IR 05000346/2011005

IR 05000346-11-005; 10/1/2011-12/31/2011; Davis-Besse Nuclear Power Station; Inservice Inspection Activities; Maintenance Risk Assessments and Emergent Work Control; Operability Evaluations; Post Maintenance Testing; Outage Activities...

ML12032A119
Person / Time
Site:	Davis Besse
Issue date:	01/31/2012
From:	Jamnes Cameron NRC/RGN-III/DRP/B6
To:	Allen B FirstEnergy Nuclear Operating Co
References
IR-11-005
Download: ML12032A119 (93)

Text

ary 31, 2012

SUBJECT:

DAVIS-BESSE NUCLEAR POWER STATION INTEGRATED INSPECTION REPORT 05000346/2011005

Dear Mr. Allen:

On December 31, 2011, the U. S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Davis-Besse Nuclear Power Station. The enclosed report documents the results of this inspection, which were discussed on January 10, 2012, with the Director of Site Operations, Mr. Brian Boles, 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.

Based on the results of this inspection, two NRC-identified and four self-revealed findings of very low safety significance were identified. Four of these findings were determined to also involve violations of NRC requirements. In addition, one Severity Level IV violation was also identified by the NRC. However, because of the very low safety significance and because these issues were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations (NCVs), in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of any finding or NCV, 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 the Resident Inspectors Office at the Davis-Besse Nuclear Power Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 the NRC Resident Inspector at the Davis-Besse Nuclear Power 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 document 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/

Jamnes L. Cameron, Chief Branch 6 Division of Reactor Projects Docket No. 50-346 License No. NPF-3

Enclosure:

Inspection Report 05000346/2011005 w/Attachment: Supplemental Information

REGION III==

Docket No: 50-346 License No: NPF-3 Report No: 05000346/2011005 Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Davis-Besse Nuclear Power Station Location: Oak Harbor, OH Dates: October 1, 2011, through December 31, 2011 Inspectors: D. Kimble, Senior Resident Inspector A. Wilson, Resident Inspector T. Briley, Reactor Engineer P. Cardona-Morales, Reactor Engineer T. Go, Radiation Protection Inspector M. Holmberg, Senior Reactor Inspector L. Jones, Jr., Reactor Inspector G. ODwyer, Reactor Inspector M. Mitchell, Radiation Protection Inspector J. Neurauter, Senior Reactor Inspector P. Smagacz, Reactor Engineer J. Steffes, Reactor Engineer Approved by: Jamnes L. Cameron, Chief Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000346/2011005; 10/1/2011-12/31/2011; Davis-Besse Nuclear Power

Station; Inservice Inspection Activities; Maintenance Risk Assessments and Emergent Work Control; Operability Evaluations; Post-Maintenance Testing; Outage Activities; Follow-Up of Events and Notices of Enforcement Discretion; and Other Activities.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Six Green findings and one Severity Level (SL) IV violation were identified by the inspectors. Four of the findings, as well as the SL IV violation, were dispositioned as non-cited violations (NCVs) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC (IMC) 0609,

Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a SL 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: Initiating Events

Green.

A self-revealed finding of very low safety significance was identified for the licensees failure to establish, implement, and maintain technically adequate procedures to permit the proper switching of feedwater sources for the stations auxiliary boiler, such that when the switching of feedwater sources from demineralized water to the stations normal condensate system took place per approved procedures, there were detrimental results. Specifically, the approved procedures for this activity relied upon a check valve to keep the demineralized water header from being exposed to greater pressure than its design. When that check valve failed to function as designed, failure of demineralized water system components and the inadvertent deluge and failure of safety-related electrical equipment resulted.

The finding was determined to be of more than minor significance because it was associated with the Initiating Events Cornerstone attribute of procedure quality and had adversely affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, electrical power to an entire string of safety-related 480 Vac motor control center (MCCs) (i.e., E11A, E11B, E11C, E11D, and E11E) was forced to be interrupted when a deficient procedure for the operation of the stations auxiliary heating boiler caused a significant amount of water to be deluged onto MCC E11C, resulting in an electrical short and fire within the MCC. The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. Because the finding involved reactor shutdown operations and conditions, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1,

Shutdown Operations Significance Determination Process - Phase 1 Operational Checklists for Both PWRs and BWRs. Since the finding was associated with an issue that occurred during the time the licensee was in a cold shutdown (Mode 5) condition, the inspectors consulted Checklist 3, PWR Cold Shutdown and Refueling Operation:

Reactor Coolant System (RCS) Open and Refueling Cavity Level Less Than 23 Feet or

RCS Closed and No Inventory in the Pressurizer; Time to Boiling Less Than 2 Hours.

The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis. Consequently, the finding was determined to be of very low safety significance. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program (CAP)component, because the licensee did not take appropriate corrective actions to address the safety issue in a timely manner, commensurate with the safety significance and complexity. Specifically, the licensee had multiple previous opportunities to have appropriately diagnosed and corrected the issue, but failed to do so. (P.1(d))

(Section 4OA3.2)

Green.

A finding of very low safety significance and an associated NCV of 10 CFR 50,

Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, were identified by the inspectors for the licensees failure to perform an adequate review of fabrication records to ensure material procured from a contractor (replaced reactor vessel closure head) met the construction code (CC). Specifically, the accessible surfaces of the 60 closure head flange stud holes were not subjected to dye penetrant or magnetic particle examinations as required by the CC. As a corrective action, the licensee completed magnetic particle examination of the accessible surfaces of the 60 flange stud holes prior to placing the vessel head into service.

The finding was determined to be more than minor because it was associated with the Initiating Events Cornerstone attribute of Equipment Performance and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Absent NRC identification, the licensee would not have completed surface examination of the 60 flange stud holes to ensure unacceptable material flaws (e.g., cracks) were not placed in service. Because material flaws such as cracks serve as stress risers that reduce the ability of the replacement reactor vessel closure head to withstand failure by crack propagation during design basis events (e.g.,

pressurized thermal shock), they would place the reactor coolant system at an increased risk for through-wall leakage and/or failure. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Initiating Events Cornerstone. Because this finding was identified prior to placing the replacement reactor vessel closure head in service and no fabrication flaws were identified, the inspectors answered no to the SDP Phase 1 screening question Assuming worst case degradation, would the finding result in exceeding the Technical Specification (TS) limit for any reactor coolant system leakage or could the finding have likely affected other mitigation systems resulting in a total loss of their safety function assuming the worst case degradation? Therefore, the finding screened as having very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Decision Making because the licensee staff failed to demonstrate that nuclear safety was an overriding priority in decisions affecting the replacement reactor vessel closure head. Specifically, the failure to perform an adequate review of the replacement reactor vessel closure head fabrication records was caused by the licensees decision to not review the manufacturers interpretations and application of the CC rules. (H.1(b)) (Section 4OA5.3).

Cornerstone: Mitigating Systems

Green.

A self-revealed finding of very low safety significance (Green) was identified when low pressure injection equipment was damaged by operators attempting to access an overhead valve. Specifically, by climbing and standing on sensitive plant equipment, the licensee failed to comply with the standards and expectations for accessing plant equipment contained in procedure NOP-OP-1002, Conduct of Operations. An immediate corrective action was taken to repair the damaged temperature element and restore low pressure injection pump no. 1 to operable status. A long-term solution to providing access to the overhead valve is under evaluation in the corrective action program.

The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Human Performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the damage caused when falling from plant equipment rendered low pressure injection train 1 inoperable. The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, using the Phase 1 SDP worksheet for the Mitigating Systems Cornerstone. The finding screened as very low safety significance because the inspectors answered no to the screening questions in Table 4a. Specifically, the finding was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent actual loss of safety function of a single train for greater than its TS allowed outage time, and the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This finding had a cross-cutting aspect in the area of Human Performance, Work Control Component, because the licensee did not plan and coordinate work activities consistent with nuclear safety.

Specifically, the licensee did not appropriately plan for job site conditions impacting human performance since an appropriate available method for accessing CC258 was not evaluated. (H.3(a)) (Section 1R13.1)

Green.

A finding of very low safety significance and an associated NCV of TS 5.4.1(a)were identified by the inspectors for the licensees failure to establish, implement, and maintain technically adequate procedures to cover the restoration (i.e., filling and venting) of the component cooling water (CCW) system following maintenance activities.

Specifically, a complex series of fill and venting evolutions to restore the system had been required following extensive maintenance activities; these evolutions did not ensure that all the air was vented from the system, such that later ultrasonic testing performed by the licensee identified a significant air void, approximately 19 cubic feet, in a CCW pump 3 horizontal suction piping segment. The issue was entered into the licensees CAP as CRs 2011-05542 and 2011-05831.

The finding was determined to be of more than minor safety significance because the issue was associated with the Mitigating Systems Cornerstone attribute of procedure quality, and had adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, CCW, a mitigating system, had its reliability adversely impacted by the lack of appropriate fill and venting procedural guidance. The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1

- Initial Screening and Characterization of Findings. Because the finding involved reactor shutdown operations and conditions, the inspectors transitioned to IMC 0609,

Appendix G, Attachment 1, Shutdown Operations Significance Determination Process - Phase 1 Operational Checklists for Both PWRs and BWRs. Since the finding was associated with an issue that occurred during the time the licensee was conducting RCS fill and venting activities and plant conditions were in transition, the inspectors consulted both Checklist 2, PWR Cold Shutdown Operation: RCS Closed and Steam Generators Available for Decay Heat Removal (Loops Filled and Inventory in the Pressurizer); Time to Boiling Less Than 2 Hours, and Checklist 3, PWR Cold Shutdown and Refueling Operation: RCS Open and Refueling Cavity Level Less Than 23 Feet or RCS Closed and No Inventory in the Pressurizer; Time to Boiling Less Than 2 Hours. The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes on either checklist, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis.

Consequently, the finding was determined to be of very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Resources component, because the licensee did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the licensees procedures and guidance for the restoration of the CCW system following outage maintenance activities did not ensure that the system was fully filled and properly vented prior to operation. (H.2(c)) (Section 1R15.1)

• Severity Level IV. The inspectors identified a SL IV NCV of 10 CFR 54(i) when a non-licensed member of the licensees engineering staff was observed operating switches that directly caused the insertion of various control rods that were being subjected to timing tests. Specifically, the inspectors observed that key switches used to interrupt power to the control rod drives and cause control rod insertion were manipulated by a member of the licensees engineering staff, and not a licensed individual. The issue was entered into the licensees CAP as CR 2011-06318.

The issue was determined to be associated with the Mitigating Systems Cornerstone attribute of procedure quality. However, the inspectors subsequently determined that the issue had not adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because of several factors, the inspectors determined that the issue was of minor safety significance and, as such, did not constitute a finding. These factors included:

• All control rod group withdrawal activities were accomplished from the control room by an on-watch licensed reactor operator;

• All activities in the electrical penetration room were performed in accordance with an approved written test procedure, and under the direct supervision of a licensed Senior Reactor Operator;

• The operation of the local key switches in the electrical penetration room, albeit by a non-licensed individual, could only cause control rod insertion. There was no withdrawal capability; and

• The individual operating the local key switches in the electrical penetration room was always in continuous communication with the on-watch licensed reactor operator in the control room.

The inspectors determined that the issue was subject to the NRCs traditional enforcement process as an issue that had the potential to impact the agencys ability to perform its regulatory function. Specifically, the NRCs Reactor Oversight Process fundamentally assumes that only duly licensed individuals are allowed to manipulate reactor controls and alter core reactivity or make changes to reactor power, and that all licensed individuals perform their licensed duties in accordance with any restrictions associated with their individual licenses. The inspectors conferred with NRC Region III management and members of the enforcement staff and determined that, because of the factors noted above, the issue constituted a SL IV violation that resulted in no, or relatively inappreciable, safety consequences. Because this issue was dispositioned through the traditional enforcement process and had no Reactor Oversight Process aspects, there was no cross-cutting aspect associated with the violation.

(Section 1R19.1)

Green.

A finding of very low safety significance and an associated NCV of TS 5.4.1(a)were identified by the inspectors for the licensees failure to establish, implement, and maintain technically adequate procedures and drawings to cover the restoration (i.e.,

motor controller re-energization) of components in the CCW system following maintenance activities. Specifically, as circuit breaker BE1161 was closed to restore power to motor-operated valve (MOV) CC2645, the train 1 auxiliary building return header isolation valve, the MOV unexpectedly stroked open resulting in a rapid loss of CCW system inventory and a low level alarm for the CCW surge tank. Subsequent investigation revealed that notes describing the operating logic for CC2645 on approved operational drawings were less than adequate. The issue was entered into the licensees CAP as CR 2011-04078.

The finding was determined to be of more than minor safety significance because the issue was associated with the Mitigating Systems Cornerstone attribute of procedure quality, and had adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, CCW, a mitigating system, had its reliability adversely impacted by the inadequate procedural guidance for motor controller restoration. The inspectors evaluated the finding using IMC 0609, Attachment 4,

Phase 1 - Initial Screening and Characterization of Findings. Because the finding involved reactor shutdown operations and conditions, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process - Phase 1 Operational Checklists for Both PWRs and BWRs. Since the finding was associated with an issue that occurred during the time the reactor was in a defueled condition, the inspectors conservatively consulted all four PWR checklists (i.e.,

Checklists 1 - 4). The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes on any checklist, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis.

Consequently, the finding was determined to be of very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Resources component, because the licensee did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the licensees procedures, drawings and guidance for the restoration of the CCW system following outage maintenance activities did not ensure that the system was properly aligned prior to restoration of electrical power to MOV CC2645. (H.2(c))

(Section 1R20.1)

Cornerstone: Barrier Integrity

Green.

