IR 05000266/2011003

IR 05000266-11-003 & 05000301-11-003, on 4/01/2011 - 06/30/2011, Point Beach Nuclear Plant, Units 1 and 2, Surveillance Testing, Maintenance Effectiveness, and Follow-Up of Events

ML11217A058
Person / Time
Site:	Point Beach
Issue date:	08/05/2011
From:	Michael Kunowski NRC/RGN-III/DRP/B5
To:	Meyer L Point Beach
References
IR-11-003
Download: ML11217A058 (53)

Text

UNITED STATES ust 5, 2011

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000266/2011003; 05000301/2011003

Dear Mr. Meyer:

On June 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on June 30, 2011, with you and 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, three findings of very low safety significance were identified by the NRC. The findings involved violation of NRC requirements. However, because of their very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings 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 these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Point Beach Nuclear Plant. 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 Point Beach Nuclear Plant. 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/

Michael A. Kunowski, Chief Branch 5 Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27

Enclosure:

Inspection Report 05000266/2011003; 05000301/2011003 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000266; 05000301 License Nos: DPR-24; DPR-27 Report No: 05000266/2011003; 05000301/2011003 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: April 1, 2011, through June 30, 2011 Inspectors: S. Burton, Senior Resident Inspector M. Thorpe-Kavanaugh, Resident Inspector K. Carrington, Reactor Engineer P. Cardona-Morales, Reactor Engineer T. Bilik, Reactor Inspector D. Jones, Reactor Inspector N. Féliz Adorno, Reactor Inspector Approved by: Michael A. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000266/2011003, 05000301/2011003; 4/01/2011 - 6/30/2011; Point Beach Nuclear Plant,

Units 1 and 2; Surveillance Testing; Maintenance Effectiveness; and Follow-Up of Events.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Three Green findings were identified by the inspectors. The findings were considered non-cited violations (NCVs) of NRC regulations.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP).

Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for the failure to implement the requirements of procedure NP 2.1.1, "Conduct of Operations. Specifically, from July 26, 2010, to February 23, 2011, the licensee failed to track the actual position of the valves associated with FT-925, 2P-15A SI Pump Discharge Flow, which resulted in the failure to return the valves and the transmitter to its normal configuration.

The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of configuration control and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors answered No to all of the questions in the Mitigating Systems column of Table 4a of Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings; therefore, the finding screened as very low safety significance. The finding has a cross-cutting aspect in the area of human performance, work control, because the licensee failed to control the related work activity by having procedures to address the impact of changes to the work scope or activity on the plant and human performance (H.3(a)). (Section 1R12)

Green.

A finding of very low safety significance and associated non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions Procedures, and Drawings, was identified by the inspectors for the licensees failure to have appropriate procedures for the control of hazard barriers. Specifically, on August 27, 2010, and as a result of a historical review of plant operating conditions resulting from NRC observations, the licensee identified multiple occurrences of inadequate controls of high energy line break barriers that resulted from inappropriate procedures.

The performance deficiency was determined to be more than minor because it was associated with the protection against external events attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609, Significance Determination Process, the Region III Senior Risk Analyst performed a Phase 3 analysis, since the risk information from a Phase 2 analysis (Appendix A, Determining the Safety Significance of Reactor Inspection Findings for At-Power Situations, of Inspection Manual Chapter 0609) did not contain the appropriate mitigating equipment and determined that the issue was of very low safety significance. The finding had no cross-cutting aspect associated with it because the issue was related to a failure to incorporate operating experience into procedures from a Regulatory Issue Summary issued in 2001. (Section 4OA3.3)

Cornerstone: Barrier Integrity

Green.

A finding of very low safety significance and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the licensees failure to perform an operability evaluation of leakage inside containment when it was identified in September 2010. Specifically, on September 26, 2010, condition report AR01397092 identified increased leakage and a related work order was initiated to inspect Unit 1 containment for the leakage source; however, an evaluation of the leak and leak location/source was not performed as required by licensee procedures.

The finding was determined to be more than minor because it was associated with the Barrier Integrity Cornerstone attribute of structure, system, and component and barrier performance, and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers, specifically the containment, would be able to protect the public from radionuclide releases caused by accidents or events.

The inspectors answered No to all of the questions in the Containment Barrier column of Table 4a of Inspection Manual Chapter 0609, Significance Determination Process,

Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings; therefore, the finding screened as very low safety significance. The finding has a cross-cutting aspect in the area of human performance, decision-making, because the licensee did not use conservative assumptions during the decision-making and review process associated with the degraded condition (H.1(b)). (Section 1R22)

Licensee-Identified Violations

No violations of significance were identified.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at 100 percent power throughout the entire inspection period with the exceptions of small power reductions during routine surveillance testing and a scheduled down power on May 21, 2011, for turbine stop and governor valve testing.

Unit 2 began the inspection period shut down for the continuation of a planned refueling outage that began in the previous inspection period on March 1, 2011, and ended June 20, 2011.

With the exception of a power reduction on June 23 and June 24 to facilitate main feedwater regulating valve repairs, the unit continued ascending to the new extended power uprate power level for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors review included:

• the coordination between the TSO and the plant during off-normal or emergency events;

• the explanations for the events;

• the estimates of when the offsite power system would be returned to a normal state; and

• the notifications from the TSO to the plant when the offsite power system was returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

• the actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related (SR) loads without transferring to the onsite power supply;

• the compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;

• a re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and

• the communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

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

This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

.2 Summer Seasonal Readiness Preparations

a. Inspection Scope

The inspectors performed a review of the licensees preparations for summer weather for selected systems, including conditions that could lead to an extended drought.

