IR 05000266/2010003

IR 05000266-10-003, 05000301-10-003; 04/01/2010 - 06/30/2010; Point Beach Nuclear Plant, Units 1 & 2; Adverse Weather Protection, Equipment Alignment, Operability Evaluations, and Other Activities

ML102180241
Person / Time
Site:	Point Beach
Issue date:	08/06/2010
From:	Michael Kunowski NRC/RGN-III/DRP/B5
To:	Meyer L Point Beach
References
IR-10-003
Download: ML102180241 (56)

Text

gust 6, 2010

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000266/2010003; 05000301/2010003

Dear Mr. Meyer:

On June 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on July 1, 2010, 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 your personnel.

Based on the results of this inspection, four NRC-identified findings of very low safety significance were identified. The findings involved violations of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations (NCVs) in accordance with Section VI.A.1 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 disagreement, 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/ by John Jandovitz Acting For/

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 05000266/2010003; 05000301/2010003 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-266; 50-301 License Nos: DPR-24; DPR-27 Report No: 05000266/2010003; 05000301/2010003 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: April 1, 2010, through June 30, 2010 Inspectors: S. Burton, Senior Resident Inspector R. Ruiz, Resident Inspector M. Thorpe-Kavanaugh, Resident Inspector (Acting)

K. Barclay, Resident Inspector, Kewaunee Power Station N. Feliz-Adorno, Reactor Engineer P. Cardona-Morales, Reactor Engineer Approved by: Michael A. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000266/2010003, 05000301/2010003; 04/01/2010 - 06/30/2010; Point Beach Nuclear

Plant, Units 1 & 2; Adverse Weather Protection, Equipment Alignment, Operability Evaluations, and Other Activities.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Four Green findings were identified by the inspectors. These 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: Initiating Events

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 follow procedural/instructional guidance contained in a temporary procedure for the maintenance of high energy line break (HELB) barriers. Specifically, on June 25, 2010, the licensee placed a wedge under the control room door, a HELB barrier, contrary to the guidance contained in Operations Notebook procedure/instruction, HELB Barrier/Vent Path Temporary Guidance. The licensee entered this item into its corrective action program.

This performance deficiency was more than minor because it was associated with the Initiating Events Cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability and reliability of equipment needed to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure to maintain the control room door available as a supporting structure, system, or component (SSC) for control room equipment availability/operability during a HELB impacted the reliability and the operability of affected control room SSCs. The finding screened as having very low safety significance (Green) because of its short exposure, approximately 0.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.

The finding had a cross-cutting aspect in the area of human performance, work practices, because the licensees staff was familiar with and had been briefed on ,

HELB Barrier/Vent Path Temporary Guidance in the Operations Notebook yet had failed to implement human error prevention techniques such as pre-job briefing or peer checking, which, if performed, could have ensured that maintenance on the control room door was performed as required by the operations notebook procedure (H.4(a)).

(Section 1R15)

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and 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 implement a required abnormal operating procedure (AOP) during a period of impending severe weather. Specifically, the licensee failed to enter AOP-13C, Severe Weather Conditions, during a tornado warning issued by the National Weather Service for the specific location of the plant.

The licensee immediately entered the issue into its corrective action program and conducted an apparent cause evaluation of the conditions.

This performance deficiency was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of protection against external events and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The finding was determined to be of very low safety significance (Green) because it did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors), and did not involve the total loss of any safety function. This finding has a cross-cutting aspect in the area of human performance, resources, because the licensee did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the entry conditions in AOP-13C were out-of-date and failed to provide an adequate nexus between the purpose and instructions of the procedure (H.2(c)). (Section 1R01)

Green.

A finding of very low safety significance and associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the failure of the licensees modification process to ensure that new 480-volt cables, installed for the future repowering of various auxiliary feedwater (AFW) system motor-operated valves, were installed in accordance with applicable regulatory requirements. Specifically, a seismic design evaluation was not completed prior to the installation of a cable coil suspended above the 2MS-2020 valve, 2P-29 turbine-driven AFW pump steam supply. In response to this issue, the licensee installed more robust restraints that satisfied seismic acceptability criteria and performed an evaluation that showed the interim condition of the modification did not challenge operability. At the conclusion of this inspection period, the licensee was in the process of conducting a root cause evaluation. The inspectors also noted that a very similar issue at this site resulted in the issuance of a NCV in the second quarter of 2009.

This performance deficiency was more than minor because it was associated with the Mitigating Systems Cornerstone attribute of design control and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, once identified, the modification required rework to comply with applicable design requirements. The inspectors determined the finding was of very low safety significance (Green) because the issue did not result in the actual loss of a safety function. The inspectors also determined the finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because the licensee failed to implement appropriate corrective actions for a previous violation with the same performance deficiency (P.1(d)). (Section 1R04)

Green.

A finding of very low safety significance and associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure to provide procedures that were appropriate to verify and document the design of new or modified SSCs with respect to seismic II/I interactions. Specifically, the procedures used for seismic II/I interaction evaluations of new or modified SSCs did not provide guidance for evaluating equipment that was not represented in the earthquake experience or generic testing equipment classes under the scope of the Seismic Qualification Utility Group methodology. Also, no formal guidance was incorporated in modification and seismic procedures to document seismic II/I interaction evaluations. As a result, the licensee did not perform an evaluation that was in accordance with the licensing basis to verify the design of the B containment sump strainers of Units 1 and 2 with respect to potential seismic II/I interactions. The licensee entered this issue into its corrective action program.