A finding of very low safety significance and an associated NCV of 10 CFR 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings were identified by the inspectors for the licensees failure to control weld rod oven temperature in accordance with procedure WFMC-1 during a rebar splice weld completed for restoration of the shield building access opening. As a corrective action, the licensee removed the welders certification to weld rebar and documented this issue in CR 2011-05536. To ensure that the horizontal rebar splice weld 2H-03R was not affected by delayed hydrogen cracking, the licensees vendor examined the weld splice 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after fabrication and did not identify cracks.

The finding was determined to be more than minor because the finding was associated with the Barrier Integrity Cornerstone attribute of Configuration Control and adversely affected the cornerstone objective to provide reasonable assurance that the physical design barriers (e.g., containment) protect the public from radionuclide releases caused by accidents or events. The shield building is part of the containment system. Absent NRC identification, rebar welds would have been fabricated with electrodes exposed to ambient temperatures for excessive periods of time creating a condition that results in hydrogen-induced weld cracking. Rebar splice material with cracks returned to service would increase risk for shield building failure during design basis events such as wind-driven missile impact or earthquake-induced loads. The inspectors completed a significance determination, in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Containment Barrier. Because the issue was corrected promptly, prior to introduction of weld material with hydrogen-induced cracks, the inspectors answered no to each of the four Phase 1 screening questions. Therefore, the finding screened as having very low safety significance. This finding had a cross-cutting aspect in the area of Human Performance, Work Practices because the licensee did not provide adequate supervisory and management oversight of work activities including contractors such that nuclear safety was supported. Specifically, the failure to control the weld rod oven temperature in accordance with procedure WFMC-1 was caused by inadequate licensee oversight of the contracted welder. (H.4(c))

(Section 1R08.1).

Licensee-Identified Violations

No violations were identified.

REPORT DETAILS

Summary of Plant Status

At midnight on September 30/October 1, 2011, the main generator output breakers were opened and the unit was taken offline for mid-cycle outage 17M to facilitate replacement of the reactor vessel closure head. On December 5, 2011, the reactor was restarted and criticality achieved. The unit was synchronized to the main electrical grid and the main generator output breakers were closed on December 6, 2011. The unit reached full power operation 2 days later, on December 8, 2011, and remained operating at or near full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

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

• Ultimate heat sink; and

• Borated water storage tank and associated piping.

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

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Alignment Verifications

a. Inspection Scope

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

• Service water train 1 in Mode 5 when lined up to support shutdown operations during the week ending November 19, 2011; and

• Emergency diesel generator (EDG) no. 2 when EDG no. 1 was unavailable for planned testing during the week ending December 24, 2011.

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, USAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports (CRs), 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 to this report.

These activities constituted two partial system alignment verification samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Alignment Verification

a. Inspection Scope

During the week ending December 10, 2011, the inspectors performed a complete system alignment inspection of the decay heat/low pressure injection 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 mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, 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 to this report.

These activities constituted one complete system alignment verification sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Quarterly Tours

a. Inspection Scope

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

• Containment Elevation 565 (Room 217, Fire Area D);

• Containment Elevation 603 (Rooms 407 and 410, Fire Area D);

• Containment Elevation 636 (Room 580, Fire Area D); and

• Containment Elevation 643 (Rooms 700 and 701, Fire Area D).

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 (IPEEE) 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 to this report.

These activities constituted four quarterly fire protection inspection samples as defined in IP 71111.05-05. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

.1 Annual Heat Sink Performance Review

a. Inspection Scope

The inspectors reviewed the licensees testing of the spent fuel pool heat exchangers to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. Inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing conditions. Documents reviewed for this inspection are listed in the Attachment to this document.

This annual heat sink performance review constituted a single inspection sample as defined in IP 71111.07-05.

b. Findings

No findings were identified.

.2 Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors reviewed operability determinations, completed surveillances, vendor manual information, associated calculations, performance test results and cooler inspection results associated with the Component Cooling Water (CCW) heat exchanger number E22-3. This heat exchanger was chosen based on its risk significance in the licensees probabilistic safety analysis, its important safety-related mitigating system support functions, its operating history, and its relatively low margin.

The inspectors verified that testing, inspection, maintenance, and monitoring of biotic fouling and macrofouling programs were adequate to ensure proper heat transfer. This was accomplished by verifying the test method used was consistent with accepted industry practices, or equivalent, the test conditions were consistent with the selected methodology, the test acceptance criteria were consistent with the design basis values, and results of heat exchanger performance testing. The inspectors also verified that the test results appropriately considered differences between testing conditions and design conditions, the frequency of testing based on trending of test results was sufficient to detect degradation prior to loss of heat removal capabilities below design basis values and test results considered test instrument inaccuracies and differences.

The inspectors reviewed the methods and results of heat exchanger performance inspections. The inspectors verified the methods used to inspect and clean heat exchangers were consistent with as-found conditions identified and expected degradation trends and industry standards, the licensees inspection and cleaning activities had established acceptance criteria consistent with industry standards, and the as-found results were recorded, evaluated, and appropriately dispositioned such that the as-left condition was acceptable.

In addition, the inspectors verified the condition and operation of the CCW heat exchanger number E22-3 were consistent with design assumptions in heat transfer calculations and as described in the final safety analysis report. This included verification that the number of plugged tubes was within pre-established limits based on capacity and heat transfer assumptions. The inspectors verified the licensee evaluated the potential for water hammer and established adequate controls and operational limits to prevent heat exchanger degradation due to excessive flow-induced vibration during operation. In addition, eddy current test reports and visual inspection records were reviewed to determine the structural integrity of the heat exchanger.

The inspectors verified the performance of ultimate heat sinks (UHS) and safety-related service water systems and their subcomponents such as piping, intake screens, pumps, valves, etc. by tests or other equivalent methods to ensure availability and accessibility to the inplant cooling water systems.

The inspectors reviewed the results of the licensees inspection of the UHS weirs or excavations. The inspectors verified that identified settlement or movement indicating loss of structural integrity and/or capacity was appropriately evaluated and dispositioned by the licensee. In addition, the inspectors verified the licensee ensured sufficient reservoir capacity by trending and removing debris or sediment buildup in the UHS.

The inspectors reviewed the licensees operation of service water system and UHS.

This included the review of licensees procedures for a loss of the service water system or UHS and the verification that instrumentation, which is relied upon for decision making, was available and functional. In addition, the inspectors verified that macrofouling was adequately monitored, trended, and controlled by the licensee to prevent clogging. The inspectors verified that licensees biocide treatments for biotic control were adequately conducted and the results monitored, trended, and evaluated.

The inspectors also reviewed strong pump-weak pump interaction and design changes to the service water system and the UHS. The inspectors also verified that the licensee maintained adequate pH, calcium hardness, etc.

In addition, the inspectors reviewed condition reports related to the heat exchangers/coolers and heat sink performance issues to verify that the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of the corrective actions. The documents that were reviewed are included in the to this report.

These inspection activities constituted two heat sink inspection samples as defined in IP 71111.07 05.

b. Findings

No findings of significance were identified. Section 4OA2 documents a review of the licensees assessment of the as-found condition of the intake canal.

1R08 Inservice Inspection Activities

From October 11, 2011, through November 23, 2011, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system (RCS), steam generator (SG) tubes, emergency feedwater (FW) systems, risk-significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, R08.3, IR08.4, and 1R08.5 below were completed in accordance with IP 71111.08. A full inspection sample was not available during this outage, so the reviews under Section 1R08.4 are considered incomplete. Additional reviews to complete this procedure will be documented in a future inspection report. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

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

• Ultrasonic examination (UT) of the pressurizer nozzle-to-lower head weld (RC-PZR-WP-15);

• Dye penetrant (PT) examination of pipe-to-valve weld (MU-31-CCA-18-1-FW23);

• UT of reactor vessel shell-to-lower head weld no. 4.; and

• UT of reactor vessel nozzle-to-shell weld no. 11.

The inspectors reviewed the following examination records (volumetric or surface) with recordable indications accepted for continued service to determine if acceptance was in accordance with the ASME Code Section XI or an NRC approved alternative:

• PT examination report no. 17-PT-011, valve HP92- to-pipe weld.

The inspectors observed the following welds completed for risk significant systems during the outage to determine if the licensee applied the preservice non-destructive examinations and acceptance criteria required by the construction code (CC).

Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of CC, the ASME Code Section IX and the American Welding Society (AWS) D.1.4 Code:

• Containment access door closure weld FW-1;

• Beam (stiffener)-to-containment plate weld FW-1; and

• Splice welds of shield building (SB) rebar joints 2H-03R and 2V-45B.

b. Findings

Inadequate Control of Weld Filler Metal Electrodes Introduction A finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, were identified by the inspectors for the licensees failure to control weld rod oven temperature in accordance with procedure WFMC-1 during a rebar splice weld completed for restoration of the SB access opening.

Description The inspectors identified that the portable weld rod oven temperature had not been maintained above the minimum required temperature of 250 degrees Fahrenheit (deg F).

The inspectors were concerned that if this practice had continued, it would increase the possibility for rebar splice weld failure due to hydrogen-induced cracking.

The coatings of shielded metal arc welding (SMAW) electrodes used for steel (especially low-hydrogen electrodes) readily absorb moisture (i.e., hydroscopic). Water present in the electrode coating, breaks down into hydrogen and oxygen within the welding arc.

The hydrogen becomes entrained in the weld metal and as the metal cools, it undergoes a phase transformation from an austenitic to a martensitic structure. From 400 deg F to room temperature, some of the retained austenite changes slowly into martensite (delayed transformation). During this delayed transformation, the monatomic hydrogen has limited solubility and recombines into hydrogen gas causing metal microcracks and fissures. These defects may appear in the weld, at the weld interface, or in the parent metal, depending on how the hydrogen moves or where it becomes trapped and results in delayed hydrogen induced cracks and weld porosity. Because detection of hydrogen-induced cracks is difficult and may not be found until after a weld is placed into service, the controls used to prevent introduction of hydrogen are critical for fabrication of acceptable welds. To prevent introduction of hydrogen, the controls for storage of low-hydrogen electrodes are designed to preclude moisture absorption by the use of hermetically-sealed containers (e.g. shipping package from manufacturer) or by the use of ovens maintained at elevated temperatures to keep the electrode coating dry.

For the low-hydrogen electrodes used to fabricate rebar splices in the restoration of the SB, the licensees contractor provided for the control of the low-hydrogen electrodes in procedure WFMC-1 Bechtel Welding Specification Welding Filler Material Control.

This procedure required the use of portable rod warmers maintained at a minimum temperature of 250 deg F for storage of low-hydrogen electrodes to ensure that the hydroscopic coating of the welding electrode stayed dry and did not absorb moisture from the atmosphere.

During fabrication of a horizontal rebar splice weld 2H-03R, the inspectors observed that the low-hydrogen electrode filler material was protruding several inches above the top of the welders portable rod storage oven (e.g. top of oven was open). The inspectors requested the welder verify that the portable oven was at or above the minimum required temperature of 250 deg F. The welder applied a temperature crayon designed to melt at 200 deg F to the oven at the inside surface of the top lid, to the oven inner wall, and at several points on the removable filler metal storage rack. The temperature crayon did not melt at any of these locations. The welder then removed a single weld electrode and applied the temperature crayon at locations along the weld electrode and was able to get the crayon to melt on the bottom 1/4 length of the electrode (portion nearest the bottom of the oven). These measurements demonstrated that the oven temperature had not been maintained above 250 deg F as required by the procedure WFMC-1.

As a corrective action, the licensee removed the welders certification to weld rebar and documented this issue in CR 2011-05536. The welder who fabricated weld 2H-03R was assigned three additional welds, and absent NRC intervention, these welds would likely have been fabricated with electrodes exposed to ambient temperature conditions for more than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. A 1-hour time limit outside the warming oven was the maximum allowed by procedure WFMC-1 and AWS D1.4 Structural Welding Code - Reinforcing Steel for the E-9018-B3H4R electrode material used on weld 2H-03R to ensure moisture was not absorbed from the atmosphere. To ensure that the horizontal rebar splice weld 2H-03R was not affected by delayed hydrogen cracking, the licensees vendor examined the weld splice 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after fabrication and did not identify cracks.

Analysis The inspectors determined that the licensees failure to control weld rod oven temperature in accordance with procedure WFMC-1 is contrary to 10 CFR 50 Appendix B, Criterion V, and a performance deficiency.

The finding was determined to be more than minor because the finding was associated with the Barrier Integrity Cornerstone attribute of Configuration Control and adversely affected the cornerstone objective to provide reasonable assurance that the physical design barriers (e.g. containment) protect the public from radionuclide releases caused by accidents or events. The SB is part of the containment system. Absent NRC identification, rebar welds would have been fabricated with electrodes exposed to ambient temperatures for excessive periods of time creating a condition that results in hydrogen-induced weld cracking. Rebar splice material with cracks returned to service would increase risk for SB failure during design basis events such as wind-driven missile impact or earthquake-induced loads. The inspectors completed a significance determination, in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Containment Barrier. Because the issue was corrected promptly, prior to introduction of weld material with hydrogen induced cracks, the inspectors answered no to each of the four Phase 1 screening questions.

Therefore, the finding screened as having very low safety significance (Green).

This finding had a cross-cutting aspect in the area of Human Performance, Work Practices because the licensee did not provide adequate supervisory and management oversight of work activities including contractors such that nuclear safety was supported.

Specifically, the failure to control the weld rod oven temperature in accordance with procedure WFMC-1 was caused by inadequate licensee oversight of the contracted welder (IMC 0310 - Item H.4(c)). The inspector determined that this was the cause of the finding based upon discussions with licensee and vendor staff.

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

Procedure WFMC-1, Bechtel Welding Specification Welding Filler Material Control, Revision 0, required; in Paragraph 6.1.2.2 that: The oven shall be held at a minimum of 250 deg F and a maximum of 350 deg F, and in Paragraph 7.5 that: The portable rod warmers shall maintain a minimum temperature of 250 deg F and in Table 1 for use of All Low-Hydrogen Electrodes to Issue in portable warmers maintained at 250 deg F minimum.