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 Final Safety Analysis Report (FSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures.

Specific documents reviewed during this inspection are listed in the Attachment to this report. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into the CAP in accordance with station procedures. The inspectors reviews focused specifically on the following plant systems:

• service water (SW);

• component cooling; and

• instrument air.

These inspections constituted one seasonal adverse weather sample of three systems as defined in IP 71111.01-05.

b. Findings

No findings were identified.

.3 Readiness for Impending Adverse Weather Condition - Severe Thunderstorm and

Potential Tornado Watch

a. Inspection Scope

Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for May 22, 2011, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. The inspectors walked down the emergency diesel generators (EDGs) and protective features, including doors and hazard barriers, and reviewed the licensee implementation of station procedures for inclement weather. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the FSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed a sample of CAP items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the Attachment to this report.

This inspection constituted one readiness for impending adverse weather condition sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• safety injection (SI) train A with train B out-of-service for testing (Unit 1).

The inspectors selected this system based on its risk significance relative to the Reactor Safety Cornerstones at the time it was 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, FSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the system 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 to this report.

These activities constituted one partial system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• fire zone 151 (SI pump room);

• fire zones 104 and 105 (Unit 1 residual heat removal (RHR) pump rooms);

• fire zone 305 (4160-volt vital switchgear room);

• fire zone 318 (cable spreading room); and

• fire zone 326 (control room).

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

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

Using the documents listed in the Attachment to this report, 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 five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On June 10, 2011, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• Problem-oriented approach for maintenance effectiveness of SI pump with discharge flow transmitter left isolated; and

• a review of the licensees 10 CFR 50.65(a)(3) evaluation.

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.

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

b. Findings

Safety Injection Pump Discharge Flow Indicator Left Isolated

Introduction:

A finding of very low safety significance (Green) and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for the failure to implement the requirements of procedure NP 2.1.1, "Conduct of Operations. Specifically, the licensee failed to track the actual position of the valves associated with SI pump flow transmitter (FT) FT-925, which resulted in the failure to return the valves and the transmitter to its normal configuration.

Description:

On February 23, 2011, during a test, the licensee identified that FT-925, the discharge flow transmitter for the Unit 2 A train SI pump (2P-15A), was isolated.

Subsequently, the licensee restored the transmitter and its associated isolation valves to their proper configuration. The licensee initiated condition report AR01620143, 2FT-925 Found Isolated and Equalized, and performed an apparent cause evaluation (ACE) to investigate the cause of the isolated transmitter.

The ACE identified that the FT was isolated on July 26, 2010, when clearance tags were hung in preparation to replace the FT. However, the replacement FT failed its bench test so the licensee cancelled the associated WO. When operators subsequently removed the clearance tags, they incorrectly assumed that the instrument root valves had already been returned to their normal configuration by maintenance personnel.

This mistake resulted in FT 925 being isolated for approximately seven months.

The inspectors reviewed licensee procedure NP 2.1.1, "Conduct of Operations,"

G, Equipment Manipulation and Status Control, Revision 12. Section 3.11, for equipment status controls, stated, in part that, the appropriate work management process will track as found and corresponding as left positions. The inspectors determined that the licensee had failed to follow this procedure and missed an opportunity to prevent this occurrence.

Additionally, the inspectors noted that the FT was a Regulatory Guide (RG) 1.97 (Criteria for Accident Monitoring Instrumentation for Nuclear Power Plants) instrument used for post-accident monitoring and is also used in the licensees emergency operating procedures (EOPs) to monitor SI system flow. The FT was used to ensure the RHR operability when supplying the containment spray pump and/or the SI pump during the containment sump recirculation mode. The licensees maintenance rule evaluation indicated that the transmitter provided a safety-related function for throttling RHR flow when aligned to the containment spray or safety injection systems.

The licensees apparent cause was that the maintenance planning group did not have the desired initial alignment steps for FT-925 in the WO. The contributing cause was that station procedures did not provide guidance to assure status control when aborting work processes. The inspectors concluded that the issue was associated with the tracking of components as required by NP 2.1.1, which was different from the licensees apparent cause.

The inspectors discussed their conclusions with the licensee. Additionally, the inspectors requested the past operability and reportability evaluation for the RHR train and found that the licensee had not evaluated these aspects. As a result of the procedural noncompliance and the lack of historical evaluations, the licensee issued condition report AR01660607, Actions Taken for CR01620143 Untimely and Lacked Rigor. Proposed corrective actions included reviewing the past operability and reportability impacts of the issue, development of a checklist to guide personnel to review an aborted activity, and a review of similar procedures to assess the adequacy of guidance for aborted tasks or alignment control.

Analysis:

The inspectors determined that the failure to follow procedures for maintaining proper configuration of equipment important to safety was a performance deficiency warranting further evaluation.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated December 24, 2009, because it was associated with the Mitigating Systems Cornerstone attribute of configuration control and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure to follow the procedure resulted in not restoring FT-925 to its proper configuration.

