Due to Outside Diameter (Transgranular) Stress Corrosion Cracking Initiated at External Diameter of Pipe (Section 4OA3.2)

05000456/2011-004-00 LER Historic Input Errors Identified in High Energy Line Break

05000457/2011-004-00 Analyses for Turbine Building Results in Potential Unanalyzed Condition (Section 4OA3.3)

Discussed

05000456/2011010-01; VIO Restoring Compliance with Respect to Single Failures

05000457/2011010-01 (4OA5.3)

Attachment