Contrary to the above, on November 16, 2011, for an activity affecting quality (weld rod oven temperature) the licensee failed to accomplish the activity in accordance with the applicable procedure WFMC-1. Specifically, the licensee failed to maintain a portable rod warmer oven containing low-hydrogen electrode weld material above the minimum required temperature of 250 deg F. Because of the very low safety significance of this finding and because the issue was entered into the licensees CAP (CR 2011-05536), it is being treated as a non-cited violation (NCV), consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000346/2011005-01)

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

The vessel head penetration nozzles and J-groove welds of the inservice head had been affected by primary water stress corrosion cracking (PWSCC) and repaired during the previous outage (reference NRC Inspection Report (IR) 05000346/2010008 - Adams Accession No. ML102930380). For the No. 17 mid-cycle outage, the in-service head was removed to an on-site storage location pending off-site disposal and thus did not require further non-destructive examination. The licensee procured a replacement reactor vessel closure head (RRVCH) with penetration nozzles and J-groove welds fabricated with materials (e.g., Alloy 690) more resistant to PWSCC.

For the RRVCH a bare metal visual pre-service examination and a non-visual pre-service examination was required pursuant to 10 CFR 50.55a(g)(6)(ii)(D) and Code Case N-729-1. The inspectors had previously completed the review of the non-visual preservice examination records for the replacement head as documented in NRC IR 05000346/2011004 (Adams Accession No. ML112991544).

For the pre-service visual examinations of the RRVCH the inspectors observed and reviewed records of the visual examination conducted on the vessel head at penetrations 1, 3, 54, and 61 to determine if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed that:

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

• The licensee criteria for visual examination quality and instructions for resolving interference and masking issues were adequate; and

• That the visual examination procedure required recording indications of potential through-wall leakage and that licensee documented relevant conditions in the corrective action system and implemented appropriate corrective actions.

Prior to the mid-cycle outage, the inspectors observed a welded repair/replacement activity associated with installation of a vent assembly on the upper head penetration of the RRVCH at nozzle No. 21 as documented in NRC IR 05000346/2011004 (Adams Accession No. ML112991544).

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors performed an independent walkdown of portions of the reactor coolant system and attached safety-related systems which had received a boric acid walkdown by the licensee staff to determine whether the licensees Boric Acid Corrosion Control (BACC) visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components and to determine if degraded conditions were entered into the CAP.

The inspectors reviewed the following evaluations of reactor coolant system or other safety-related systems with components affected by boric acid to determine if the licensee applied appropriate corrosion rates and properly assessed the effects of corrosion-induced wastage on the components structural or pressure boundary integrity:

• CR 2010-74892, reactor coolant pump 1-2-2 boric acid;

• CR 2010-79012, high pressure injection (HPI) pump 2P58-2 boric acid; and

• CR 2011-94103, spent fuel pool pump 1-2 seal leak.

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

• CR 2010-78548, leak at DH 22A packing;

• CR 2010-73653, leak at DH-11 packing; and

• CR 2010-76667, leak at SF-35 packing.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

Steam Generator tube eddy current (ET) examinations were not required during the No. 17 mid-cycle outage pursuant to TS 3.4.17 Steam Generator Tube Integrity, and TS 5.5.8 Steam Generator Program. Therefore, the licensee did not conduct SG tube examinations and only a portion of the NRC IP could be completed for this review area.

Specifically, from October 11, 2011, through November 23, 2011, the inspectors performed an on-site review of documentation related to the SG ISI program to determine if:

• Primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons per day or the detection threshold during the previous operating cycle.

Completion of Section 02.04 of IP 71111.08 is scheduled to be completed during the Spring 2012 refueling outage when the licensee will perform ET of the SG tubes.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

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

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

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

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

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

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:

• Auxiliary building and SB structures; and

• Containment systems.

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

• Implementing appropriate work practices;

• Identifying and addressing common cause failures;

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

• Characterizing system reliability issues for performance;

• Charging unavailability for performance;

• Trending key parameters for condition monitoring;

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

• Verifying appropriate performance criteria for structures, systems, and components (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 to this report.

The inspectors maintenance effectiveness reviews constituted two quarterly inspection samples as defined in IP 71111.12-05. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Work activities during the week ending October 8, 2011, which included a period of yellow shutdown risk during the time that the RCS was drained to reduced inventory conditions. Other activities included the lift and movement of the reactor vessel head from the reactor vessel to the containment storage stand;

• Emergent work associated with cracking identified in the containment SB during the 17M mid-cycle reactor head replacement outage, as documented in CR 2011-03346 and other entries into the licensees CAP; and

• Emergent repairs associated with damage to decay heat pump 1-1 during the week ending December 24, 2011, as documented in CR 2011-07195.

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.

Specific documents reviewed during this inspection are listed in the Attachment to this report. These maintenance risk assessments and emergent work control activities constituted three inspection samples as defined in IP 71111.13-05. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

Decay Heat Pump 1-1 Damaged and Rendered Inoperable By Personnel Climbing on Equipment Introduction A self-revealed finding of very low safety significance (Green) was identified when low pressure injection equipment was damaged by operators attempting to access an overhead valve. Specifically, by climbing and standing on sensitive plant equipment, the licensee failed to comply with the standards and expectations for accessing plant equipment contained in procedure NOP-OP-1002, Conduct of Operations.

Description On the morning of December 22, 2011, the plant was performing DB-PF-03071, CCW Check Valve Testing. Performance of this test requires an operator to manipulate CC258, CCW Essential Line 1 to Makeup Pump 1 Isolation Valve. The location of this valve makes it difficult for an operator to gain access. The valve is approximately 12 feet off the floor, amidst overhead interferences, and is located directly above the motor for decay heat removal pump no. 1. A convenient way to access the valve was not readily available when CC258 was required to be closed and opened during the performance of the CCW check valve test. The operator attempting to perform the task determined the most practical method to access the valve was to climb up plant equipment and position himself standing on the top of the decay heat pump motor. The first time the valve was accessed, the operator chose the more open, north, side of the motor. This proved difficult, though the operator was able to make the climb and perform the valve manipulation without event. The operator lowered himself from the motor on the east side, which contained more sensitive equipment, but had more hand and foot holds that made it easier to climb down. For the second time accessing CC258, the operator attempted to climb up the side he had just descended (east), despite the proximity to more sensitive equipment. Upon climbing the motor the second time, the operators hand slipped causing a fall of approximately 3 feet. The operator landed on his feet, however, during the fall the operator came into contact with the oil temperature probe for the decay heat motor outboard bearing. The temperature element was dislodged and oil began spilling from motor out the open connection.

The loss of oil from the outboard motor bearing rendered low pressure injection pump no. 1 inoperable, causing entry into the action statement for limiting condition for Operation (LCO) 3.5.2.A, which has a 7-day completion time for restoring the system to an operable status. The temperature element was repaired; and the system was restored in the afternoon of December 22, 2011, after being out-of-service for approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />.

The inspectors reviewed the standards and expectations contained in Section 4.17 of NOP-OP-1002, Conduct of Operations, covering access to plant equipment. The expectation states that: Climbing on equipment is the exception and not the rule. The Conduct of Operations standards also include the following:

• Plant equipment should not be climbed upon to gain access from one location to another. Ladders and/or scaffold are used whenever possible; and

• If no other means are available, plant equipment may be climbed upon provided it does not pose a risk to the safety of personnel or equipment.

Contrary to the standards above, the operator climbed upon plant equipment (decay heat pump motor no. 1) despite the risks involved to personnel safety and equipment safety. An alternate method for accessing CC258 was not addressed in the pre-job brief for the CCW check valve test. A ladder could have been used to provide safer access to the top of the motor or a scaffold addition could have provided better access to the valve itself.

The licensee included this issue in their CAP as CR 2011-07195. An immediate corrective action was taken to repair the damaged temperature element and restore low pressure injection pump no. 1 to operable status. A long-term solution to providing access to the overhead valve is under evaluation in the licensees CAP.

Analysis The inspectors reviewed this finding using the guidance contained in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Reports. The inspectors determined that the licensees failure to comply with the standards and expectations for accessing plant equipment contained in the Conduct of Operations procedure was a performance deficiency that was reasonably within the licensees ability to foresee and correct and should have been prevented. The inspectors determined that the finding was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Human Performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the damage caused when falling from plant equipment rendered low pressure injection train 1 inoperable.

The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, using the Phase 1 SDP worksheet for the mitigating systems cornerstone. The finding screened as very low safety significance (Green) because the inspectors answered no to the screening questions in Table 4a.

Specifically, the finding was not a design or qualification deficiency, did not represent a loss of system safety function, did not represent actual loss of safety function of a single train for greater than its TS allowed outage time, and the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

This finding had a cross-cutting aspect in the area of Human Performance, Work Control component, because the licensee did not plan and coordinate work activities, consistent with nuclear safety. Specifically, the licensee did not appropriately plan for job site conditions impacting human performance since an appropriate available method for accessing CC258 was not evaluated. (H.3(a))

Enforcement The inspectors concluded that the licensee did not comply with the standards and expectations for accessing plant equipment contained in procedure NOP-OP-1002, Conduct of Operations. This finding, however, did not involve a corresponding violation of NRC requirements. Specifically, the inspectors determined that the Conduct of Operations procedure is an administrative procedure, and not covered under the quality assurance (QA) requirements set forth in 10 CFR 50, Appendix B. Additionally, the inspectors also determined that the Conduct of Operations procedure is not covered under TS 5.4.1(a), which requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A.

(FIN 05000346/2011005-02)

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• The functionality of the containment SB and operability of the plants containment system following identification of cracking in the SB concrete, as documented in CR 2011-03346 and other related entries in licensees CAP;

• The operability of the plants safety-related station batteries and direct current (DC) electrical distribution systems following identification of loading issues, as documented in CR 2011-01902;

• The functionality and operability of the CCW system following the unexpected drop in CCW surge tank level, as documented in CR 2011-05542; and

• The functionality and operability of the service water (SW) system following issues associated with the balancing of SW train no. 2 safety-related flows after maintenance, as documented in CR 2011-05526.

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 USAR 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 to this report.

The inspectors reviews of these operability and functionality evaluations constituted four inspection samples as defined in IP 71111.15-05. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

Air Voids in Component Cooling Water System Caused By Inadequate Fill and Vent Procedure Introduction A self-revealed finding of very low safety significance (Green) and an associated NCV of TS 5.4.1(a) were identified for the licensees failure to establish, implement, and maintain technically adequate procedures to cover the restoration (i.e., filling and venting) of the CCW system following maintenance activities.

Description In the early morning hours of November 17, 2011, the plant was in Mode 5, cold shutdown. A heightened shutdown safety awareness condition (i.e., yellow risk) was in effect due to the plant having a reduced capacity for decay heat removal until activities to fill and vent the RCS were completed. These RCS filling and venting procedures were in progress.

At approximately 0120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br />, the on-watch control room crew received an unexpected annunciator alarm, 11-3-A, which indicated a low level in the CCW surge tank. The crew entered DB-OP-02011, Heat Sink Alarm Panel 11 Annunciators, and cut in demineralized water to the CCW system to retard the drop in surge tank level in accordance with the procedure. CCW surge tank level was stabilized, and restored to the normal operating band in short order. The operating crew calculated that approximately 125 gallons of inventory from the CCW surge tank had been lost.

A follow-on investigation by the operating crew revealed no signs of leakage from the system, but that a chemical addition had been made to the CCW system approximately 50 minutes before the receipt of annunciator alarm 11-3-A. From this, the licensee surmised that an air bubble might have been introduced into the CCW system during the chemical addition. The chemical addition piping was a long run of approximately 300 feet that had not been used since maintenance had been conducted on the system and, if voided, could have introduced an air bubble of sufficient size to account for the drop in CCW surge tank level.

On November 18, 2011, the inspectors discussed the issue with the licensees Superintendent of Nuclear Operations, and voiced a concern regarding how the licensees procedures for restoration from maintenance activities on the CCW system could have permitted parts of the system to have air entrapped. The possibility that more sections of the CCW system could be voided was also discussed, whereupon the Superintendent of Nuclear Operations stated that the licensee would conduct additional inspections and investigation into the issue.

On November 22, 2011, UT performed by the licensee identified a significant air void, approximately 19 cubic feet, in a CCW pump 3 horizontal suction piping segment.

CCW pump 3 is a swing pump that can be lined up to take the place of either the normal train 1 CCW pump or the normal train 2 CCW pump. Component Cooling Water pump 3 was immediately declared unavailable upon identification of the air void, but because the pump was not lined up to support either train of the CCW system there was no TS implications. Extensive ultrasonic testing was performed on the rest of the CCW system, with no abnormal conditions being noted.

A follow-on investigation by licensee engineering and operations personnel revealed that the air entrapment in the CCW system was most likely due to the extensive maintenance activities on the system during the 17M mid-cycle outage. A complex series of fill and venting evolutions to restore the system had been required, and these evolutions may not have vented all of the air from the system. The licensee had entered this issue into their CAP as CRs 2011-05542 and 2011-05831. Planned corrective actions included additional procedural guidance for CCW fill and venting activities.

Analysis The inspectors determined that failure of the licensee to establish, implement, and maintain technically adequate procedures to cover the restoration (i.e., filling and venting) of the CCW system following maintenance activities was contrary to the requirements in the licensees Quality Assurance Program Manual and TS, and as such constituted a performance deficiency that was reasonably within the licensees ability to foresee and correct and should have been prevented.