The inspectors determined the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings," Tables 3b and 4a for the Mitigating Systems Cornerstone, dated January 10, 2008. The inspectors answered No to all the screening questions in the SDP Phase 1 Screening Worksheet in the Mitigating Systems column; therefore, this finding is of very low safety significance (Green).

The finding has a cross-cutting aspect in the area of human performance, work control, because the licensee failed to control the related work activity by having procedures to address the impact of changes to the work scope or activity on the plant and human performance. Specifically, the licensee work control process failed to provide a barrier to inappropriate configuration management when work processes were cancelled (H.3(a)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be accomplished in accordance with documented instructions, procedures, or drawings. Licensee procedure NP 2.1.1, "Conduct of Operations," Attachment G, Equipment Manipulation and Status Control, Revision 12, Section 3.11, states, in part, that, the appropriate work management process will track as found and corresponding as left positions.

Contrary to this, from July 26, 2010, to February 23, 2011, the licensee failed to track the as-left positions of the isolation valves for FT-925, the 2P-15A SI pump discharge flow transmitter, during the removal of maintenance isolation tags, an activity affecting quality. As a result, the transmitter was inoperable for seven months after the associated isolation valves were left closed.

Because this violation was of very low safety significance (Green) and it was entered into the licensees CAP, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000266/2011003-01; 05000301/2011003-01, Safety Injection Pump Discharge Flow Indicator Left Isolated).

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 SR equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• risk management during integrated leak rate testing and associated procedure changes;

• risk management during procedure ORT 3B testing and movements in outage schedule;

• risk management during heavy rains impacting main generator output transformer (week of April 25); and

• risk management during Unit 2 startup and 2P-29 (the Unit 2 turbine-driven auxiliary feedwater pump) testing.

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

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• RHR heat exchanger shell was not able to be removed;

• wall and flooding barrier protecting vital switchgear room from a condensate storage tank (CST) failure may not be seismically qualified (Temporary Instruction (TI) 2515/183 Inspection Report (IR) 2011010);

• manholes 1 and 2 (containing SR cables) with degraded cable supports; and

• RHR pump operability with tanks in auxiliary building not seismically qualified (TI 2515/183 IR 2011010).

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 FSAR 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.

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

b. Findings

(1) Seismic Qualification of the Condensate Storage Tank and Related Flooding Barriers

Introduction:

The inspectors identified an unresolved item (URI) associated with the wall and flooding barrier between the CST and the non-vital switchgear room because the seismic qualifications were not clearly defined.

Description:

During the performance of TI 2515/183, the inspectors identified a potential deficiency associated with the seismic qualification of the CST, the flooding barriers between the CST and the vital switchgear room, and the ability to protect the related vital switchgear. The inspectors, in consultation with a Region III civil engineer, performed an evaluation of the licensees determination of operability for the issue. The inspectors found that the licensee utilized various elements of seismic qualification utility group (SQUG) methodology and complex calculations to justify operability of the equipment.

The inspectors concluded that this issue is an URI pending a review of the related calculations, use of SQUG methodology, and a review of the Point Beach licensing basis for seismic qualifications (URI 05000266/2011003-02; 05000301/2011003-02, Seismic Qualification of the Condensate Storage Tank and Related Flooding Barriers).

(2) RHR Pump Operability with Tanks in Auxiliary Building Not Seismically Qualified

Introduction:

The inspectors identified an URI for the operability of the RHR pumps because the seismic qualifications of certain water storage tanks in the auxiliary building were not clearly defined.

Description:

During the performance of TI 2515/183 the inspectors identified a potential deficiency associated with the seismic qualification of the RHR pumps because several tanks in auxiliary building were not seismically qualified. The inspectors, in consultation with a Region III civil engineer, performed an evaluation of the licensees determination of operability for the issue. The inspectors found that the licensee utilized various elements of SQUG methodology and complex calculations to justify operability of the equipment. The inspectors concluded that this issue is unresolved pending a review of the related calculations, use of SQUG methodology, and a review of the Point Beach licensing basis for seismic qualifications (URI 05000266/2011003-03; 05000301/2011003-03, RHR Pump Operability with Tanks in Auxiliary Building Not Seismically Qualified).

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modifications:

• 1P-29 instrument air supply from temporary nitrogen bottle assignment (temporary); and

• new battery chargers on D07/D08/D09 (permanent).

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the updated FSAR, and the TSs, as applicable, to verify that the modification did not affect the operability or availability of the affected systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed are listed in the Attachment to this report.

These inspections constituted one temporary modification sample and one permanent plant modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

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

• PM testing RHR pump B (2P-10B) following pump removal and installation (Unit 2);

• PM testing of component cooling water (CCW) pump B (1P-10B) following routine maintenance (Unit 1);

• PM testing of main feedwater (FW) regulating valve bypass following repeat failure during 3B (Unit 2);and

• PM testing of control rod position step counter after repairs (Unit 2).

These activities were selected based upon the structure, system, or component's (SSCs) ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated.

The inspectors evaluated the activities against TSs, the FSAR, 10 CFR Part 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 PM tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the to this report.

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

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 2 refueling outage (RFO), conducted March 1 through June 20, 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. Documents reviewed are listed in the Attachment to this report.