The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of protection against external events and adversely affected the cornerstone objective of ensuring the capability of systems that respond to initiating events to prevent undesirable consequences. This finding was of very low safety significance (Green) because it was a qualification deficiency confirmed not to result in loss of operability or functionality.

The inspectors determined that the finding had a cross-cutting aspect in the area of problem identification and resolution, self and independent assessments, because the licensee did not conduct self-assessments of the Seismic Qualification Utility Group program (P.3(a)). (Section 4OA5)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period shut down for the continuation of a planned refueling outage that began in the previous inspection period on March 1, 2010, and ended April 4, 2010. With the exceptions of small power reductions during routine surveillance testing, the unit remained at full power for the remainder of the inspection period.

Unit 2 operated at 100 percent power throughout the entire inspection period with the exception of: small power reductions during routine surveillance testing; and an unscheduled outage from June 19 through June 20, 2010, as a result of a main generator trip and manual reactor trip while at reduced power for condenser cleaning.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition - Tornado Warning

a. Inspection Scope

Since severe thunderstorms, which had already produced tornado activity and high winds in nearby counties, were forecast in the vicinity of the facility for May 4, 2010, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined if the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors ensured the plant grounds were walked down 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 Final Safety Analysis Report (FSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate specified by plant-specific procedures. The inspectors also reviewed a sample of corrective action program (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 Inspection Procedure (IP) 71111.01-05.

b. Findings

Failure to Enter Abnormal Operating Procedure During Tornado Warning

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the licensees failure to implement a required abnormal operating procedure (AOP) during a period of impending severe weather. Specifically, the licensee failed to enter AOP-13C, Severe Weather Conditions, during a tornado warning issued by the National Weather Service for the specific location of the plant.

Description:

On May 4, 2010, the National Weather Service in Green Bay, WI, issued a tornado warning effective for the plants location in northern Manitowoc County from 7:58 p.m. to 8:30 p.m. The warning specifically stated this dangerous storm will be near Two Creeks around 8:25 p.m., an area in the immediate vicinity of Point Beach Nuclear Plant.

During a follow-up review of the licensees response to the warning, the inspectors reviewed operator logs and AOP-13C, whose stated purpose is To outline actions to be addressed to protect personnel and equipment at Point Beach during severe weather warnings or actual severe weather conditions. Through the review of operator logs and interviews, the inspectors identified that the licensee had not entered AOP-13C on May 4.

The licensee later reported that some of the AOP actions were performed on May 4, such as the suspension of risk-significant work activities and the application of the adverse weather factor to the safety monitor risk management program; however, because AOP-13C was not actually entered, the licensee did not perform all of the applicable steps delineated in Attachment A of the AOP, entitled Response to High Winds, such as installing various door braces. The failure to secure roll-up doors in accordance with the AOP instructions could have led to unnecessary, or more extensive, damage to safety-related or risk-significant SSCs within the plant during an actual tornado or high wind event.

When the inspectors inquired about the reason why the AOP had not been entered, the licensee stated that the specific symptoms and entry conditions in the procedure were not met. Specifically, the licensee stated that condition B.1.a of AOP-13C, which states Storm warning via WE [Wisconsin Electric] Energies Power System Supervisor (WEPSS), Appleton dispatcher, or police radio, was not satisfied because the site never received notification of the tornado warning from those specific sources. A further review of the operator logs for May 4 showed that on three separate occasions (at 7:52 p.m., 8:14 p.m., and 8:30 p.m.) various members of the operating crew wrote the following log entries which provided evidence that the operating crew was aware of the tornado warning at the time: Entered Severe Weather test factor into Safety Monitor due to Tornado Warning for Manitowoc County; Suspending 1-TS-ECCS-002 Train B

SAFEGUARDS

SYSTEM VENTING Unit 1, Due to tornado warning, and severe weather; and Severe Weather Test factor removed from Safety Monitor due to cancellation of Tornado Warning. Further, members of the licensee staff outdoors at the time reported to operations that tornado sirens in the area were sounding.

Additionally, the licensee stated that the operations staff was monitoring the onsite meteorological conditions and that, if high winds actually became present at the site, the AOP would have reactively been entered and the remaining actions completed.

However, due to the potential for a fast-moving storm to rapidly change conditions onsite, the inspectors determined it would have been inappropriate to delay entry into the AOP in the presence of a known, active tornado warning. Specifically, the inspectors concluded that there may not be enough time to complete the other required actions of the AOP to prevent damage to plant equipment once the storm has already arrived.

The inspectors noted that section 4.2.6 of FPL nuclear fleet procedure PI-AA-103-1000, Human Performance Program Error Reduction Tools, Revision 1, states Following the procedure without question does not guarantee safety because procedures contain hidden flaws. But, understanding the overall purpose and strategy of the procedure promotes safer outcomes. The procedure further states, Procedure adherence means understanding a procedures purpose, scope, and intent and following its direction.

However, the licensee failed to adhere to the purpose of AOP-13C when the decision was made to not enter the procedure because they were not notified of the warning by one of the specific sources listed in the procedure. This occurred despite the fact that the operating crew was aware of the severe weather warning as shown by multiple log entries.

Analysis:

The inspectors determined that the failure to enter AOP-13C during a tornado warning was contrary to the purpose and intent of the procedure and was a performance deficiency. 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 protection against external events and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, by failing to enter AOP-13C, the equipment protective measures outlined in Attachment A, Response to High Winds, were not fully performed, and as a result, the cornerstone objective was impacted.