The inspectors reviewed this issue using the guidance contained in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Reports, and determined that it was of more than minor safety significance and constituted a finding. The issue was determined to be associated with the Mitigating Systems Cornerstone attribute of procedure quality, and had adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, CCW, a mitigating system, had its reliability adversely impacted by the lack of appropriate fill and venting procedural guidance. In addition, the unexpected 11-3-A annunciator alarm and ensuing alarm response and investigation caused the on-watch operations crew to temporarily suspend the in-progress RCS fill and venting procedures, which extended the heightened shutdown safety awareness condition (i.e., yellow risk) by approximately 30 minutes.

The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. Because the finding involved reactor shutdown operations and conditions, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process - Phase 1 Operational Checklists for Both PWRs and BWRs. Since the finding was associated with an issue that occurred during the time the licensee was conducting RCS fill and venting activities and plant conditions were in transition, the inspectors consulted both Checklist 2, PWR Cold Shutdown Operation: RCS Closed and Steam Generators Available for Decay Heat Removal (Loops Filled and Inventory in the Pressurizer); Time to Boiling Less Than 2 Hours, and Checklist 3, PWR Cold Shutdown and Refueling Operation: RCS Open and Refueling Cavity Level Less Than 23 Feet or RCS Closed and No Inventory in the Pressurizer; Time to Boiling Less Than 2 Hours. The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes on either checklist, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis.

Consequently, the finding was determined to be of very low safety significance (Green).

This finding had a cross-cutting aspect in the area of Human Performance, Resources component, because the licensee did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the licensees procedures and guidance for the restoration of the CCW system following outage maintenance activities did not ensure that the system was fully filled and properly vented prior to operation. (H.2(c))

Enforcement Technical Specification 5.4.1(a) requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in RG 1.33, Revision 2, Appendix A. Section 3(e) of RG 1.33, Revision 2, Appendix A, requires procedures for the proper operation of the CCW system, including filling, venting, and draining operations. Contrary to this requirement, the licensee failed to properly prepare and implement technically adequate written procedures for the filling and venting of the CCW system following mid-cycle outage 17M maintenance, such that significant air voids were left in the system following its restoration and return to service.

Because this finding was of very low safety significance and had been entered into the licensees CAP as CRs 2011-05542 and 2011-05831, the associated violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000346/2011005-03)

1R18 Plant Modifications

.1 Temporary and Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary and permanent plant modifications:

• Engineering change package (ECP) 11-0412, which covered replacement of large portions of service water (SW) piping and removal of emergency core cooling system (ECCS) room cooler check valves [permanent modification];

• ECP 02-0540, which covered replacement of the unit load demand module of the stations integrated control system (ICS) [permanent modification]; and

• ECPs 10-0458 and 10-0459, which covered the opening and restoration of the access openings in the concrete containment SB and steel containment vessel (CV) to facilitate replacement of the integrated reactor head assembly [temporary modification].

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screenings against the design basis, the USAR, and the TS 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. In addition, 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 in the course of this inspection are listed in the Attachment to this report.

These inspection activities constituted a single temporary modification sample and two permanent plant modification samples as defined in IP 71111.18-05. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

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

• Motor testing and pump baseline testing of containment spray train 1 during the week ending October 29, 2011, following motor replacement and preventive maintenance activities;

• Motor testing and baseline testing of no. 1 makeup pump during the week ending October 29, 2011, following motor replacement and preventive maintenance (PM) activities;

• Motor testing and baseline testing of no. 1 decay heat pump during the week ending November 5, 2011, following motor replacement and preventive maintenance activities;

• Motor testing and 18-month response time testing of containment air cooling unit no. 3 during the week ending November 12, 2011, following motor replacement and preventive maintenance activities;

• Post-modification test and 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> load test of station battery charger 1N and 1P during the weeks ending October 29 and November 5, 2011, following replacement of the battery chargers;

• Emergency ventilation system train 1 refueling interval SFAS drawdown test during the week ending November 26, 2011, following restoration of the SB and CV openings;

• Testing and tuning of main feedwater regulating valve (FRV) SP6B during the week ending November 5, 2011, following various outage-related maintenance activities;

• Integrated leakage testing of the primary containment during the week ending November 19, 2011, following restoration of the maintenance access opening that facilitated replacement of the reactor vessel integrated closure head assembly;

• Performance testing of auxiliary FW train no. 1 during the week ending December 10, 2011, following various outage-related maintenance activities; and

• Control rod drop timing testing during the week ending December 10, 2011, following replacement of the reactor vessel integrated closure head assembly.

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

that the effect of testing on the plant had been adequately addressed; that testing was adequate for the maintenance performed; that acceptance criteria were clear and demonstrated operational readiness; that test instrumentation was appropriate; that the tests were performed as written in accordance with properly reviewed and approved procedures; that equipment was returned to its operational status following testing (i.e.,

temporary modifications or jumpers required for test performance were properly removed after test completion, etc.); and that test documentation was properly evaluated. The inspectors evaluated the activities against TS, the USAR, 10 CFR 50 requirements, licensee procedures, and various NRC generic communications to verify 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 PMTs 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 to this report.

The inspectors reviews of these activities constituted ten PMT samples as defined in IP 71111.19-05. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

Reactivity Manipulations Performed By Non-Licensed Individual Introduction The inspectors identified a SL IV NCV of 10 CFR 54(i). Specifically, on December 4, 2011, during the conduct of control rod insertion timing testing, the inspectors observed a non-licensed member of the licensees engineering staff operating switches that directly and purposefully caused the insertion of various control rods that were being tested.

Description On December 4, 2011, the inspectors were observing control rod insertion timing testing as part of a normal baseline inspection sample, and also to fulfill post-installation testing requirements associated with IP 71007, Reactor Vessel Head Replacement. The sequence of testing involved the withdrawal of each control rod group (one group at a time) from the control room, and then timing the insertion of the control rods upon removal of power from their control rod drive (CRD) mechanisms. This latter action was accomplished locally in the field from electrical penetration room no. 1 where the control rod power supply cabinets were situated.

The inspectors observed the first of several control rod groups to be tested from the control room. Control rod group withdrawal was accomplished by an on-watch licensed reactor operator who was in constant communication with testing personnel in the electrical penetration room, and no issues were noted by the inspectors. During a brief pause between control rod groups, the inspectors moved to electrical penetration room no. 1 to observe the remaining testing from that location.

During the next control rod group to be tested, the inspectors observed that the actual key switches used to interrupt power to the CRDs and cause control rod insertion were manipulated by a member of the licensees engineering staff, and not a licensed individual. A licensed Senior Reactor Operator (SRO) was present in the electrical penetration room and providing oversight and test direction. The inspectors immediately questioned the SRO concerning the appropriateness of having a non-licensed individual causing control rod insertion and directly manipulating core reactivity, at which point the testing was suspended and the Shift Manager and Superintendent of Nuclear Operations were contacted and informed of the issue. The licensee immediately dispatched a licensed reactor operator to the electrical penetration room and testing resumed with a licensed reactor operator conducting all further operation of the local key switches.

The licensee entered the issue into their CAP as CR 2011-06318, and initially classified it as a severity level (SL) 5 reactivity management issue (i.e., low level and inconsequential).

Analysis The inspectors determined that failure of the licensee to assign a licensed operator to manipulate the key switches in the electrical penetration room and directly change core reactivity constituted a performance deficiency that was reasonably within the licensees ability to foresee and correct and should have been prevented.

The inspectors reviewed this issue using the guidance contained in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Reports. The issue was determined to be associated with the Mitigating Systems Cornerstone attribute of procedure quality. However, the inspectors subsequently determined that the issue had not adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Because of several factors, the inspectors determined that the issue was of minor safety significance and, as such, did not constitute a finding.

These factors included:

• All control rod group withdrawal activities were accomplished from the control room by an on-watch licensed reactor operator;

• All activities in the electrical penetration room were performed in accordance with an approved written test procedure, and under the direct supervision of a licensed SRO;

• The operation of the local key switches in the electrical penetration room, albeit by a non-licensed individual, could only cause control rod insertion; there was no withdrawal capability; and

• The individual operating the local key switches in the electrical penetration room was always in continuous communication with the on-watch licensed reactor operator in the control room.

Continuing in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Reports, the inspectors determined that the issue was subject to the NRCs traditional enforcement process as an issue that had the potential to impact the agencys ability to perform its regulatory function. Specifically, the NRCs Reactor Oversight Process fundamentally assumes that only duly licensed individuals are allowed to manipulate reactor controls and alter core reactivity or make changes to reactor power, and that all licensed individuals perform their licensed duties in accordance with any restrictions associated with their individual licenses.

The inspectors reviewed the violation examples in Section 6.4 of the NRCs Enforcement Policy, Licensed Reactor Operators. However, no similar examples of non-licensed individuals performing licensed duties could be found. Subsequently, the inspectors conferred with NRC Region III management and members of the enforcement staff and determined that, because of the factors noted above, the issue constituted a SL IV violation that resulted in no, or relatively inappreciable, safety consequences. Because this issue was dispositioned through the traditional enforcement process and had no Reactor Oversight Process aspects, there was no cross-cutting aspect associated with the violation.

Enforcement Controls is defined in 10 CFR 50.2, Definitions, as: When used with respect to nuclear reactors means apparatus and mechanisms, the manipulation of which directly affects the reactivity or power level of the reactor. Further, 10 CFR 50.54(i) states that:

Except as provided in part 55.13 of this chapter, the licensee may not permit the manipulation of the controls of any facility by anyone who is not a licensed operator or senior operator as provided in part 55 of this chapter.

Contrary to this requirement, on December 4, 2011, the licensee permitted a non-licensed member of the engineering staff to manipulate controls (e.g., key switches) in electrical penetration room no. 1 that directly altered core reactivity through the insertion of a group of control rods. Because the licensee entered this issue into the CAP as CR 2011-06318, this SL IV violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000346/2011005-04)

1R20 Outage Activities

.1 Reactor Vessel Head Replacement Outage Activities

a. Inspection Scope

The inspectors reviewed the licensees shutdown safety plan and contingency plans for the 17M mid-cycle outage conducted from October 1, 2011, to December 6, 2011, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below:

• Licensee configuration management, including maintenance of defense-in-depth commensurate with the shutdown safety plan for key safety functions and compliance with the applicable TS when taking equipment out of service;

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

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

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

• Monitoring of decay heat removal processes, systems, and components;

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

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

• Controls over activities that could affect reactivity;

• Maintenance of secondary containment as required by TS;

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

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

• Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the containment building to verify that debris had not been left which could block ECCS suction strainers; and

• Licensee identification and resolution of problems related to outage activities.

In addition, the inspectors reviewed the licensees heavy lift plans and activities in conjunction with the NRCs Operating Experience Smart Sample (OpESS) FY2007-03, Revision 2, Crane and Heavy Lift Inspection, Supplemental Guidance for IP 71111.20.

Documents reviewed during the inspection are listed in the Attachment to this report.

This inspection constituted one non-refueling outage activity sample as defined in IP 71111.20-05. Additionally, these inspection items contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

Inadequate Information on Valve Interlocks Resulted in Inadvertent Operation and Loss of Component Cooling Water Surge Tank Inventory Introduction A self-revealed finding of very low safety significance (Green) and an associated NCV of TS 5.4.1(a) were identified for the licensees failure to establish, implement, and maintain technically adequate procedures to cover the restoration (i.e., motor controller re-energization) of components in the CCW system following maintenance activities.

Description On Thursday, October 20, 2011, the plant was in a defueled condition. At approximately 1511 hours0.0175 days <br />0.42 hours <br />0.0025 weeks <br />5.749355e-4 months <br />, the on-watch control room crew received an unexpected annunciator alarm, 11-3-A, which indicated a low level in the CCW surge tank. The crew entered DB-OP-02011, Heat Sink Alarm Panel 11 Annunciators, and cut in demineralized water to the CCW system to retard the drop in surge tank level in accordance with the procedure.

At the same time that the above event was occurring, an equipment operator was in the process of restoring electrical loads on 480 Vac Motor Control Center (MCC) E11D. The operator had just closed circuit breaker BE1161 for motor-operated valve (MOV)

CC2645, the train 1 auxiliary building return header isolation valve. This valve had been in the shut position to isolate a portion of the CCW system that had been drained for maintenance, and plant operators after reviewing the valves operating drawings and interlock logic had expected the valve to remain in the shut position following closure of its circuit breaker. As circuit breaker BE1161 was closed, however, CC2645 unexpectedly stroked open. Operations personnel in the control room heard the distinct sounds of collapsing air voids in the CCW piping outside the control room as CC2645 stroked open and annunciator 11-3-A came into alarm.

The on-watch operations crew quickly determined that the unexpected opening of MOV CC2645 was the cause of the low level condition in the CCW system. Because of the low level condition, once CC2645 completed its open stroke it automatically received a command to shut and moved back to the closed position. On an ensuing cycle when the valve was closed or nearly closed, plant operators reopened circuit breaker BE1161 and halted the transient. Component Cooling Water surge tank level was then restored to the normal operating band and stabilized there.

Prior to the event, loads on MCC E11D were being restored at the discretion of the unit supervisor. Drawings being utilized by the plant operators for this activity indicated that CC2645 should only automatically open under a set of very specific conditions. All but one of these conditions were met, and the operators believed that CC2645 would remain in the shut position when circuit breaker BE1161 was closed because an interlock associated with CCW pump no. 1 was not met. Specifically, the operators thought that based on the information on their reference drawings that CC2645 would only open with the circuit breaker for CCW pump no. 1 racked into the test position. Since the circuit breaker for CCW pump no. 1 was racked to the out position, plant operators had concluded that closing circuit breaker BE1161 would not result in any change in CC2645 valve position. A follow-up investigation by licensee engineering personnel, however, identified that both CCW pump no. 1 being racked into the test position and being racked to the out position satisfied the CC2645 interlocks and will provide the MOV with a signal to open.

The licensee had entered this issue into their CAP as CR 2011-04078. Corrective action taken or planned by the licensee included a revision to the referenced drawings to include all interlock requirements associated with MOV CC2645, as well as other similar valves.