During the RFO, the inspectors observed shutdown activities, portions of the startup, and monitored licensee controls over the outage activities listed below:

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

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

• installation and configuration of 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 OSP requirements were met, and controls over switchyard activities;

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

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

• 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 TSs;

• 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 to verify that debris had not been left which could block emergency core cooling system (ECCS) suction strainers, and reactor physics testing; and

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

This inspection constituted one refueling outage sample as defined in IP 71111.20-05 and completes the partial sample discussed in IR 50000266/2011002; 50000301/2011002 (Section 1R20).

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• Unit 2 containment integrated leak rate test (routine);

• Unit 2 procedure ORT 3C - auxiliary feedwater (AFW) system and AMSAC

[Anticipated Transient Without Scram Mitigating System Actuation Circuitry]

actuation (routine);

• Diesel driven fire pump surveillance (TI 2515/183 - IR 2011010) (routine);

• (Unit 1) procedure ITO8A - cold start of TDAFW pump and valve quarterly SR (inservice testing (IST));

• Unit 2 power range nuclear instruments (routine);

• Unit 2 visual/ultrasonic inspection of liner plate through core holes (IST);

• Unit 1 primary leak rate calculation (OI 55) following downpower for routine testing (reactor coolant system (RCS)); and

• Unit 1 containment A increased sump leakage not evaluated (RCS).

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 FSAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

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

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

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

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers (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 SR 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.

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

b. Findings

(1) Failure to Perform an Operability Evaluation for Leakage Inside Unit 1 Containment

Introduction:

The inspectors identified a finding of very low safety significance and an associated non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to perform an operability evaluation of leakage inside containment when it was identified in September 2010. Specifically, on September 26, 2010, condition report AR01397092 identified increased leakage and a related WO was initiated to inspect Unit 1 containment for the leakage source. However, an evaluation of the leak and leak location/source was not performed as required by licensee procedures.

Description:

On May 22, 2011, as part of other scheduled activities, the licensee assessed increased leakage into the containment sump that had been observed.

The inspectors noted the increase leakage rate and were following the issue to ensure that proper evaluations were being performed.

On September 26, 2010, the licensee identified increased leakage into the Unit 1 containment sump. The inspectors reviewed this issue at that time and, due to the small magnitude (<0.01 gpm [gallons per minute]), and due to the fact the leakage did not appear to be from the primary system as indicated by the dally TS-required surveillances, and because the licensee entered the issue into the CAP, the inspectors elected to allow the licensees corrective action process to evaluate the issue.

On November 22, 2010, the licensee completed an evaluation of the leakage and concluded that it was from the main steam or feedwater system. On January 17, 2011, the licensee completed an operational decision-making (ODM) assessment which created an action plan associated with the leak. During this period and as late as June 20, 2011, members of the operations staff indicated that the leak was from the flange gasket on the steam generator man-way. However, the May 22, entry identified the leakage source as the lower penetration for steam generator level instrument 1CS-462A. Additionally, the licensees revised ODM indicated that actions to correct the leakage would be re-evaluated at leakage rate of 0.33 gpm, and that actions to correct the leakage would be commenced at 0.66 gpm.

The inspectors reviewed AR01653834, which was associated with the newly revised location for the source of the leakage, and found that the immediate operability evaluation did not evaluate the ASME code pressure boundary aspects of the leakage, did not evaluate the effect of the leakage on the supported equipment (the level instrument), and it also concluded that further evaluation needed to be performed to assess a possible containment bypass flow path. The inspectors were concerned that the licensee had not considered the cause of the leakage relative to the ASME Code Class II pressure boundary, specifically the steam generator. Also the operability evaluation failed to recognize that the need to further evaluate containment bypass conditions indicated that the operability of the containment was not assured without further evaluation.

The inspectors concluded that the leakage into the containment sump was a degraded condition per licensee procedure PI-AA-205, Condition Evaluation and Corrective Actions, Revision 10. Procedure PI-AA-205, Step 4.4.1, requires that any condition representing a degraded condition to a SSC required to be operable by TS have an immediate operability evaluation. Because leakage into containment represented potential ASME Code class pressure boundary leakage and/or represented a potential breach in the containment boundary, the inspectors concluded that an operability evaluation should have assessed these conditions. Additionally, the May 2011, operability evaluation associated with AR01653834, did not assess several aspects as described above.

The licensee initiated AR01662339 to assess the inspectors observations relative to the lack of an adequate operability evaluation for the leakage inside containment.

Immediate actions were to perform an operability evaluation of the leakage condition.

Proposed actions include an apparent cause evaluation for the failure to perform the operability evaluation. On June 24, 2011, the licensee completed an operability evaluation of the steam generator leakage. The inspectors reviewed the licensee assessment and concluded that the licensee provided reasonable assurance that the leakage was from a gasket on a modified flange installed upstream of level instrument 1CS-462A. Additionally, the operability evaluation concluded that reasonable assurance of operability existed as long as the leakage remained below approximately 0.5 gpm. Because 0.5 gpm was less than the actions limit of 0.66 gpm identified in the ODM, the inspectors concluded that the ODM developed prior to the operability evaluation was non-conservative with respect to continued plant operation.

Assessment: The inspectors concluded that the failure to perform operability evaluations as required by procedure PI-AA-205 was a performance deficiency warranting further evaluation.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated December 24, 2009, because the finding was associated with the Barrier Integrity Cornerstone attribute of SSC and barrier performance, and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers, specifically the containment, would be able to protect the public from radionuclide releases caused by accidents or events. Additionally, the ODM allowed plant operation beyond the value at which reasonable assurance of operability existed as determined by a subsequent evaluation that was performed as a result of inspector observations.