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 4b, Seismic, Flooding, and Severe Weather Screening Criteria, dated January 10, 2008, for the Mitigating Systems Cornerstone. The finding was determined to be of very low safety significance (Green)because the finding did not involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors), and did not involve the total loss of any safety function identified by the licensee through a risk analysis, that contributes to external event initiated core damage accident sequences (i.e., initiated by a seismic, flooding, or severe weather event).

This finding has a cross-cutting aspect in the area of human performance, resources, because the licensee did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety. Specifically, the resources associated with the Symptoms or Entry Conditions proceduralized in AOP-13C, Revision 21, were inadequate in a number of ways, including, but not limited to:

(1) out-of-date reliance upon receipt of storm warning notifications from an entity (i.e., Wisconsin Electric) no longer associated with Point Beach;

(2) reliance upon storm warning notifications through monitoring of a police radio, when the operating crew does not actively monitor the police radio at a sufficient frequency or volume level to credit its use as a reliable means of notification; and

(3) narrowly focused entry criteria that do not allow sufficient flexibility to address realistic entry conditions(H.2(c)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Additionally, section 4.2.6 of FPL nuclear fleet procedure PI-AA-103-1000, Human Performance Program Error Reduction Tools, Revision 1, states, Following the procedure without question does not guarantee safety because procedures contain hidden flaws. But, understanding the overall purpose and strategy of the procedure promotes safer outcomes. The procedure further states Procedure adherence means understanding a procedures purpose, scope, and intent and following its direction.

Contrary to this, on May 4, 2010, the licensee failed to accomplish the instructions of a safety-related procedure during a period when conditions existed for which the procedure was created. Specifically, the failure to enter AOP-13C during a known tornado warning was contrary to the documented purpose and intent of this safety-related procedure, and explicitly conflicted with the directions contained within the body of the procedure. The licensee immediately entered the issue into its corrective action program and conducted an apparent cause evaluation (ACE).

Because this violation was of very low safety significance and it was entered into the licensees corrective action program as AR 01172921, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000266/2010003-01; 05000301/2010003-01, Failure to Enter Abnormal Operating Procedure During Tornado Warning).

.2 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 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 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.

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

b. Findings

No findings of significance were identified.

.3 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 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 review focused specifically on the service water and component cooling water systems.

This inspection constituted one seasonal adverse weather sample as defined in IP 71111.01-05.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• 4160-Volt safety buses;

• 480-Volt safety buses;

• Unit 1 - low temperature overpressure protection system; and

• Unit 2 - turbine-driven auxiliary feedwater pump after return to service from maintenance.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, 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 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 to this report.

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

b. Findings

Failure to Control the Design of Partially Installed Modifications for Seismic Requirements

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the failure of the licensees modification process to ensure that new 480-Volt cables, installed for the upcoming repowering of various auxiliary feedwater (AFW) system motor-operated valves, were installed in accordance with applicable regulatory requirements. Specifically, no seismic design evaluation was completed prior to the installation of a coil of cable suspended above the motor operator for 2MS 2020, 2P-29 turbine-driven AFW (TDAFW) pump steam supply valve.

Description:

On June 16, 2010, while performing a system walkdown of the Unit 2 AFW system, inspectors noted that a significant quantity of cable was suspended above the 2MS-2020 steam supply valve for the 2P-29 TDAFW pump. This bundle of cable, which was estimated by the licensee to weigh about 40 pounds, was hanging from a nearby pipe support and was tied off with nylon rope, secured with two knots. The location of the suspended cables was such that the bundle was directly suspended over the manual declutch lever of the 2MS-2020 motor operator, and was separated by a distance of about one inch, measured vertically. The inspectors determined that if the rope broke or the knots came loose from settling or during a seismic event, the cable would have come in contact with the motor operator, declutch lever, or the valve body below. Inspectors noted that if the 2MS-2020 valve was rendered inoperable, then the 2P-29 TDAFW pump would have been inoperable.

The suspended cables resulted from Engineering Change (EC) 1339, which was developed to repower valves for the 2P-29 TDAFW pump. The 480V power cable to the 2MS-2020 valve was anticipated to remain in this configuration until it was connected at some later date. On May 27, 2010, the new cable was pulled, coiled, and hung from an adjacent pipe support near the 2MS-2020 motor operator, where it was intended to remain until future installation. The inspectors reviewed EC 13399 and its associated 10 CFR 50.59 screening and found that no seismic evaluation was present or discussed regarding the interim configuration of the cable installation. A seismic evaluation of the as-found interim configuration of the cable was not performed until June 17, 2010, after the issue was discovered by the inspectors and communicated to the licensee.

The licensee documented the inspectors observations in AR 01175527.

Immediate corrective actions by the licensee included moving the bundle of cable to a location further away from the motor operator and reinforcing the nylon rope with acceptable restraints to preclude any seismic interactions with the component.

Additionally, the licensee performed an extent-of-condition walkdown and identified that a second valve, 2MS-2019, had a similar configuration of suspended cable. At that point, the as-left configurations were inspected by a seismic qualification utility group (SQUG) qualified structural engineer and deemed adequate.

Inspectors noted that a very similar issue arose at this site in the second quarter of 2009, which resulted in the issuance of NCV 05000266/2009003-01; 05000301/2009003-01 for failing to adequately control the seismic design aspects of a coil of cables that were similarly inadequately suspended above safety-related components of the AFW system.