Analysis The inspectors determined that failure of the licensee to establish, implement, and maintain technically adequate procedures to cover the restoration (i.e., motor controller re-energization) of the CCW system following maintenance activities was contrary to the requirements in the licensees Quality Assurance Program Manual and TS, and as such constituted a performance deficiency that was reasonably within the licensees ability to foresee and correct and should have been prevented.

The inspectors reviewed this issue using the guidance contained in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Reports, and determined that it was of more than minor safety significance and constituted a finding. The issue was determined to be associated with the Mitigating Systems Cornerstone attribute of procedure quality, and had adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, CCW, a mitigating system, had its reliability adversely impacted by the inadequate procedural guidance for motor controller restoration.

The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. Because the finding involved reactor shutdown operations and conditions, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process - Phase 1 Operational Checklists for Both PWRs and BWRs. Since the finding was associated with an issue that occurred during the time the reactor was in a defueled condition, the inspectors conservatively consulted all four PWR checklists (i.e.,

Checklists 1 - 4). The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes on any checklist, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis.

Consequently, the finding was determined to be of very low safety significance (Green).

This finding had a cross-cutting aspect in the area of Human Performance, Resources component, because the licensee did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the licensees procedures, drawings and guidance for the restoration of the CCW system following outage maintenance activities did not ensure that the system was properly aligned prior to restoration of electrical power to MOV CC2645. (H.2(c))

Enforcement Technical Specification 5.4.1(a) requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in RG 1.33, Revision 2, Appendix A. Section 3(e) of RG 1.33, Revision 2, Appendix A, requires procedures for the proper operation of the CCW system, including restoration operations following maintenance and other outage activities. Contrary to this requirement, the licensee failed to properly prepare and implement technically adequate written procedures and drawings for the restoration of CCW system components, specifically electrical power to MOV CC2645, following mid-cycle outage 17M maintenance.

Because this finding was of very low safety significance and had been entered into the licensees CAP as CR 2011-04078, the associated violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000346/2011005-05)

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:

• DB-SC-03121, Safety Features Actuation System Train 2 Integrated Response Time Test, during the weeks ending October 15, 2011 and November 12, 2011 (routine);

• DB-PF-10310, Containment Integrated Leakage Rate Test, during the week ending November 19, 2011 (routine);

• DB-SC-03074, Emergency Diesel Generator 1, ABDC1, and AC103 Appendix R Test, during the week ending October 29, 2011 (routine);

• DB-PF-03010, Reactor Coolant System Leakage Test, during the week ending December 10, 2011 (RCS leakage);

• DB-PF-03008, Containment Local Leakage Rate Tests, {Local Leak Rate Test P71C - Core Flood Tank 1-1 Fill and Nitrogen Supply Line and Local Leak Rate Test P49 - Refueling Canal Fill Line}, during the week ending October 8, 2011 (containment isolation valve); and

• DB-SP-03157, Auxiliary Feedwater Pump 1 Response Time Test, during the week ending December 10, 2011 (inservice testing).

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 USAR, 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 (IST) activities, testing was performed in accordance with the applicable version of Section XI, ASME 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 in 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 to this report.

These inspection activities constituted three routine surveillance testing samples, one RCS leakage testing sample, one containment isolation valve testing sample, and one IST sample as defined in IP 71111.22, Sections -02 and -05. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational Radiation Safety and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

The activities in sections 1 through 9 that follow constituted one complete inspection sample as defined in IP 71124.01-05. In addition, these samples contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed all licensee performance indicators (PIs) for the occupational exposure cornerstone for follow-up since the last inspection. The inspectors reviewed the results of radiation protection program audits (e.g., licensees QA audits or other independent audits). The inspectors also reviewed reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed and assessed results of the licensees audit and operational report reviews to gain insights into overall licensee performance before and during the outage.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors assessed any changes to plant operations since the last inspection that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether the licensee assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last three to five radiological surveys from selected plant areas and evaluated whether the thoroughness and frequency of the surveys where appropriate for the given radiological hazard.

The inspectors conducted walkdowns of the facility, including radioactive waste processing, storage, containment, fuel handling, and auxiliary building areas to evaluate material conditions, and performed independent radiation measurements to assess conditions of radioactive materials at these areas.

The inspectors selected the following radiologically risk-significant work activities that involved exposure to radiation:

• Reactor head swap work activities in containment;

• ISI of the reactor vessel, core support assembly;

• Plenum and reactor flange maintenance;

• Reactor head disassembly/reassembly work activities; and

• Replacement of SW piping in the auxiliary building.

For these work activities, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey programs to determine if hazards were properly identified, including the following:

• Identification of hot particles;

• The presence of alpha emitters;

• The potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials;

• The hazards associated with work activities that could suddenly and severely increase radiological conditions and that the licensee has established a means to inform workers of changes that could significantly impact their occupational dose; and

• Severe radiation field dose gradients that can result in non-uniform exposures of the body.

The inspectors observed work in potential airborne areas during the 17M mid-cycle outage and evaluated whether the air samples were representative of the breathing air zone. The inspectors evaluated whether continuous air monitors (CAMs) were located in areas with low background to minimize false alarms and were representative of actual work areas. The inspectors evaluated the licensees program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

b. Findings

No findings were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors selected various containers holding non-exempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and assessed whether the containers were labeled and controlled in accordance with 10 CFR 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g), Exemptions To Labeling Requirements.

The inspectors reviewed the following radiation work permits (RWPs) used to access high-radiation areas and evaluated the specified work control instructions or control barriers.

• Reactor head swap work activities in containment;

• ISI of the reactor vessel, core support assembly;

• Plenum and reactor flange maintenance;

• Reactor head disassembly/reassembly work activities; and

• Refueling activities.

For these RWPs, the inspectors assessed whether allowable stay times or permissible dose (including from the intake of radioactive material) for radiologically significant work under each RWP were clearly identified. The inspectors evaluated whether electronic personal dosimeter alarm set-points were in conformance with survey indications and plant policy.

The inspectors reviewed selected occurrences where a workers electronic personal dosimeter noticeably malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately to the off-normal condition. The inspectors assessed whether the issue was included in the CAP and dose evaluations were conducted as appropriate.

For work activities in transient radiological conditions, the inspectors assessed the licensees means to inform workers of changes that could significantly impact their occupational dose.

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors potentially contaminated material leaving the radiological control area and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use and evaluated whether the work was performed in accordance with plant procedures and whether the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site. The inspectors assessed whether the radiation monitoring instrumentation had appropriate sensitivity for the types of radiation present.

The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was a procedural guidance on how to respond to an alarm that indicates the presence of licensed radioactive material.

The inspectors reviewed the licensees procedures and records to assess that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters. The inspectors assessed whether or not the licensee has established a de facto release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high-radiation background area.

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

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

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels) during tours of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, RWPs, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of electronic personal dosimeters in high noise areas as high radiation area monitoring devices.

The inspectors assessed whether radiation monitoring devices were placed on the individuals body consistent with licensee procedures. The inspectors assessed whether the dosimeter was placed in the location of highest expected dose or that the licensee properly employed an NRC-approved method of determining effective dose equivalent.

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

The inspectors reviewed the following RWPs for work within airborne radioactivity areas with the potential for individual worker internal exposures.

• Reactor head swap work activities in containment;

• ISI of the reactor vessel and core support assembly;

• Plenum and reactor flange maintenance;

• Reactor head disassembly/reassembly work activities; and

• Replacement of SW piping in the auxiliary building.

For these RWPs, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding, grit blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The inspectors assessed barrier (e.g., tent or glove box) integrity and temporary high efficiency particulate air ventilation system operation.

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

The inspectors examined the posting and physical controls for selected high radiation areas and very high radiation areas to verify conformance with the occupational PI.

b. Findings

No findings were identified.

.6 Risk-Significant High Radiation Area and Very High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors discussed with the radiation protection manager the controls and procedures for high-risk high radiation areas and very high radiation areas. The inspectors discussed methods employed by the licensee to provide stricter control of very high radiation area access as specified in 10 CFR 20.1602, Control of Access to Very High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and Very High Radiation Areas of Nuclear Plants. The inspectors assessed whether any changes to licensee procedures substantially reduce the effectiveness and level of worker protection.

The inspectors discussed the controls in place for special areas that have the potential to become very high radiation areas during certain plant operations with first-line health physics supervisors (or equivalent positions having backshift health physics oversight authority). The inspectors assessed whether these plant operations require communication before hand with the health physics group, so as to allow corresponding timely actions to properly post, control, and monitor the radiation hazards including re-access authorization.

The inspectors evaluated licensee controls for very high radiation areas and areas with the potential to become very high radiation areas to ensure that an individual was not able to gain unauthorized access to the very high radiation area.

b. Findings

No findings were identified.

.7 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors assessed whether workers were aware of the radiological conditions in their workplace and the RWP controls/limits in place, and whether their performance reflected the level of radiological hazards present.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. The inspectors discussed with the radiation protection manager any problems with the corrective actions planned or taken.

b. Findings

No findings were identified.

.8 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

The inspectors observed the performance of the radiation protection technicians with respect to all radiation protection work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace and the RWP controls/limits, and whether their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be radiation protection technician error. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

b. Findings

No findings were identified.

.9 Problem Identification and Resolution (02.09)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring and exposure controls.

The inspectors assessed the licensees process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

The activities in Sections 1 through 4 that follow constituted one complete inspection sample as defined in IP 71124.05-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the plant USAR to identify radiation instruments associated with monitoring area radiological conditions including airborne radioactivity, process streams, effluents, materials/articles, and workers. Additionally, the inspectors reviewed the instrumentation system and the associated TS requirements for post-accident monitoring instrumentation including instruments used for remote emergency assessment.

The inspectors reviewed a listing of in-service survey instrumentation including air samplers and small article monitors, along with instruments used to detect and analyze workers external contamination. Additionally, the inspectors reviewed personnel contamination monitors and portal monitors, including whole-body counters, to detect workers internal contamination. The inspectors reviewed this instrumentation list to assess whether an adequate number and type of instruments were available to support operations.

The inspectors reviewed licensee and third-party evaluation reports of the radiation monitoring program since the last inspection. These reports were reviewed for insights into the licensees program and to aid in selecting areas for review (smart sampling).

The inspectors reviewed procedures that govern instrument source checks and calibrations, focusing on instruments used for monitoring transient high radiological conditions, including instruments used for underwater surveys. The inspectors reviewed the calibration and source check procedures for adequacy and as an aid to smart sampling.

The inspectors reviewed the area radiation monitor (ARM) alarm setpoint values and setpoint bases as provided in the TS and the USAR.

The inspectors reviewed effluent monitor alarm setpoint bases and the calculational methods provided in the Offsite Dose Calculation Manual (ODCM).

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors walked down effluent radiation monitoring systems, including at least one liquid and one airborne system. Focus was placed on flow measurement devices and all accessible point-of-discharge liquid and gaseous effluent monitors of the selected systems. The inspectors assessed whether the effluent/process monitor configurations aligned with ODCM descriptions and observed monitors for degradation and out-of-service tags.

The inspectors selected portable survey instruments that were in use or available for issuance and assessed calibration and source check stickers as well as instrument material condition and operability.

The inspectors observed licensee staff performance as the staff demonstrated source checks for various types of portable survey instruments. The inspectors assessed whether high-range instruments were source checked on all appropriate scales.

The inspectors walked down ARMs and CAMs to determine whether they were appropriately positioned relative to the radiation sources or areas they were intended to monitor. Selectively, the inspectors compared monitor response (via local or remote control room indications) with actual area conditions for consistency.

The inspectors selected personnel contamination monitors, portal monitors, and small article monitors and evaluated whether the periodic source checks were performed in accordance with the manufacturers recommendations and licensee procedures.

b. Findings

No findings were identified.

.3 Calibration and Testing Program (02.03)

a. Process and Effluent Monitors

(1) Inspection Scope The inspectors selected effluent monitor instruments (such as gaseous and liquid) and evaluated whether channel calibration and functional tests were performed consistent with radiological effluent TS/ODCM. The inspectors assessed whether:

(a) the licensee calibrated its monitors with National Institute of Standards and Technology traceable sources;

(b) the primary calibrations adequately represented the plant nuclide mix;

(c) the sources were verified by the primary calibration when secondary calibration sources were used; and

(d) the licensees channel calibrations encompassed the instruments alarm set-points.

The inspectors assessed whether the effluent monitor alarm setpoints were established as provided in the ODCM and station procedures.

When changes to effluent monitor setpoints were made, the inspectors evaluated the bases for the changes to ensure that an adequate justification existed.

(2) Findings No findings were identified.

b. Laboratory Instrumentation

(1) Inspection Scope The inspectors assessed laboratory analytical instruments used for radiological analyses to determine whether daily performance checks and calibration data indicated that the frequency of the calibrations was adequate and there were no indications of degraded instrument performance.

The inspectors assessed whether appropriate corrective actions were implemented in response to indications of degraded instrument performance.

(2) Findings No findings were identified.

c. Whole Body Counter

(1) Inspection Scope The inspectors reviewed the methods and sources used to perform whole body count functional checks before daily use of the instrument and assessed whether check sources were appropriate and aligned with the plants nuclide mix.

The inspectors reviewed whole body count calibration records and evaluated whether calibration sources were representative of the plant source term and whether the appropriate calibration phantoms were used. The inspectors assessed the calibration data for anomalous results or other indications of instrument performance problems.

(2) Findings No findings were identified.

d. Post-Accident Monitoring Instrumentation

(1) Inspection Scope The inspectors selected containment high-range monitors and reviewed the calibration documentation since the last inspection.

The inspectors reviewed the electronic calibration data and assessed whether calibration acceptance criteria were reasonable, accounted for the large measuring range, and reflective of the intended purpose of the instruments.