The inspectors determined the finding could be evaluated using IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Barrier Integrity Cornerstone, dated January 10, 2008 The inspectors answered No to all of the questions in the Containment Barrier column of Table 4a; therefore, the finding screened as very low safety significance (Green).

This finding has a cross-cutting aspect in the area of human performance, decision-making, because the licensee did not use conservative assumptions during the decision-making and review process associated with the degraded condition.

Specifically, the licensees operability evaluation, which was reviewed by multiple levels of management, failed to fully assess the degraded condition; and most significantly, noted that an indeterminate containment bypass condition existed yet failed to declare the containment inoperable. The inspectors considered the licensees proposed causal evaluation, which determined that the cause was related to communications, and although there were contributions from communications the inspectors concluded that these contributors were not as significant as failing to recognize a TS system nonconformance (H.1(b)).

Enforcement:

Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed and accomplished in accordance with the procedures. Contrary to this, on September 26, 2010, when leakage was identified inside containment, the licensee failed to perform an operability evaluation of the condition as required by Procedure PI-AA-205, Step 4.4.1.

Because this violation was of very low safety significance and it was entered into the licensees CAP (as AR01662339), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000266/2011003-04; 05000301/2011003-04, Failure to Perform an Operability Evaluation for Leakage Inside Containment).

(2) Diesel-Driven Fire Pump Loss of Suction During Surveillance Testing

Introduction:

The inspectors identified a URI when the diesel-driven fire pump failed a routine surveillance test.

Description:

On June 21, 2011, the licensee unsatisfactorily performed surveillance test, O-PT-FP-014, Z-935 Portable Diesel-Driven Fire Water Pump Quarterly Functional Test, Revision 4, when the pump was unable to take suction from the lake using the portable strainer. Specifically, on the first of two attempts, the pump strainer clogged with grass; and on the second attempt, when the strainer was moved further into the lake, the strainer turned upright into the air space and the pump lost suction.

The inspectors were unable, at the completion of this inspection period, to ascertain the impact of the failures relative to the regulatory requirements which established the need for the pump. This issue is unresolved pending a review of the failure and procedural adequacy relative to the current licensing basis (URI 05000266/2011003-05; 05000301/2011003-05, Diesel-Driven Fire Pump Loss of Suction During Surveillance Testing).

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications performance indicator (PI) for Unit 1 and Unit 2, for the third quarter 2010 through the second quarter 2011. To determine the accuracy of the PI data reported during this periods, 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 operator narrative logs, issue reports, event reports, and NRC Integrated IRs for the period to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two unplanned scrams with complications samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Leakage PI for Unit 1 and Unit 2 for the third quarter 2010 through the second quarter 2011. To determine the accuracy of the PI data reported, 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, issue reports, event reports, and NRC Integrated IRs for the period to validate the accuracy of the submittals.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two reactor coolant system leakage samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

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

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: 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

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 January through June 2011.

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

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

Observations The inspectors noted that system or equipment problems, although documented in the corrective action program, were not trended within the CAP process. The licensee used the CAP to identify human performance trends and used the NAMS Work Management System to trend equipment issues.

Because of the separation of trending programs, the inspectors selected an apparent equipment trend related to radiation monitor failures and out-of-service times for the semi-annual trend review as the inspectors noted that numerous CAPs were written on these topics. The inspectors also choose this as a semi-annual trend as it related to a URI 05000266/2011002-03; 05000301/2011002-03, Out-of-Service Radiation Monitors Potentially Impact Emergency Classification Ability, related to the radiation monitors being out-of-service impact on emergency plan.

The inspector reviewed out-of-service logs for radiation monitors for the past six months and found that a substantive number of radiation monitors that have been out-of-service, with very few ARs written. Additionally, the inspectors reviewed the licensees trends for the past six months and found that no trends were identified. Based on these results and the impact on the URI, the inspectors turned this item over to the biennial Problem Identification and Resolution team inspection.

b. Findings

No findings were identified.

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

.1 Unplanned Reactor Trip During Low Power Physics Testing Due to Failure of Source

Range Nuclear Instrumentation

a. Inspection Scope

The inspectors reviewed the plants response to a Unit 2 reactor trip that occurred during low power physics testing. The cause of the trip was related to a failed source range monitor causing a reactor protection system actuation when power decreased below the related trip setpoint. All other equipment operated as designed during the reactor trip.

Documents reviewed are listed in the Attachment to this report.

This event follow-up review constituted one sample(s) as defined in IP 71153-05.

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Report (LER) 50000266/2010-004-00, Improper Controls for

Breach of HELB Barrier On June 25, 2010, the licensee blocked the control room door open for replacement of the lock on the door without an analysis of the impact of a high energy line break (HELB)on the control room. This LER was the subject of NCV 05000266/2010003-03; 05000301/2010003-03, Failure to Follow Procedures Needed to Maintain Equipment Operability with Hazard Barriers Out-Of-Service, and discussed in NRC integrated IR 05000266/2010003; 05000301/2010003. This LER is closed.