As a result of that incident, the licensee implemented a number of corrective actions to provide additional seismic awareness training and additional SQUG-related communications to the appropriate work groups at the time. Because of the repeat nature of this finding, the licensee was in the process of conducting a root cause evaluation for the current issue at the conclusion of this inspection period.

Analysis:

The inspectors determined that the licensees continued failure to adequately assess the potential seismic interactions that newly installed components may pose on currently installed SSCs was a performance deficiency. 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 design control and adversely affected the cornerstone objectives of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, once identified, the modification required rework to comply with applicable design requirements.

In accordance with IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," dated January 10, 2008, the inspectors conducted a Phase 1 SDP screening and determined the finding to be of very low safety significance (Green) because the finding was not a design or qualification deficiency resulting in a loss of functionality, did not represent a loss of system safety function or loss of a single train for greater than its allowed TS time, and did not screen as potentially risk significant due to seismic, flooding, or severe weather initiating events.

The inspectors determined the finding was of very low safety significance (Green)because the issue did not result in the actual loss of a safety function.

The inspectors determined that the finding had a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because the licensee failed to implement appropriate corrective actions for the previous violation, which resulted from the same performance deficiency. Specifically, the corrective actions for NCV 05000266/2009003-01; 05000301/2009003-01 from mid-2009 did not result in any changes or improvements to the modification processes or procedures. Rather, the licensee elected to provide additional one-time training to the individuals involved, and to various associated personnel. The inspectors noted that a number of individuals from workgroups currently responsible for cable installations, and various other installations throughout the plant, were not working at Point Beach at the time of the previous violation, and as such, did not receive the additional seismic training/information.

This included individuals involved with the specific cable installation in question. Due to the narrow scope of the previous corrective actions, and their apparent ineffectiveness at correcting the performance deficiency, the inspectors determined that the corrective actions were not appropriate nor commensurate with the safety significance of the issue (P.1(d)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions.

Contrary to this, prior to June 24, 2009, the licensee failed to correctly translate applicable design basis into the modification design specification. Specifically, design control measures failed to account for seismic requirements for 4160-volt electrical cables hanging over the operable TDAFWPs.

Upon notification by the inspectors, the licensee immediately entered the condition into its CAP and moved the bundle of cable to a location further away from the motor operator and reinforced the nylon rope with acceptable restraints to preclude any seismic interaction with the surrounding components. Additionally, the licensee performed an extent-of-condition walkdown. The as-left configurations were inspected by a SQUG-qualified structural engineer and deemed adequate. At the end of this inspection period, the licensee was also conducting a root cause evaluation of this issue.

Because this violation was of very low safety significance and it was entered into the licensees CAP as AR 01175527, this violation is being treated as a NCV consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000266/2010003-02; 05000301/2010003-02, Failure to Control the Design of Partially Installed Modifications for Seismic Requirements).

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On April 12, 2010, the inspectors performed a complete system alignment inspection of the pressurizer power-operated relief valve system, after its return-to-service from an outage, 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, and 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 walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings of significance 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 308, 4160-Volt vital switchgear room;

• fire zone 318, cable spreading room;

• Unit 1 - fire zone 304S, north AFW pump room and vital switch gear room; and

• Unit 2 - fire zone 304N, south AFW pump room and vital switch gear 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.

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.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On June 7, 2010, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and 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 of significance were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• 4160-Volt safety buses;

• 480-Volt safety buses; and

• safety injection due to multiple level instrument issues.

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

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• maintenance risk and emergent work during temporary condensate storage tank evolution (Unresolved Item (URI) 2010002-04);

• maintenance risk and emergent work during failure of Unit 2 TDAFW pump;

• maintenance risk assessment of historical risk management when errors existed in safety monitor associated with service water pump mapping;

• maintenance risk assessment of routine and emergent work for the week of June 1, 2010, including the unplanned inoperability of the 2P-11A component cooling water pump; and

• maintenance risk assessment and emergent work during failure of Unit 2 plant process computer system Channel 3 multiplexer.

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.

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

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Unit 1 - steam generator logic wiring discrepancies found during performance of surveillance testing;

• Unit 2 - containment fan coils exceed plugging limits due to zebra mussel kill;

• Unit 2 - post-operability of Unit 2 TDAFW pump due to water intrusion in bearing; and

• equipment operability with high energy line break (HELB) barriers out-of-service.

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

Equipment Operability with Hazard Barriers Out-Of-Service

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions Procedures, and Drawings, was identified by the inspectors for the licensees failure to follow procedural/instructional guidance contained in a temporary procedure for the maintenance of HELB barriers.

Specifically, on June 25, 2010, the licensee placed a wedge under the control room door, a HELB barrier, contrary to the guidance contained in Operations Notebook procedure/instruction, HELB Barrier/Vent Path Temporary Guidance.

Description:

While reviewing maintenance activities associated with the battery D-05 replacement, the inspectors noted that a blind penetration had been reconfigured to allow cable access to the D-05 battery via the related vital switchgear room.

Because this issue was similar to a HELB issues identified in the first quarter, the inspectors reviewed related procedures and operator guidance to determine if operability of technical specification related equipment in the vital switchgear room had been affected.

The inspectors reviewed procedure NP 8.4.16, PBNP High Energy Line Break Barriers/Vent Paths, Revision 14, and found that the procedure allowed designated penetrations to be out-of-service for 24 consecutive hours and allowed designated doors to be out of service for 12 consecutive hours. The inspectors reviewed the guidance provided in NRC Regulatory Issue Summary (RIS) 2001-009, Control of Hazard Barriers, which indicated that risk must be managed in accordance with 10 CFR 50.65(a)(4) of the maintenance rule and that the TS operability requirements should be evaluated using the appropriate operability guidance.