The inspectors reviewed the licensees stack effluent process monitors that were relied on by the licensee in its emergency operating procedures as a basis for triggering emergency action levels and emergency classifications in order to make protective action recommendations during an accident. The inspectors evaluated the calibration and availability of these instruments.

The inspectors reviewed the licensees capability to collect high-range, post-accident iodine effluent samples.

As available, the inspectors observed electronic and radiation calibration of these instruments to assess conformity with the licensees calibration and test protocols.

(2) Findings No findings were identified.

e. Portal Monitors, Personnel Contamination Monitors, and Small Article Monitors

(1) Inspection Scope During a review of these instruments used on site, the inspectors assessed whether the alarm setpoint values were reasonable under the circumstances to ensure that licensed material was not released from the site.

The inspectors reviewed the calibration documentation for each instrument selected and discussed the calibration methods with the licensee to determine consistency with the manufacturers recommendations.

(2) Findings No findings were identified.

f. Portable Survey Instruments, Area Radiation Monitors, Electronic Dosimetry, and Air Samplers/Continuous Air Monitors

(1) Inspection Scope The inspectors reviewed calibration documentation for at least one of each type of instrument. In reviewing these portable survey instruments and ARMs, the inspectors reviewed detector measurement geometry and calibration methods and had the licensee demonstrate use of its instrument calibrator as applicable. The inspectors conducted comparison of instrument readings versus an NRC survey instrument if problems were suspected.

As available, the inspectors reviewed the data for portable survey instruments that did not meet acceptance criteria during calibration in order to assess whether the licensee took appropriate corrective actions with instruments that were found significantly out of calibration greater than 50 percent. The inspectors assessed whether the licensee evaluated the out of tolerance instruments for possible consequences when used during radiation surveys.

(2) Findings No findings were identified.

g. Instrument Calibrator

(1) Inspection Scope As applicable, the inspectors reviewed the current output values for the licensees portable survey and ARM instrument calibrator units. The inspectors assessed whether the licensee periodically measures calibrator output over the range of the instruments used through measurements by ion chamber/electrometer.

The inspectors assessed whether the measuring devices had been calibrated by a facility using National Institute of Standards and Technology traceable sources and whether corrective factors for these measuring devices were properly applied by the licensee in its output verification.

(2) Findings No findings were identified.

h. Calibration and Check Sources

(1) Inspection Scope The inspectors reviewed the licensees 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, source term to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

(2) Findings No findings were identified.

.4 Problem Identification and Resolution (02.04)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring instrumentation.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Reactor Coolant System Specific Activity

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Specific Activity performance indicator for the period from October 2010 through September 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees RCS chemistry samples, TS requirements, CRs, and NRC Integrated Inspection Reports for the period from October 2010 through September 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator.

In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample. Documents reviewed are listed in the to this report.

This inspection constituted one reactor coolant system specific activity sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Leakage performance indicator for the period from October 2010 through September 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator logs, RCS leakage tracking data, condition reports and NRC Integrated IRs for the period from October 2010 through September 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition 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 to this report.

This inspection constituted one reactor coolant system leakage sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

a. Inspection Scope

As part of the various baseline IPs 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: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

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

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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

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

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6 month period of July 1, 2011, through December 31, 2011, although some examples expanded beyond those dates where the scope of the trend warranted.

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

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

b. Observations The inspectors identified a potential adverse trend related to the technical quality of the licensees infrequently performed procedures, specifically those procedures that are potentially only utilized during a unit refuel or other outage:

• On October 20, 2011, the on-watch control room crew received an unexpected annunciator alarm, 11-3-A, which indicated a low level in the CCW surge tank.

The crew entered DB-OP-02011, Heat Sink Alarm Panel 11 Annunciators, and cut in demineralized water to the CCW system to retard the drop in surge tank level in accordance with the procedure. The lowering level in the CCW surge tank was traced to the inadvertent stroking of MOV CC2645, the train 1 auxiliary building return header isolation valve, which had unexpectedly stroked open when plant operators restored 480 Vac power to the MOV as part of system restoration following outage maintenance. Operations personnel had been misled by instructional notes on approved plant drawings that indicated that the valve would not automatically stroke open upon restoration of power. A finding associated with this issue is discussed in detail in Section 1R20.1 of this report;

• On November 17, 2011, the on-watch control room crew again received an unexpected annunciator alarm, 11-3-A, which indicated a low level in the CCW surge tank. Once again, the crew entered DB-OP-02011, Heat Sink Alarm Panel 11 Annunciators, and cut in demineralized water to the CCW system to retard the drop in surge tank level in accordance with the procedure. Following this event, the lowering level in the CCW surge tank was traced to air intrusion into the CCW system. A complex series of fill and venting evolutions to restore the system had been required, and these evolutions had not vented all of the air from the system. A finding associated with this issue is discussed in detail in Section 1R15.1 of this report;

• On November 16, 2011, an Alert was declared by the licensee due to a fire and explosion with a flash of flame coming from safety-related MCC E11C. The fire was caused by an electrical short within one of the MCCs circuit breakers that had resulted from water intrusion. A demineralized water supply valve, PW55, located above MCC E11C had been overpressurized and leaked water onto the MCC. The overpressurization of PW55 resulted from an improper sequence of procedure steps for the switching of makeup water to the stations auxiliary boiler that relied upon a check valve to protect lower pressure rated piping and components. A finding associated with this issue is discussed in detail in Section 4OA3.2 of this report;

• On November 21, 2011, while conducting RCS fill and venting activities the licensee overpressurized the low-range suction pressure gauges on decay heat pump 1 and decay heat pump 2. The sequence of steps in procedure DB-OP-06904, Shutdown Operations, was identified as the issue. The licensee documented this issue in their CAP as CRs 2011-05781 and 2011-05782;

• On November 19, 2011, the licensee attempted to obtain a chemistry sample to verify pressurizer dissolved oxygen concentrations during pressurizer heatup in accordance with procedure DB-CH-06002, Sampling System Nuclear Areas.

The sample was unable to be obtained due to limitations with the procedure as written. The licensee documented this issue in their CAP as CR 2011-05726; and

• On November 29, 2011, the licensee identified an adverse condition associated with procedure DB-PF-03811, Miscellaneous Valves Test. The procedure as written would have overpressurized a section of piping in the decay heat system had it been performed as scheduled. Fortunately, the on-watch Operations crew identified the vulnerability before the procedure was performed and had it rescheduled for a time when plant conditions would adequately support it. The licensee entered the issue into their CAP as CR 2011-06011.

In each of these cases, the issue was of very low or minor safety significance. However, taken collectively they represent a potential adverse trend that may require a mitigation strategy.

c. Findings

No findings were identified.

.4 Annual Sample: Review of Licensee Extent-of-Condition for Shield Building Concrete

Cracking

a. Inspection Scope

On October 10, 2011, a laminar crack was found in the flute shoulder area of the opening being cut through the SB concrete cylindrical wall for transfer of the RRVCH head. The crack was found on the vertical side of the opening (left side, looking from the outside), generally along the main reinforcing steel of the cylinder, and extending to across the top (approximately 6 feet) and across the bottom (approximately 4 feet) of the opening. After the licensee performed some minor manual chipping along the edges, the crack indication along the left and bottom edges essentially disappeared. Based on the observation, the licensee considered the crack to have been a circumferential laminar tear and not a radial through-thickness direction crack. The licensee initiated CR 2011-03346 to identify this issue and informed the NRC via the Resident Inspectors Office on site.

Based upon inspection of this crack at the SB opening, the licensee determined that the extent of the cracking warranted further examination and investigation. A contractor was contacted to perform impulse response (IR) testing. The IR testing method measured the structures frequency at a specific location and plotted that frequency with adjacent readings to obtain any change in building frequency. Changes in frequency within a short span were possible subsurface indications of concrete cracking. To confirm the IR readings, the licensee performed core boring of the concrete in the indicated areas (where cracking was suspected) and in the adjacent areas (where no cracking was suspected). The IR readings were performed on a representative sample of all readily accessible areas of the SB, with the progression of IR testing based upon the indications of possible cracking that were obtained. From this information, the licensee concluded that the laminar cracking initially identified adjacent to the RRVCH opening was not restricted to that area, but was a much more generic issue for the SB as a whole. The licensee entered this extent-of-condition issue for the SB cracking into their CAP as CR 2011-03996 on October 19, 2011, and informed the NRC via the Resident Inspectors Office on site.

On October 26, 2011, during investigation actions associated with CR 2011-03346, the licensee identified additional areas of concern via IR testing in semicircular zones above the main steam line penetrations through the SB. This condition appeared to be different from the condition documented in CR 2011-03346, which had been primarily concerned with cracking at the SB opening and similar areas around the buildings circumference. These new areas of concern were not similar to those previously identified, and appeared to be associated with the main steam line penetrations. The licensee entered this extent-of-condition issue for the SB cracking into their CAP as CR 2011-04402 and informed the NRC via the Resident Inspectors Office on site.

On October 31, 2011, the licensee identified additional indications of concrete cracking during IR testing towards the top of the SB wall, approximately between the 780 ft and 800 ft elevations. This area of indications was yet another one different from the laminar cracking initially identified adjacent to the RRVCH opening. The licensee entered this extent-of-condition issue for the SB cracking into their CAP as CR 2011-04648, informed the NRC via the Resident Inspectors Office on site, and continued to investigate further to determine if any additional adverse conditions existed.

The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve these challenges. The inspectors also reviewed the associated CRs and investigations for the issue to verify that the licensees identification of the problems were complete, accurate, and timely, and that the consideration of the extent-of-condition reviews, generic implications, common causes, and previous occurrences, if any, were adequate. Throughout the entire process, the NRC Resident Inspectors Office was augmented by structural engineering experts from the NRC Region III Office in Lisle, Illinois, as well as structural engineering and concrete construction experts from the Office of Nuclear Reactor Regulation located at NRC Headquarters in Washington, D.C.

Inspector follow-up activities related to the laminar concrete cracking and the long-term impact on the SB are on-going. Upon completion, the inspection will be documented in a separate report, IR 05000346/2012007, along with the results of the NRCs technical assessment of the licensees evaluation of the SBs capability to perform its designated safety functions.

The documents listed in the Attachment were reviewed to accomplish the objectives of the IP. This review constituted one annual inspection sample as defined in IP 71152-05.

In addition, this sample contributed towards completion of IP 71007, Reactor Vessel Head Replacement.

b. Findings

No findings were identified.

.5 Selected Issue Follow-Up Inspection Associated with Condition Report 07-26185

Degradation Found on Rip-Rap sides of the Forebay and Intake Canal

a. Inspection Scope

The inspectors reviewed the corrective actions associated with excessive settlement in a section of the safety-related Northern Wall of the Intake Canal Forebay that was identified by the licensee and documented in CR 07-26185 Degradation Found on Rip-Rap sides of the Forebay and Intake Canal. This issue was selected for an in-depth review based on the Ultimate Heat Sink inspection (Section 1R.07) and discussions with the Division of License Renewal in the Office of Nuclear Regulation. The inspectors reviewed the troubleshooting activities and subsequent CRs to verify that the licensee was appropriately addressing the adverse condition in their corrective action program.

b. Findings and Observations

During a routine inspection of the Intake Canal in 2007, the licensee identified unexpected settlement on the North side of the embankment in the safety-related portion of the Forebay for a length of approximately 200 feet. This settlement reduced the slope of the embankment and the concern was captured in CR 07-26185. The licensee contracted an external organization to perform a stability study to ensure the operability of the embankment. In 2009, the licensee received the final report and CR 09-54330 Slope Stability Study for the FOREBAY North Wall Found Low Strength Clay Till, was created to evaluate the conclusions of the contractors report, Bowser- Morner Report No. 144188-0209-1575. The report documented the soil profile of the core bores taken above the affected areas were very similar to the soil profile described in the original plant design documents. The licensee concluded the condition was insignificant and did not affect operability of the canal walls; however, the licensee initiated actions to restore the canal wall. However, in 2010, the licensee rejected the initial repair plan and in March 2011, concluded additional data and analysis were necessary to understand the cause of the condition.

During the Ultimate Heat Sink inspections, the inspectors walked the length of the canal walls with the system engineer and noted that the wall had degraded further. At the NRCs prompting, the licensee initiated CR 11-97166, Degradation of the Intake Canal North Wall in the Q/NQ Portion of the Canal. The licensee concluded the canal remained operable based on EQE Calculation 250785-C-001, Slope Stability, dated March 31, 1999, which evaluated erosion of the earthen wall embankment in the nonsafety-related portion of the canal. However, the inspectors questioned the applicability of the EQE Calculation and subsequent licensee conclusion of current functionality because the EQE addressed a specific failure mechanism, which was not present in the safety-related section of the intake structure. The inspectors also questioned the term stable being used to describe what the inspectors observed as active degradation of the canal wall.

During this same time period, the licensee performed a surveillance to measure the length and width of the intake canal. The licensee concluded portions of the canal were narrower than expected; therefore, the Intake Canal did not meet the licensed design requirements due to volume reduction of approximately three percent (3 percent).

Additionally, the slopes, canal toe-to-toe lengths and wall heights were not consistent with the original design requirements and documentation. The licensee initiated CR 11-00422 Intake Canal Dike Does Not Meet Design Configuration Requirements, and a prompt operability determination. The licensee re-calculated the available volume and surface area and determined that margin was available such that the canal remained operable. However, the licensee noted UFSAR Section 2.5.1.10.2, Foundations for Seismic Class I Structures; Seismic Class I Intake Forebay Canal Dikes, stated the intake canal was designed to have a 2.5 factor of safety against failure during the maximum possible earthquake. The current condition resulted in a factor of safety of 2.44. The licensee determined in the prompt operability determination that while this condition did not meet the UFSAR, there was reasonable assurance of operability.