.3 (Closed) LER 50000266/2010-005-00; 05000301/2010-005-00, Improper Administrative

Controls for HELB Barriers (Closed) LER 50000266/2010-005-01; 05000301/2010-005-01, Improper Administrative Controls for HELB Barriers (Closed) URI 05000266/2010005-04; 05000301/2010005-04, High Energy Line Break Barrier Controls)

Introduction:

A finding of very low safety significance (Green) and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions Procedures, and Drawings, was identified by the inspectors for the licensees failure have appropriate procedures for the control of hazard barriers. Specifically, on August 27, 2010, and as a result of a historical review of plant operating conditions resulting from NRC observations, the licensee identified multiple occurrences of inadequate controls of hazard barriers that resulted from procedures that were inappropriate for the control of the related barriers.

Discussion: On June 25, 2010, the licensee blocked the control room door open for replacement of the lock on the door without an analysis of the impact of a High Energy Line Break (HELB) on the control room. This issue was the subject of LER 50000266/2010-004-00, Improper Controls for Breach of HELB Barrier.

Additionally, the cause of this issue was discussed in NRC IR 05000266/2010003; 05000301/2010003, and was the subject of NCV 05000266/2010003-03;05000301/2010003-03, Failure to Follow Procedures Needed to Maintain Equipment Operability with Hazard Barriers Out-Of-Service.

Because of this observation, the licensee reviewed historical practices related to the HELB issue and evaluated maintenance activities associated with the historical observations. As a result, on August 27, 2010, the licensee issued LER 50000266/2010-005-00, Improper Administrative Controls for HELB Barriers, which indicated that multiple occurrences occurred where HELB barriers were not properly controlled.

The inspectors reviewed the licensee analysis and concluded that the cause of the procedural inadequacy was the failure to properly evaluate and incorporate guidance for hazard barriers into procedures when regulatory issue summary (RIS) 2001-009, Control of Hazard Barriers, was issued. The licensee entered this issue into the CAP as AR01402154, LER Required for Past HELB Issues. Corrective actions related to establishing adequate procedural guidance were completed as a result of the LER and related NCV for the June 25, 2010, issue discussed above.

Licensee Event Report, LER 05000266/2010-005-00; 05000301/2010-005-00 ,

Improper Administrative Controls for HELB Barriers, and supplement LER 05000266/2010-005-01; 05000301/2010-005-01, Improper Controls for Breach of HELB Barriers, and URI 05000266/2010005-04, 05000301/2010005-04, High Energy Line Break Barrier Controls, are closed.

Analysis:

The failure to properly evaluate and incorporate guidance for hazard barriers into procedures when RIS 2001-009, Control of Hazard Barriers, was issued was a performance deficiency warranting further evaluation.

The performance deficiency was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated December 24, 2009, because it was associated with the protection against external events attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Using IMC 0609, Significance Determination Process, Phase 1 Worksheets, dated January 10, 2008, the inspectors concluded that a further risk evaluation was required because the finding represented a loss of safety function for various SR systems in the control room, cable spreading room, and possibly other areas. The Region III Senior Risk Analyst (SRA) performed a Phase 3 analysis since the risk information from Phase 2 (Appendix A, Determining the Safety Significance of Reactor Inspection Findings for At-Power Situations, of IMC 0609) did not contain the appropriate mitigating equipment.

The safety significance of this issue, as discussed in LER 266/2010-005-001, used information based on the licensees review of station logs and security door alarm logs.

The licensees review identified that the HELB doors for the control room and cable spreading room were temporarily defeated during the period of concern (May 1, 2009, through April 30, 2010) and thus could have affected both trains of SR equipment in the event of a HELB. Equipment within these rooms were considered the targets and dominated the risk. Breaches of HELB barriers into rooms that contained only a single train of redundant equipment or were small in size compared to an open doorway were insignificant contributors to the total risk of this finding. The licensee determined that the total exposure time (i.e., time doors were open) was approximately eight hours throughout the period for both control room and cable spreading room doors.

The SRA performed a bounding assessment using initiating event frequency information from NUREG/CR-5750, Rates of Initiating Events at U.S. Nuclear Power Plants:

1987-1995 and a 24-hour exposure time. This NUREG showed the frequency for a steam line break outside of containment as 1E-2/yr. Each of the two main steamline isolation valves has a failure probability of 1E-3 per the NRCs Point Beach SPAR Model. Thus, the frequency of a main steamline break that can be isolated by a main steamline isolation valve is calculated to be approximately 6E-8.

The frequency of a feedwater line break shown in NUREG/CR-5750 is 3.4E-3/yr.

Each of the two main FW isolation valves has a failure probability of 2.9E-4 per NUREG/CR-6928, Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants. Thus, the frequency of a main FW line break that can be isolated by its isolation valve is calculated to be approximately 6E-9.

Based on this, the SRA concluded that the risk significance for this issue was very low (Green). The SRA also reviewed the licensees risk assessment discussed in EC 272009, Revision 0, which also concluded the risk to be very low.

The inspectors determined that there was no cross-cutting aspect associated with this issue because it was related to a failure to incorporate operating experience into procedures for a RIS issued in 2001.

Enforcement:

Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions or procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions or procedures. Contrary to this, on August 27, 2010, the licensee determined that as a result of an inadequate procedures hazard barriers were not historically controlled for multiple issues.

Specifically, the historical procedures for hazard barrier control were determined to be inappropriate for the circumstance because the procedures did not contain adequate guidance to ensure that evaluations were properly performed when hazard barriers were removed from service.