The inspectors concluded that NP 8.4.16 may adequately control risk for the removed HELB barriers; however, the risk basis for the 24- and 12-hour allowed out-of-service times was not reviewed by the inspectors. The inspectors noted that procedure NP 8.4.16 did not provide guidance to perform an operability evaluation for TS SSCs that were impacted when a HELB barrier was removed from service. Additionally, the inspectors did not find any generic licensee guidance relative to control of hazard barriers. The various hazard barriers, such as fire barriers, HELB barriers, and flood barriers, had procedures specific to their type, and a review of these procedures also did not reveal any guidance relative to assessing the operability of TS SSCs.

The inspectors communicated their observations to the licensee relative to RIS 2001-009 and TS operability requirements for various hazard barrier items on several occasions between March 23 and June 8, 2010. During these discussions, the inspectors expressed concern that TS SSCs were not being evaluated for operability when supporting hazard barriers were being removed from service. The inspectors noted that the related operating experience, RIS 2001-009, and RIS 2005-20, Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, warranted these reviews.

On June 11, 2010, the licensee created Operations Notebook temporary instruction, HELB Barrier/Vent Path Temporary Guidance, which clarified HELB barrier breaches that did not require prior approval, an engineering evaluation, or entry into a TS action statement as a result of operability issues. One requirement of this procedure stated that, Normal ingress and egress through HELB barrier doors. Doors may be held open by hand but shall NOT be blocked open or held open by some other device.

On June 25, while performing a plant tour, a visiting NRC inspector observed the licensee placing a wedge under the control room door and questioned the acceptability of the activity. The shift manger and shift technical advisor (STA) quoted procedure the NP 8.4.16 requirements and provided the inspector a copy of the related pages.

Subsequently, the resident inspectors discussed the matter with with the shift manager and the STA and pointed out the prohibition about wedging the control room door open and that the HELB Barrier/Vent Path Temporary Guidance indicated that NP 8.4.16 was under revision to eliminate the 12 & 24 hr allowance and require Design Engineering review and approval before a barrier is breached. The work order for the repair of the control room door indicated that the out-of-service time was 36 minutes.

Because the Operations Notebook instruction, HELB Barrier/Vent Path Temporary Guidance, prohibited the wedging open of the control room door, this performance deficiency was evaluated as a procedural noncompliance. This issue was entered into the licensees corrective action program as condition report CAP01176020.

Immediate corrective actions were taken to review all temporary instructions with appropriated staff; additional corrective actions will be assessed in the corrective action process.

Analysis:

The inspectors determined that the failure to follow the Operations Notebook instruction, HELB Barrier/Vent Path Temporary Guidance, which prohibited operation with the control room door wedged open, was a performance deficiency warranting further review.

The finding was determined to be more than minor because in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated December 24, 2009, it was associated with the Initiating Events Cornerstone attribute of equipment performance and adversely affected the cornerstone objective of ensuring the availability and reliability of equipment needed to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations.

Specifically, the failure to maintain the control room door available as a supporting SSC for control room equipment availability/operability during a HELB impacted the reliability and the operability of affected control room SSCs.

The inspectors evaluated the issue using the SDP in accordance with IMC 0609, Significance Determination Process, Appendix A, under the Initiating Events Cornerstone and determined that the finding was a transient initiator that contributed to the likelihood of a reactor trip and that mitigation equipment or functions would not be available. Therefore, the issue was reviewed with the Senior Reactor Analyst and, due to the short exposure of the issue, approximately 0.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, the event screened as Green.

The inspectors also determined that the finding has a cross-cutting aspect in the area of human performance, work practices, because the licensees staff was familiar with and had been briefed on , HELB Barrier/Vent Path Temporary Guidance in the Operations Notebook yet had failed to implement human error prevention techniques such as pre-job briefing or peer checking, which, if performed, could have ensured that maintenance on the control room door was performed as required by the operations notebook procedure (H.4(a)).

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 theses instructions or procedures. Contrary to this, on June 25, 2010, the licensee failed to follow guidance contained in the Operations Notebook temporary instruction/procedure , HELB Barrier/Vent Path Temporary Guidance for an activity affecting quality , when the control room door was propped open during maintenance.

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 a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000266/2010003-03; 05000301/2010003-03, Failure to Follow Procedures Needed to Maintain Equipment Operability with Hazard Barriers Out-Of-Service).

1R18 Plant Modifications

.1 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification:

• temporary modification installed for core bore through HELB barrier for M-3-5-17-F203 penetration.

The inspectors compared the temporary configuration changes and associated 10 CFR 50.59 screening and evaluation information against the design basis, the FSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors also compared the licensees information to operating experience information to ensure that lessons-learned from other utilities had been incorporated into the licensees decision to implement the temporary modification. The inspectors, as applicable, performed field verifications to ensure that the modifications were installed as directed; the modifications operated as expected; 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. Lastly, the inspectors discussed the temporary modification with operations, engineering, and training personnel to ensure that the individuals were aware of how extended operation with the temporary modification in place could impact overall plant performance. Documents reviewed are listed in the to this report.

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

b. Findings

No findings of significance were identified.

.2 Permanent Plant Modifications

a. Inspection Scope

The following engineering design package was reviewed and selected aspects were discussed with engineering personnel:

• HELB barrier - permanent installation of a 3 line for M-3-5-17-F203 penetration as part of EC 13398; repower valves for TDAFW pump 1P-29.