Although the licensee was aware of the above issues, the inspectors were concerned that in the prompt operability determinations, the licensee narrowly assessed the current, as-found condition and did not consider whether the mechanism causing the degradation could result in a problem beyond additional sediment in the canal. As part of their corrective actions, core bores of the affected area were obtained and the November 2011 preliminary assessment found the soil profile was very similar to that described in the original plant design documents. The inspectors were also concerned with the timeliness of repairs described in the CRs because the initial plans were replaced with continued monitoring. The condition and the licensees plans to repair the wall became the subject of several Requests for Additional Information (RAIs)associated with the License Renewal Application. As documented in a letter dated October 31, 2011, (ML11306A066), the licensee outlined a schedule to repair the canal wall while continuing to monitor for further degradation.

No findings were identified.

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

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report 05000346/2011-001-00: Pressurizer Code Safety Valve

Setpoint Test Failures On February 28, 2010, Davis-Besse commenced refueling outage sixteen. Per the outage plan, the sites pressurizer safety valves were removed and sent to an offsite vendor for testing and refurbishment. This testing was performed on August 16, 2010.

In December 2010, the licensee received information from the testing vendor that the two pressurizer safety valves had as-found lift setpoints (2531 psig and 2535 psig respectively) that were slightly above the limits specified in TS 3.4.10 (2525 psig). The licensee attributed the as-found values to setpoint drift during operation. A past operability evaluation was completed by the licensee on January 12, 2011, and concluded that the pressurizer safety valves had been inoperable while they were installed in the plant during the previous reactor operating cycle.

The inspectors review of this event determined that the safety significance of the issue was minimal. While both valves had as-found setpoints that exceeded the TS allowed value, the highest out-of-tolerance setpoint was only 10 psig higher than the required value, and the discrepancy would not have adversely impacted either valves ability to have fulfilled its safety function had either been called upon to do so during the previous period of reactor operation. Consequently, the inspectors determined that this failure to comply with TS 3.4.10 was a violation of minor safety significance that was not subject to formal enforcement action in accordance with Section 2.3 of the NRC Enforcement Policy.

The licensee had entered these failures into their CAP as CR 2010-87048. Documents reviewed as part of this inspection are listed in the Attachment. This Licensee Event Report (LER) is closed.

This event follow-up review by the inspectors constituted a single inspection sample as defined in IP 71153-05.

.2 Event Notification 47443: ALERT Due to Fire in Electrical Bus Affecting Safety-Related

Equipment

a. Inspection Scope

In the early morning hours of November 16, 2011, the inspectors responded to the site following the report of an electrical explosion and fire, and the licensees declaration of an Alert per the sites Emergency Plan. In response to the event, the inspectors observed and reviewed the licensees response to the event, plant parameters and status, including but not limited to:

• Mitigating systems and fission product barriers performance and integrity;

• The realignment of the plants affected electrical equipment;

• All emergency notifications made to state and local government agencies as required by 10 CFR 50.72; and

• Emergency plan termination and exit.

The inspectors remained on station in the sites control room providing independent assessment of the event until after the licensee had completed determinations that the Alert could be terminated. Documents reviewed in this inspection are listed in the

.

This event follow-up review by the inspectors constituted a single inspection sample as defined in IP 71153-05.

b. Findings

Inadequate Procedure Resulted in Water Intrusion Into Safety-Related Motor Control Center Introduction A self-revealed finding of very low safety significance (Green) was identified for the licensees failure to establish, implement, and maintain technically adequate procedures to permit the proper switching of FW sources for the stations auxiliary boiler, such that when the switching of FW sources from demineralized water to the stations normal condensate system took place per approved procedures there were detrimental results.

Specifically, the approved procedures for this activity relied upon a check valve to keep the demineralized water header from being exposed to greater pressure than its design.

When the check valve failed to function as designed, a failure of demineralized water system components and the inadvertent deluge and failure of safety-related electrical equipment resulted.

Description At 0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />, the licensee switched makeup water to the auxiliary boiler from the demineralized water system, operating at approximately 95 psig, to the plants normal condensate system, operating at approximately 300 psig. Shortly thereafter, at approximately 0205 hours0.00237 days <br />0.0569 hours <br />3.38955e-4 weeks <br />7.80025e-5 months <br />, control room operators were notified of water spraying from the overhead in the auxiliary building corridor between mechanical penetration rooms 3 and 4. The operations Shift Engineer, who was dispatched to the scene, reported that the water was coming down on safety-related MCC E11C.

At about 0214 hours0.00248 days <br />0.0594 hours <br />3.53836e-4 weeks <br />8.1427e-5 months <br />, the Shift Engineer witnessed an explosion with a flash of flame coming from MCC E11C. The control room was notified and operations personnel entered the sites procedures for a fire and dispatched the fire brigade. Electrical power was removed to MCC E11C by opening the feeder breaker to the entire E11 MCC string (i.e., E11A, E11B, E11C, E11D, and E11E). Power to numerous train 1 safety-related MOVs was lost as a result. However, because the plant was in cold shutdown/Mode 5 at the time of the event, these MOVs were either not required to be operable under present plant conditions and/or already in their safety-related positions. At 0222 hours0.00257 days <br />0.0617 hours <br />3.670635e-4 weeks <br />8.4471e-5 months <br />, the on-watch Shift Manager declared an Alert per the sites Emergency Plan in accordance with Emergency Action Level HA4, Fire or Explosion Affecting the Operability of Plant Safety Systems Required to Establish or Maintain Safe Shutdown.

The fire was reported out by the fire brigade at approximately 0233 hours0.0027 days <br />0.0647 hours <br />3.852513e-4 weeks <br />8.86565e-5 months <br />. No extinguishing agents were required; the removal of electrical power resulted in the fire burning itself out. A subsequent investigation of the condition of MCC E11C revealed that the source of the fire was the 480 Vac breaker BE1144, HA5261A Control Room Emergency Ventilation Fan 1-1 Inlet Valve, and that certain breaker subcomponents had shorted when they became wetted by the water spray cascading down through the MCC from the overhead. Further investigation revealed that the source of the water was a small diaphragm valve located above MCC E11C, PW55, which served to supply demineralized water to a nearby maintenance shop. At approximately 0443 hours0.00513 days <br />0.123 hours <br />7.324735e-4 weeks <br />1.685615e-4 months <br />, the site exited from the Alert and fire response procedures.

Following the event, the licensee conducted an investigation into the cause. Station engineering personnel quickly concluded that the procedure being used to switch makeup water to the auxiliary boiler from the demineralized water system, operating at approximately 95 psig, to the plants normal condensate system, operating at approximately 300 psig, contained a sequence of steps that relied upon a check valve to keep portions of the demineralized water system from being exposed to the much higher condensate system pressure. When the check valve failed to completely close, the excessive pressure, albeit not high enough to damage piping and other hard components within the demineralized water system due to that systems installed relief valve protection, was high enough to cause catastrophic failure to soft components, such as the soft diaphragm inside PW55. More egregious, however, was that there were no fewer than three previous occurrences (March 7, 2006, December 31, 2007, and August 28, 2008) where the licensee had identified water spraying from above MCC E11C under similar circumstances, but failed to pursue the matter sufficiently to identify the real cause and enact proper corrective actions. The licensee had entered this issue into their CAP as CRs 2006-00624, 2007-32157, 2008-45463; 2011-05456, 2011-05457, 2011-05465, 2011-05466, and 2011-05523. Corrective actions taken by the licensee included, but were not limited to, changes to the station auxiliary boiler operating procedure and repair of the affected electrical components.

Analysis The inspectors determined that failure of the licensee to establish, implement, and maintain technically adequate procedures to permit the proper switching of FW sources for the stations auxiliary boiler was contrary to the requirements in the licensees administrative procedure governing the content of balance-of-plant system procedures, NG-QS-00121, Davis-Besse Procedure Writers Guide, and as such constituted a performance deficiency that was reasonably within the licensees ability to foresee and correct and should have been prevented.

The inspectors reviewed this issue using the guidance contained in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Reports, and determined that it was of more than minor safety significance and constituted a finding. The issue was determined to be associated with the Initiating Events cornerstone attribute of procedure quality, and had adversely affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, electrical power to an entire string of safety-related 480 Vac MCCs (i.e., E11A, E11B, E11C, E11D, and E11E) was forced to be interrupted when a deficient procedure for the operation of the stations auxiliary heating boiler caused a significant amount of water to be deluged onto MCC E11C, resulting in an electrical short and fire within the MCC.

The inspectors evaluated the finding using IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. Because the finding involved reactor shutdown operations and conditions, the inspectors transitioned to IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance Determination Process -

Phase 1 Operational Checklists for Both PWRs and BWRs. Since the finding was associated with an issue that occurred during the time the licensee was in a cold shutdown (Mode 5) condition, the inspectors consulted Checklist 3, PWR Cold Shutdown and Refueling Operation: RCS Open and Refueling Cavity Level Less Than 23 Feet or RCS Closed and No Inventory in the Pressurizer; Time to Boiling Less Than 2 Hours. The inspectors determined that the finding did not adversely impact any shutdown defense-in-depth or mitigation attributes, nor did it meet any of the checklist specific requirements for a Phase 2 or Phase 3 SDP analysis. Consequently, the finding was determined to be of very low safety significance (Green).

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, CAP component, because the licensee did not take appropriate corrective actions to address the safety issue in a timely manner, commensurate with the safety significance and complexity. Specifically, the licensee had multiple previous opportunities to have appropriately diagnosed and corrected the issue, but failed to do so. (P.1(d))

Enforcement The inspectors concluded that the licensee did not comply with the standards and expectations for establishing, implementing, and maintaining technically adequate procedures to permit the proper switching of FW sources for the stations auxiliary boiler, as required in Attachment F7 of NG-QS-00121, Davis-Besse Procedure Writers Guide.

This finding, however, did not involve a corresponding violation of NRC requirements.

Specifically, the inspectors determined that the Davis-Besse Procedure Writers Guide is an administrative procedure, and not covered under the QA requirements set forth in 10 CFR 50, Appendix B. Additionally, the inspectors also determined that the Davis-Besse Procedure Writers Guide is not covered under TS 5.4.1(a), which requires the licensee to establish, implement, and maintain applicable written procedures for the safety-related systems and activities recommended in RG 1.33, Revision 2, Appendix A. (FIN 05000346/2011005-06)

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000346/2011-004-01: Plant Transient During High

Pressure Injection Flow Instrument String Checks On September 15, 2011, instrumentation and controls (I&C) technicians replaced the HPI 3A and 3B flow instrument signal monitors with refurbished modules. Upon insertion of the module into the cabinet, the control room received an unexpected alarm for ICS Input Mismatch. The alarm immediately cleared and was attributed to a slight disruption in voltage when the modules were inserted. A decision was made to continue replacement activities. On September 16, 2011, I&C technicians commenced PMT of the signal monitors. During the string check of the HPI flow instrument alarms, annunciator alarm 14-4-E, ICS Input Mismatch, was received. The alarm initially cleared, then returned. Coincident with ICS Input Mismatch alarm, the plants ICS began reducing reactor power without any operator input. On-watch plant operators entered procedure DB-OP-02526, Primary to Secondary Plant Upset, and went through actions of placing ICS stations in manual control. The I&C technicians performing the HPI flow instrument signal monitor refurbishment were directed to stop their activities. Reactor power initially dropped to approximately 95 percent before operators stabilized the plant, and then returned reactor power to approximately 100 percent using manual controls.

The refurbished HPI flow instrument signal monitor modules were removed from the system and taken to the I&C shop for inspection and testing, while the original signal monitor modules were reinstalled. Inspection and testing of the refurbished modules in the I&C shop did not reveal any issues. The modules were sent to the licensees offsite testing laboratory for further analysis.

The inspectors reviewed the licensees analysis which identified that when the K1 high flow positive relay coil was energized on the refurbished signal monitor module, Electromagnetic Interference/Radio Frequency Interference (EMI/RFI) affected the low input ICS converter module located in an adjacent slot in the cabinet. The licensees laboratory identified that some of the signal monitor modules, including the one used that caused the plant transient, did not have ferrite suppression beads on the leads of two capacitors in the circuitry. Ferrite suppression beads are passive electrical components used to suppress high frequency noise and prevent oscillations from occurring. The licensees laboratory confirmed that signal monitor circuit boards without ferrite beads resulted in oscillations larger in duration and amplitude than circuit boards that did contain ferrite suppression beads. These oscillations were the underlying reason why EMI/RFI was generated from the K1 high flow relay coil, causing the ICS circuitry to respond.

The installation of ferrite suppression beads on signal monitor circuit boards was an enhancement that the circuit card manufacturer had implemented sometime in the 1980s. Circuit boards manufactured in the 1970s did not contain ferrite beads. The licensees supply of signal monitor modules contains a mix of boards with and without the ferrite suppression beads installed. The licensee indicated that they did not have any prior knowledge of this design enhancement and discovered it during the investigation of the event. A review of operating experience did not reveal any similar design issues associated with the signal monitor modules at Davis-Besse or any other nuclear plant facility. Therefore, the inspectors determined that the issue was a latent problem with the refurbished circuit board and was not within the licensees ability to foresee and correct. The licensee has initiated corrective actions to inspect all currently installed signal monitor modules of the same module and will replace boards that do not contain ferrite suppression beads. Also, an order was created to inspect all spare signal monitor modules onsite to identify any other boards that lack ferrite suppression beads.

All further circuit board refurbishments at the laboratory will contain a requirement to ensure ferrite suppression beads are installed.

The inspectors did not identify a performance deficiency or violation of NRC requirements. Based on the inspectors review of the licensees analysis of the event, this unresolved item is closed.