Because of the very low safety significance of this finding and because the finding was entered into the licensees CAP, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000266/2011003-06; 05000301/2011003-06, Failure to Follow Procedures Needed to Maintain Equipment Operability with Hazard Barriers Out-Of-Service).

4OA5 Other Activities

.1 (Closed) NRC Temporary Instruction 2515/183, Follow-up to the Fukushima Daiichi

Nuclear Station Fuel Damage Event The inspectors assessed the activities and actions taken by the licensee to assess its readiness to respond to an event similar to the Fukushima Daiichi nuclear plant fuel damage event. This included

(1) an assessment of the licensees capability to mitigate conditions that may result from beyond design basis events, with a particular emphasis on strategies related to the spent fuel pool, as required by NRC Security Order Section B.5.b issued February 25, 2002, as committed to in severe accident management guidelines (SAMGs), and as required by 10 CFR 50.54(hh);

(2) an assessment of the licensees capability to mitigate station blackout (SBO) conditions, as required by 10 CFR 50.63 and station design bases;

(3) an assessment of the licensees capability to mitigate internal and external flooding events, as required by station design bases; and

(4) an assessment of the thoroughness of the walkdowns and inspections of important equipment needed to mitigate fire and flood events, which were performed by the licensee to identify any potential loss of function of this equipment during seismic events possible for the site.

IR 05000305/2011010 (ML111320368) documented detailed results of this inspection activity. Following issuance of the report, the inspectors conducted detailed follow-up on selected issues.

.2 (Closed) NRC Temporary Instruction 2515/184, Availability and Readiness Inspection of

Severe Accident Management Guidelines On May 20, 2011, the inspectors completed a review of the licensees SAMGs, implemented as a voluntary industry initiative in the 1990s, to determine

(1) whether the SAMGs were available and updated;

(2) whether the licensee had procedures and processes in place to control and update its SAMGs;

(3) the nature and extent of the licensees training of personnel on the use of SAMGs; and

(4) licensee personnels familiarity with SAMG implementation.

The results of this review were provided to the NRC task force chartered by the Executive Director for Operations to conduct a near-term evaluation of the need for agency actions following the Fukushima Daiichi fuel damage event in Japan.

Plant-specific results for Point Beach Nuclear Plant, Unit 1 and Unit 2, were provided as an Enclosure to a Memorandum to the Chief, Reactor Inspection Branch, Division of Inspection and Regional Support, dated June 1, 2011, (ML111520396).

.3 (Closed) Unresolved Item (05000266/2008009-07; 05000301/2008009-07):

Technical Specification Bases and the Design Basis Were Not Consistent with the Technical Specification Regarding EDG Onsite Fuel Oil Storage During the Component Design Bases Inspection completed on July 25, 2008, the team determined that the current FSAR, previous TS Bases, and TS limiting condition for operation (LCO) for EDG fuel oil storage volume were not consistent. Specifically, TS 3.8.3 LCO stated that a minimum fuel inventory of 11,000 gallons was required.

This volume corresponded to a mission time of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. However, FSAR Section 8.8 stated that sufficient fuel is normally maintained between the two underground fuel oil storage tanks to allow one EDG to operate continuously at the required load for 7 days.

In addition, the team noted that operators would not declare the EDGs inoperable unless the fuel oil level was below 11,000 gallons. The team questioned whether the minimum required fuel should be 11,000 gallons or a value representing seven days of operations as described in previous TS Bases and FSAR. The licensee initiated ARs 01131288 and 01131143 to address this issue.

During this inspection, the inspectors consulted the Office of Nuclear Reactor Regulation (NRR). The staff reviewed several documents to reconstruct the license bases for the minimum fuel oil volume storage requirement. The staff noted the following:

• The original Atomic Energy Commission Safety Evaluation Report for the station stated, Onsite fuel storage capacity is sufficient for a minimum of seven days operation of the required safety feature loads which is acceptable. However, TSs required a minimum fuel inventory of 11,000 gallons per tank for a continuous run of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />;

• In 1994, the licensee completed modifications to the fuel storage system which included installation of different capacity tanks. In a letter dated July 11, 1994, the licensee acknowledged the above statement regarding the seven days of operation by adding an operability requirement to the TS Bases. Specifically, through Amendment to TS Change Request 166, the licensee stated, We [the licensee] believe that it would be appropriate to include the seven days fuel oil supply requirement in the TS Bases for Section 15.3.7. As a result, the following statement was added to TS Bases 15.3.7, Therefore, to satisfy this requirement, at least 34,500 gallons of fuel oil will be maintained available for the EDGs at Point Beach at all times when EDG operability is required. It was not clear why this operability requirement was not incorporated into a TS; and

• In its letter to the NRC dated November 15, 1999, the licensee requested to convert its current TSs (CTSs) to improved TSs (ITSs) that modeled the format of the NRCs Standard TSs contained in NUREG-1431. The EDG fuel oil TS and TS Bases were modified as part of the conversion. The licensee stated that the Bases of the CTSs for Section 3.8.3 had been completely replaced by revised Bases that reflected the format and applicable content of ITSs, consistent with the Standard TSs for Westinghouse Plants, NUREG-1431. The licensee categorized this as an administrative change and used this justification to delete the operability statement from the TS Bases. In its letter to the licensee dated August 8, 2001, the NRC approved and issued the Point Beach ITS.