This document and related documentation were reviewed for adequacy of the associated 10 CFR 50.59 safety evaluation screening, consideration of design parameters, implementation of the modification, post-modification testing, and relevant procedures, design, and licensing documents were properly updated. The inspectors observed ongoing and completed work activities to verify that installation was consistent with the design control documents. The modification changed the power supply for motor-operated valve 1AF-04006 from an AC supply panel to a direct current (DC)supply panel.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one permanent plant modification samples as defined in IP 71111.18-05.

b. Findings

No findings of significance 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:

• Unit 1 - atmospheric steam dump A repair after it was found not fully seated;

• Unit 1 - channel 3 reactor hot leg temperature sensor failed during reactor startup;

• D-05 battery replacement;

• Unit 2 - service water strainer outlet valve replaced due to leakage; and

• Unit 2 - TDAFW pump steam leak repair.

These activities were selected based upon the SSC's 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 TS, the FSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to verify that the test results demonstrated that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings of significance were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 1 refueling outage (RFO), conducted from March 1, 2010, through April 4, 2010, to confirm that the licensee had appropriately considered risk, industry experience, and previous site specific problems in developing and implementing a plan that assured maintenance of defense in depth. During the RFO, the inspectors monitored licensee controls over the outage activities listed below. Documents reviewed during the inspection are listed in the Attachment to this report.

• 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;

• 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;

• startup and ascension to full power operation, tracking of startup prerequisites, walkdown of containment to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing; and

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

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

b. Findings

No findings of significance were identified.

.2 Other Outage Activities: Unplanned Unit 2 Outage Due To An Improperly Set Relay

a. Inspection Scope

The inspectors evaluated outage activities for an unscheduled outage that began on June 19 and continued through June 20, 2010. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.

The inspectors observed or reviewed the reactor shutdown, outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, forced outage work lists, maintenance and repair activities, startup activities, and identification and resolution of problems associated with the outage.

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

b. Findings

Unresolved Item (URI) - Potential Degradation of Reactor Protection System P-9 Permissive Operability

Introduction:

During the forced outage, the inspectors identified an URI regarding the licensees utilization of the P-9 permissive below 50 percent power with less than full condenser steam dump capacity available. Specifically, the inspectors identified that operation in this condition had the potential to have been in violation of TS 3.3.1, condition S.2, or TS 3.0.3.

Description:

On Saturday, June 19, 2010, the inspector responded to the plant for a Unit 2 unplanned reactor trip. Prior to the trip, Unit 2 was at 44 percent reactor power for condenser cleaning activities. The plant alignment had one circulating water pump secured and the steam dumps to the related condenser bays tagged out-of-service in anticipation of workers entering the related water-boxes for maintenance. At this power level, the main generator monitoring circuitry incorrectly sensed a fault on the generator, which resulted in a generator trip and a related turbine trip. As a result of the turbine trip, reactor controls sensed a power mismatch and automatically inserted control rods to control reactor coolant temperature. However, with half of the steam dumps out-of-service, operators were unable to stabilize reactor power and inserted a manual reactor trip.

The inspectors reviewed operator and equipment performance during the transient and noted no significant issues; however, the inspectors noted that the P-9 permissive was in effect at the time of the transient. The P-9 permissive is a TS reactor protection system feature that bypasses the reactor trip on a turbine trip when the reactor power is less than 50 percent. At Point Beach, the plant design was that the condenser steam dump system, when at full functional capacity, was capable of coping, without operator involvement, with a 40 percent load rejection and an additional 10 percent load reduction can be accounted for by the insertion of the control rods. The inspectors were concerned that the designed automatic plant response following the turbine trip was defeated as a result of the the licensee taking half of the steam dumps out-of-service.

Had the steam dump system been at full capacity, the transient would have been much smaller, more easily controllable, and would have required little, if any, manual operator intervention.

The inspectors reviewed generic plant information and found that not all Westinghouse plants utilize the P-9 permissive and that the permissive is a function of steam dump capacity. Subsequently, the inspectors reviewed the licensees current licensing basis and were unable to determine, before the end of the inspection period, if the steam dump capacity was a basis or an input into design assumptions for the P-9 permissive circuit. However, the related TS basis stated that Below the P-9 setpoint, a load rejection can be accommodated by the Steam Dump System, and In MODE 1, a turbine trip could cause a load rejection beyond the capacity of the steam dump system, so the Power Range Neutron Flux interlock must be OPERABLE. The inspectors concluded that with half of the steam dump capacity unavailable, the load rejection could not have been accommodated by the steam dump system as stated. Based on the statements in the TS basis, the licensee is reviewing the acceptability of bypassing steam dumps below 50 percent reactor power and continuing to call the P-9 function operable with less than full steam dump capacity available.

The inspectors further questioned the licensees statement in AR 01175719, initiated on June 21, 2010, which stated in this alignment with four dumps out-of-service, the condenser steam dumps do not operate as designed in Automatic, therefore, the mode selector switch will be placed in manual....The switch will be left in manual throughout the duration of the condenser water box cleaning. The condition report further stated that in manual/pressure control mode, the steam dump valves no longer have the ability to blow open in less than 3 seconds; instead, the steam dump valves could take as long as 20 seconds to open in this mode.