.2 Reactor Vessel Head Replacement (IP 71007) - Containment Access Restoration

a. Inspection Scope

The Davis-Besse containment lacked an access opening of sufficient size to permit removal of the old vessel head and reinstallation of the RRVCH. Therefore, the licensee cut a temporary access opening in the SB and CV of sufficient size to support the head replacement. To restore the temporary construction opening in the CV, the licensee reused and reinstalled (by SMAW) the original plate section cut from the CV. To restore the temporary construction opening in the SB, the licensee installed new reinforcing steel (i.e., rebar) to replace the original steel reinforcement and poured new concrete fabricated at an on-site batch plant.

The inspectors reviewed the licensee activities associated with the restoration of the CV and SB access openings. Specifically, the inspectors observed activities and reviewed records as discussed below:

• Inspectors observed the cutting of the CV opening using a track-mounted welding torch to determine if the cutting activity followed the WO;

• Inspectors observed installation of the replaced CV plate to determine if the gap tolerances had been maintained in accordance with the WO and to determine if site procedures were adequate to control plate distortion;

• Inspectors observed full penetration butt welds fabricated during reinstallation of the 1.5 inch thick CV access plate to determine if the welding process followed the qualified welding procedures and to determine if weld filler materials were traceable to certified material test reports;

• Inspectors reviewed the welding procedures and welder qualification records for containment closure welding activities to determine if the welding was qualified in accordance with the ASME Code Section IX;

• Inspectors reviewed samples of the radiographic (RT) records and magnetic particle (MT) exam records of the CV welds to determine if weld acceptance criteria met the CC requirements (ASME Code 1968 Edition, 1969 Summer Addenda of Section III);

• Inspectors observed installation of mechanical rebar splices (reattachment by crimping of the steel reinforcement (rebar)) in the reinforcing steel used to restore the SB opening to determine if the licensee process conformed to the qualified procedure and design requirements;

• Inspectors observed installation of welded rebar splices in the reinforcing steel used to restore the SB to determine if the welding process followed the qualified welding procedures and that weld filler materials were traceable to certified material test reports and that welders were properly qualified;

• Inspectors reviewed the results of concrete field tests (e.g., slump and air content) during installation to determine if the concrete had the expected properties specified for the mix design;

• Inspectors observed the onsite and off-site storage and curing conditions for concrete test cylinders to determine if they met the American Society for Testing and Materials (ASTM) C31 Making and Curing Concrete Test Specimens in the Field, and ASTM C192 Making and Curing Concrete Test Specimens in the Laboratory, prior to acceptance testing;

• Inspectors reviewed the licensees vendor records for the source materials (e.g.,

aggregate, cement, water, and admixtures) for concrete batches used in restoration of the SB to determine if it these materials conformed to the design specifications;

• Inspectors observed concrete cylinder compressive tests to determine if testing was conducted in accordance with ASTM C39 Compressive Strength of Cylindrical Concrete Specimens, and to determine if the test results demonstrated that the concrete used for restoration of the SB opening had adequate shear strength to meet the USAR Section 3.8.2.3.7 minimum design compressive strength (e.g., in excess of 4000 psi); and

• The records reviewed by the inspectors are identified in the Attachment to this report.

b. Findings

No findings were identified.

.3 (Closed) Unresolved Item 05000346/2011004-05: Code Surface Examination

Requirements Not Applied to Closure Head Stud Holes

a. Inspection Scope

During the review of the fabrication records for the RRVCH, the inspectors identified a URI associated with the licensees decision to not perform surface examination of the accessible surfaces of the RRVCH stud holes based upon an interpretation of the ASME Code Section III requirements. On October 6, 2011, the Agency completed a review of the licensees interpretation of the Code, and determined that it was not correct (reference Task Interface Agreement (TIA) No. 2011-15 - ADAMS Accession No.

ML11279A218). Based upon review of this issue as discussed below, Unresolved Item (URI)05000346/2011004-05 is closed.

b. Findings

Incomplete Surface Examination of the Replacement Reactor Vessel Closure Head Introduction A finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, were identified by the inspectors for the licensees failure to perform an adequate review of fabrication records to ensure material procured from a contractor (RRVCH) met the CC. Specifically, the accessible surfaces of the 60 closure head flange stud holes were not subjected to PT or MT examinations as required by the CC.

Description The inspectors identified that the licensee had not performed PT or MT examinations of accessible surfaces for the 60 closure head flange stud holes as required by the CC.

The inspectors were concerned that failure to perform these examinations could have allowed rejectable indications to be placed inservice.

On July 22, 2011, during review of RRVCH fabrication records, the inspectors identified that the licensee had not completed the surface examinations required by the CC (1989 Edition of the ASME Code Section III). Specifically, the accessible surfaces of the RRVCH flange stud holes had not been examined using MT or PT methods as required by the Articles NB-2541(a) and NB-4121.3 of Section III of the ASME Code. The inspectors were concerned that without surface examination, rejectable flaws could be placed in service. Additionally, inservice examination of stud hole surfaces is not required by Section XI of the ASME Code, so rejectable fabrication defects would not be identified once the RRVCH was placed inservice. In response to the inspectors concern, the licensee determined that the accessible interior surfaces of the RRVCH stud holes did not require surface examination. The licensees position was based on the ASME Code Interpretation III-1-77-162, which stated in part that drilled holes are not considered to be material form surfaces and the requirement for examination of holes (if any) resides in NX-4000 and NX-5000. The licensee concluded that the reexamination of machined surfaces as discussed in the ASME Code Section III, Article NB-4121.3 did not apply to the accessible interior surfaces of the flange stud holes because they were not material form surfaces.

On October 6, 2011, the NRC issued TIA No. 2011-15, which documented the Agency position on the application of the CC requirements. Specifically, the NRC determined that examination of the accessible surfaces of the RRVCH flange stud holes by MT or PT was required to meet the requirements of Articles NB-2541(a) and NB-4121.3 of Section III of the ASME Code. The licensee entered this issue into the corrective action system in multiple CRs (reference CR-2011-00344, CR-2011-01739 and CR 2011-04373) and subsequently completed MT examination of the accessible surfaces of the 60 RRVCH flange stud holes prior to placing the vessel head into service. At each stud hole, the accessible surface for MT examination included 3 inches in depth from the flange top and bottom surface and in total, amounted to an additional 7,917 square inches of surface area examined. No rejectable fabrication flaws were identified during this examination.

Analysis The inspectors determined that failure to perform an adequate review of fabrication records to ensure material procured from a contractor (RRVCH) met the CC was contrary to 10 CFR 50, Appendix B, Criterion VII, and was a performance deficiency.

The finding was determined to be more than minor because the finding was associated with the Initiating Events Cornerstone attribute of Equipment Performance and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Absent NRC identification, the licensee would not have completed surface examination of the 60 flange stud holes to ensure unacceptable material flaws (e.g., cracks) were not placed in service. Because material flaws such as cracks serve as stress risers that reduce the ability of the RRVCH to withstand failure by crack propagation during design basis events (e.g., pressurized thermal shock), they would place the reactor coolant system at an increased risk for through-wall leakage and/or failure. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Initiating Events Cornerstone. Because this finding was identified prior to placing the RRVCH in service and no fabrication flaws were identified, the inspectors answered no to the Significance Determination Process Phase 1 screening question Assuming worst case degradation, would the finding result in exceeding the TS limit for any reactor coolant system leakage or could the finding have likely affected other mitigation systems resulting in a total loss of their safety function assuming the worst case degradation?

Therefore, the finding screened as having very low safety significance (Green).

This finding had a cross-cutting aspect in the area of Human Performance, Decision Making because the licensee staff failed to demonstrate that nuclear safety was an overriding priority in decisions affecting the RRVCH. Specifically, the failure to perform an adequate review of the RRVCH fabrication records was caused by the licensees decision to not review the manufacturers interpretations and application of the CC rules (IMC 0310 - Item H.1.b). The inspectors reached this conclusion based on discussions with licensee staff and review of the licensees apparent cause evaluation documented in CR-2011-04373.

Enforcement Appendix B of 10 CFR 50, Criterion VII, Control of Purchased Material, Equipment, and Services, requires in part that Measures shall be established to assure that purchased material, equipment, and services, whether purchased directly or through contractors and subcontractors, conform to the procurement documents. And: This documentary evidence shall be retained at the nuclear power plant, or fuel reprocessing plant site and shall be sufficient to identify the specific requirements, such as codes, standards, or specifications, met by the purchased material and equipment.

Contrary to the above, as of July 22, 2011, the licensee had not established adequate measures (e.g. adequate review of vendor fabrication records) to ensure material procured from a contractor for the RRVCH conformed to the procurement documents.

Specifically, licensee measures were not sufficient to ensure that surface examinations of 60 flange stud holes were completed in accordance with Section III of the ASME Code as required by Procurement Specification BUHSDB/NCC001 issued on January 22, 2002, and Purchase Order 7084643 issued on January 31, 2002. Because this violation was of very low safety significance and it was entered into the licensees CAP (reference CR 2011-00344, CR 2011-01739, and CR 2011-04373), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000346/2011005-07)

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 10, 2012, the inspectors presented the inspection results to the Director of Site Operations, Mr. Brian Boles, and other members of the licensee 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:

• Radiological Hazard Assessment and Exposure Controls Program inspections under the Occupational Radiation Safety Cornerstone with the Site Vice President, Mr. Barry Allen, on October 21, 2011;

• Radiation Monitoring Instrumentation Program and Performance Indicator Verification under both the Public Radiation Safety Cornerstone and the Occupational Radiation Safety Cornerstone with the Site Vice President, Mr. Barry Allen, on September 16, 2011. Additionally, a telephone re-exit was conducted on October 21, 2011; and

• The Reactor Vessel Head Replacement Fabrication Review (IP 71007) with the Director of Special Projects, Mr. Clark Price, and other members of the licensees staff on November 23, 2011.

• The Triennial Heat Sink Performance Review, the inspectors presented the inspection results to Mr. Barry Allen, and other members of the licensee staff, on January 31, 2012 via telephone conference. The licensee acknowledged the issues presented.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

B. Allen, Site Vice President

P. Boissoneault; Manager, Chemistry

B. Boles, Director, Site Operations

K. Byrd, Director, Site Engineering

T. Chowdhary, NRC Liaison

J. Dominy, Director, Site Maintenance

J. Hook, Manager, Design Engineering

R. Hovland, Manager, Training

G. Kendrick, Manager, Site Outage Management

P. McCloskey, Manager, Site Regulatory Compliance

D. Noble, Manager, Radiation Protection

W. OMalley, Manager, Nuclear Oversight

R. Oesterle, Superintendent, Nuclear Operations

M. Parker, Manager, Site Protection

R. Patrick, Manager, Site Work Management

D. Petro, Manager, Steam Generator Replacement Project

S. Plymale, Manager, Site Operations

C. Price, Director, Special Projects

M. Roelant, Manager, Site Projects

C. Sacha, Radiation Protection Services Supervisor

D. Saltz, Manager, Site Maintenance

S. Steagall, Fleet Oversight Manager

C. Steenbergen, Superintendent, Operations Training

J. Stelmaszak, Supervisor of NSSS Plant Engineering

J. Sturdavant, Regulatory Compliance

T. Summers, Manager, Plant Engineering

L. Thomas, Manager, Nuclear Supply Chain

M. Travis, Superintendent, Radiation Protection

J. Vetter, Manager, Emergency Response

A. Wise, Manager, Technical Services

G. Wolf, Supervisor, Regulatory Compliance

K. Zellers, Supervisor, Reactor Engineering

Attachment

LIST OF ITEMS

Opened

05000346/2011005-01 NCV Inadequate Control of Weld Filler Metal Electrodes (Section 1R08.1)

05000346/2011005-02 FIN Decay Heat Pump 1-1 Damaged and Rendered Inoperable By Personnel Climbing on Equipment (Section 1R13.1)

05000346/2011005-03 NCV Air Voids in Component Cooling Water System Caused By Inadequate Fill and Vent Procedure (Section 1R15.1)

05000346/2011005-04 NCV Reactivity Manipulations Performed By Non-Licensed Individual (Section 1R19.1)

05000346/2011005-05 NCV Inadequate Information on Valve Interlocks Resulted in Inadvertent Operation and Loss of Component Cooling Water Surge Tank Inventory (Section 1R20.1)

05000346/2011005-06 FIN Inadequate Procedure Resulted in Water Intrusion Into Safety-Related Motor Control Center (Section 4OA3.2)

05000346/2011005-07 NCV Incomplete Surface Examination of the RRVCH (Section 4OA5.3)

Closed

05000346/2011005-01 NCV Inadequate Control of Weld Filler Metal Electrodes (Section 1R08.1)

05000346/2011005-02 FIN Decay Heat Pump 1-1 Damaged and Rendered Inoperable By Personnel Climbing on Equipment (Section 1R13.1)

05000346/2011005-03 NCV Air Voids in Component Cooling Water System Caused By Inadequate Fill and Vent Procedure (Section 1R15.1)

05000346/2011005-04 NCV Reactivity Manipulations Performed By Non-Licensed Individual (Section 1R19.1)

05000346/2011005-05 NCV Inadequate Information on Valve Interlocks Resulted in Inadvertent Operation and Loss of Component Cooling Water Surge Tank Inventory (Section 1R20.1)

05000346/2011004-01 URI Plant Transient During HPI Flow Instrument String Checks (Section 4OA5.1)

05000346/2011005-06 FIN Inadequate Procedure Resulted in Water Intrusion Into Safety-Related Motor Control Center (Section 4OA3.2)

05000346/2011005-07 NCV Incomplete Surface Examination of the RRVCH (Section 4OA5.3)

05000346/2011004-05 URI Code Surface Examination Requirements Not Applied to Closure Head Stud Holes (Section 4OA5.3)

05000346/2011-001-00 LER Pressurizer Code Safety Valve Setpoint Test Failures (Section 4OA3.1)

Attachment

Discussed

None.

Attachment