The corresponding TS bases stated, in part, There are two underground fuel oil storage tanks on site []. Each tank has a capacity of approximately 35,000 gallons. Sufficient fuel is normally maintained between the two tanks to allow one diesel to operate continuously at the required load for seven days.

Based on the above and numerous other documents reviewed, it was not clear why the requirement to maintain 35,000 gallons of fuel onsite was placed in the TS Bases and not directly placed in the TS. Because the license bases (TS) consistently stated 11,000 gallons of fuel, no violation of NRC requirements was identified.

However, to address a separate issue, on January 27, 2011, and May 2, 2011, the licensee submitted License Amendment Request 264 and Supplement 1, Diesel Fuel Oil Storage Requirements, to increase the minimum volume of fuel resulting from calculation and operational deficiencies. It should be noted that in Supplement 1 of the request, the licensee addressed the underlining safety concern of this unresolved issue.

Specifically, the licensee enhanced the proposed TS 3.8.3 to better align the fuel oil storage requirements to current industry standards. Therefore, the licensee requested to change the current requirement of 11,000 gallons of fuel to a minimum volume corresponding to six days of EDG operation. This change is currently being reviewed by the NRR staff.

This URI is closed.

.4 Samples Credited for Extended Power Uprate (EPU)

a. Inspection Scope

From April 1 through June 23, 2010, the inspectors performed the following samples to be credited to IP 71004, Power Uprate Inspections.

• Unit 2 Surveillance Procedure, ORT 3C, for AFW system and AMSAC actuation (1R22);

• the inspectors observed plant evolutions during Unit 2 power ascension to the uprated power levels (1R20); and

• preventive maintenance testing of Unit 2 main FW regulating valve bypass following repeat failure during 3B (1R19).

4OA6 Management Meetings

.1 Exit Meeting Summary

On June 30, 2011, inspectors presented the inspection results to Tom Vehec 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.

• the resolution of URI 05000266/2008009-07; 05000301/2008009-07 with Mrs. F. Flentje on June 22, 2011.

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

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Vehec, Plant Manager

C. Trezise, Engineering Director

R. Harrsch, Operations Director

J. Costedio, Licensing Manager

Nuclear Regulatory Commission

M. Kunowski, Chief, Reactor Projects Branch 5

Attachment

LIST OF ITEMS

Opened

05000266/2011003-01; NCV Safety Injection Pump Discharge Flow Indicator Left

05000301/2011003-01 Isolated (Section 1R12)

05000266/2011002-02; URI Seismic Qualification of the Condensate Storage Tank

05000301/2011002-02 and Related Flooding Barriers (Section 1R15.1(1))

05000266/2011003-03; URI RHR Pump Operability with Tanks in Auxiliary Building Not

05000301/2011003-03 Seismically Qualified (Section 1R15.1(2))

05000266/2011003-04; NCV Failure to Perform an Operability Evaluation for Leakage

05000301/2011003-04 Inside Containment (Section 1R22.1(1))

05000266/2011003-05; URI Diesel-Driven Fire Pump Loss of Suction During

05000301/2011003-05 Surveillance Testing (Section 1R22.1(2))

05000266/2011003-06; NCV Failure to Follow Procedures Needed to Maintain

05000301/2011003-06 Equipment Operability with Hazard Barriers Out-Of-Service (Section 4OA3.3)

Closed

05000266/2011003-01; NCV Safety Injection Pump Discharge Flow Indicator Left

05000301/2011003-01 Isolated (Section 1R12)

05000266/2011003-04; NCV Failure to Perform an Operability Evaluation for Leakage

05000301/2011003-04 Inside Containment (Section 1R22.1(1))

05000266/2011003-06; NCV Failure to Follow Procedures Needed to Maintain

05000301/2011003-06 Equipment Operability with Hazard Barriers Out-Of-Service (Section 4OA3.3)

50000266/2010-004-00; LER Improper Controls for Breach of HELB Barrier

05000301/2010-004-00 (Section 4OA3.2)

50000266/2010-005-00; LER Improper Administrative Controls for HELB Barriers

05000301/2010-005-00 (Section 4OA3.3)

05000266/2010-005-01; LER Improper Administrative Controls for HELB Barriers

05000301/2010-005-01 (Section 4OA3.3)

05000266/2010005-04; URI High Energy Line Break Barrier Controls (Section 4OA3.3)

05000301/2010005-04

05000266/2008009-07; URI Technical Specification Bases and the Design Basis Were

05000301/2008009-07 Not Consistent with the Technical Specification Regarding EDG Onsite Fuel Oil Storage (Section 4OA5.3)

2515/183 TI Follow-up to the Fukushima Daiichi Nuclear Station Fuel Damage Event (Section 4OA5.1)

2515/184 TI Availability and Readiness Inspection of Severe Accident Management Guidelines (Section 4OA5.2)

Attachment

Discussed

05000266/2011002-03; URI Out-of-Service Radiation Monitors Potentially Impact

05000301/2011002-03 Emergency Classification Ability (Section 4OA2.3)

05000266/2010003-03; NCV Failure to Follow Procedures Needed to Maintain

05000301/2010003-03 Equipment Operability With Hazard Barriers Out-Of-Service (Section 4OA3.3)

Attachment