This issue is unresolved pending the licensees evaluation of the technical basis for the P-9 permissive reactor protection interlock, and pending the evaluation of the effects of operation below 50 percent power with steam dump valves out-of-service or in manual mode (URI 05000266/2010003-04; 05000301/2010003-04, Potential Degradation of Reactor Protection System P-9 Permissive Operability).

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:

• emergency diesel generator (EDG) monthly testing practices - TS-81, TS-82, TS-83, TS-84 (routine);

• Unit 1 - ORT 3A: safety injection actuation with loss of engineered safeguards AC (train A) (routine);

• EDG G-02 endurance run surveillance test (routine);

• Unit 2 - TDAFW pump quarterly test (Inservice Testing - IST);

• pressurizer power-operated relief valve and block valve test (IST); and

• Unit 1 reactor coolant system (RCS) leakage surveillance - containment sump level refueling calibration (RCS leakrate).

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

• did preconditioning occur;

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

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

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

• as-left setpoints were within required ranges; and the calibration frequency were 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 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.

This inspection constituted three routine surveillance testing samples, two IST samples, and one RCS leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings of significance were identified.

.2 Surveillance Testing Associated with Temporary Instruction (TI) 2515/177,

Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems

a. Inspection Scope

When reviewing procedure 2-TS-ECCS-002 Train B, Safeguards System Venting (Monthly) Unit 2, the inspectors verified it was acceptable for void elimination methods.

Additionally, the inspectors reviewed an associated WO used to perform ultrasonic testing (UT) of system pipes for void detection.

The inspectors reviewed instructions and procedures used for conducting surveillances and determination of void volumes to ensure that the void criteria were satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.a). Also, the inspectors reviewed procedures used for filling and venting following conditions which may have introduced voids into the subject systems to verify that the procedures acceptably addressed testing for such voids and provided acceptable processes for their reduction or elimination (TI 2515/177, Section 04.03.b). Additionally, the inspectors interviewed the licensee gas accumulation management program owner. Further, the inspectors verified that issues identified during this inspection were captured in the licensees CAP such that the aspects below were either verified or a corrective action document generated to address the issue.

Specifically, the inspectors verified that:

• gas venting, monitoring, evaluation, and void correction activities were acceptably controlled by approved operating procedures (TI 2515/177, Section 04.03.c.1);

• procedure ensured the system did not contain voids that may jeopardize operability (TI 2515/177, Section 04.03.c.2);

• procedure established that void criteria were satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.c.3);

• the licensee entered changes into the CAP as needed to ensure acceptable response to issues; in addition, the inspectors confirmed that a clear schedule for completion was included for CAP entries that have not been completed (TI 2515/177, Section 04.03.c.5); and

• procedure included independent verification that critical steps were completed (TI 2515/177, Section 04.03.c.6).

The inspectors verified the following with respect to surveillance and void detection:

• specified surveillance frequency was consistent with TS requirements (TI 2515/177, Section 04.03.d.1);

• surveillance frequencies were stated or, when conducted more often than required by TSs, the process for their determination was described (TI 2515/177, Section 04.03.d.2);

• surveillance method was acceptably established to achieve the needed accuracy (TI 2515/177, Section 04.03.d.3);

• surveillance procedure included up-to-date acceptance criteria (TI 2515/177, Section 04.03.d.4);

• procedure included effective follow-up actions when acceptance criteria were exceeded or when trending indicates that criteria may be approached before the next scheduled surveillance (TI 2515/177, Section 04.03.d.5);

• measured void volume uncertainty was considered when comparing test data to acceptance criteria (TI 2515/177, Section 04.03.d.6);

• venting procedures and practices utilized criteria such as adequate venting durations and observing a steady stream of water (TI 2515/177, Section 04.03.d.7);

• an effective sequencing of void removal steps was followed to ensure that gas does not move into previously filled system volumes (TI 2515/177, Section 04.03.d.8);

• qualitative void assessment methods included expectations that the void will be significantly less that allowed by acceptance criteria (TI 2515/177, Section 04.03.d.9);

• venting results were trended periodically to confirm that the systems were sufficiently full of water and that the venting frequencies were adequate.

The inspectors also verified that records on the quantity of gas at each location were maintained and trended as a means of preemptively identifying degrading gas accumulations (TI 2515/177, Section 04.03.d.10);

• surveillances were conducted at any location where a void may form, including high points, dead legs, and locations under closed valves in vertical pipes (TI 2515/177, Section 04.03.d.11);

• the licensee ensured that systems were not pre-conditioned by other procedures that may cause a system to be filled, such as by testing, prior to the void surveillance (TI 2515/177, Section 04.03.d.12); and

• procedure included gas sampling for unexpected void increases if the source of the void was unknown and sampling was needed to assist in determining the source (TI 2515/177, Section 04.03.d.13).

The inspectors verified the following with respect to void control:

• void removal methods were acceptably addressed by approved procedures (TI 2515/177, Section 04.03.f.1).

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one routine surveillance testing sample as defined in IP 71111.22, Sections 02 and 05. Additionally, this inspection effort counts towards the completion of TI 2515/177, which will be closed in a later inspection report.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on May 5, 2010, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the alternate emergency offsite facility and joint public information center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures.

The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

.1 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI for Unit 1 and Unit 2 for the first quarter 2009 through the first quarter 2010. To determine the accuracy of the PI data reported, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used.

The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC inspection reports 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 of significance 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 from the first quarter 2009 through the first quarter 2010. To determine the accuracy of the PI data reported, PI definitions and guidance contained in NEI 99-02 were used. The inspectors reviewed the licensees operator logs, RCS leakage tracking data, issue reports, event reports, and NRC inspection reports 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 to this report.

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

b. Findings

No findings of significance 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: the complete and accurate identification of the problem; that timeliness was commensurate with the safety significance; that 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 of significance 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 of significance 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, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six-month period of January through June 2010, 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 other programs, such as departmental challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

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

b. 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 Passport Work Management System to trend equipment issues. Because of the separation of trending programs, the inspectors selected three apparent equipment trends to assess trending of related issues. Trends were reviewed due to repetitive condition reports associated with source range monitors (SRMs), safety injection accumulator level indication, and an adverse interaction between DC bus operations and their potential to cause inverter transients on the opposite unit.

Condition reports associated with the SRMs showed a trend of repetitive failures.

Failures appeared to routinely occur during reactor startup and shutdowns when the instruments were placed in service for the evolution. The inspectors found that the trends had been prior identified and were evaluated in the related maintenance rule program. However, the inspectors noted that the maintenance rule criteria for this system did not assess the failure rate related to the total time the instruments were required to be in operation. The inspectors noted that the time the instruments were required to be in-service during each 18-month operating period was minimal and when the failures were evaluated related to the required operating windows the failure rate seemed high. The licensee acknowledged the inspectors observations and entered this observation into the CAP for further evaluation.

The inspectors reviewed the condition reports and failure rates associated with safety injection accumulators and found that the licensee had identified the issues. Issues were related to differences in designs between the units and obsolescence issues with instrumentation. Related system health programs and engineering feedback indicated that evaluations were being conducted to correct related issues.

URI - Unit 2 Battery Inverter Transfers to Nonsafety-Related Power During Unit 1 Testing

Introduction:

The inspectors identified an URI related to a potentially adverse trend associated with testing on one Units equipment inadvertently causing the inoperability of equipment on the opposite Unit. Through a review of related historical CAP documents, the inspectors identified a potential adverse trend associated with repeat occurrences of this issue. The inspectors are awaiting the licensees response to questions regarding this unintended cross-unit phenomenon as it pertains to the design basis of the facility.

Description:

The inspectors identified a potentially adverse trend associated with Unit 1 testing of electrical equipment that affected Unit 2s battery inverters and instrument bus.

Specifically, during the spring 2010 Unit RFO, while operators performed Unit 1 ORT 3A step 5.8.3.c, load shedding of 4160-Volt safety bus 1A-05 and 480-Volt safety bus 1B03, Unit 2s white instrument inverter 2DY-03 transferred from its safety-related power source to its nonsafety-related alternate power source, rendering the inverter inoperable.

The inspectors noted that facility design information indicated that the site was analyzed for an initiating event on one unit and that the non-affected unit would trip and be brought to a safe shutdown condition. The inspectors noted that the ORT 3A testing, which frequently produced the noted interaction between the units during recent iterations, could also occur during various accident/transient response scenarios.

Because of this cross-unit interaction, the inspectors were unsure how a transient on one unit causing an unplanned inverter loss on the opposite unit was within the design and licensing basis of the facility. The licensee was evaluating the design basis related to the observed transients at the completion of the inspection period. The transient interaction between Units 1 and 2 related to DC busses and instrument inverters was considered unresolved pending the licensees evaluation of the related design basis aspect (URI 05000266/2010003-05; 05000301/2010003-05, Unit 2 Battery Inverter Transfers to Nonsafety-Related Power During Unit 1 Testing).

.4 Selected Issue Follow-Up Inspection Associated with TI 2515/177, Managing Gas

Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems: Rollup Assessment of Recent CAPs Written as a Result of Monthly Emergency Core Cooling Systems (ECCS) Ventings and Ultrasonic Tests (UTs)

a. Inspection Scope

and Documentation During a review of items entered in the licensees CAP, the inspectors recognized a number of corrective action items documenting various issues associated with the monthly ECCS venting procedures and UTs. The inspectors ensured that each of the issues reviewed met the requirements of the licensees corrective action program.

The inspectors verified that the selected CAP entries acceptably addressed the areas of concern associated with the scope of GL 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (TI 2515/177, Section 04.01). Documents reviewed are listed in the Attachment to this report.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05. In addition, this inspection effort counts towards the completion of TI 2515/177, which will be closed in a later inspection report.

b. Findings

No findings of significance were identified.

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

.1 Unit 2 Manual Reactor Trip Due to Main Generator Lockout

a. Inspection Scope

The inspectors reviewed the plants response to a Unit 2 unplanned manual reactor trip that occurred on June 19, 2010, as a result of a main generator lockout caused by an improperly set relay. Documents reviewed are listed in the Attachment to this report.

The inspectors evaluated the forced outage aspects of the shutdown in Section 1R20 of this report.

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

b. Findings

No findings of significance were identified.

.2 (Closed) Licensee Event Report (LER) 05000266(301)/2005-006-00: Calculation Errors

in Model for ECCS Long Term Cooling On January 9, 2006, the licensee issued an LER when the inspectors identified errors in the calculations used as the basis for the licensees response to NRC Generic Letter 98-04. The two significant errors included: a correlation for the head loss across a mixed fiber and particulate debris bed on a screen was improperly applied to a debris bed consisting only of epoxy coating chips; and while interpreting the resulting calculated head loss, the licensee used the total submergence depth of the screens rather than the average submergence depth, resulting in the erroneous conclusion that the available submergence would be sufficient to ensure adequate flow to the residual heat removal pumps. The errors, deficiencies in modeling, and interpretation of results, impacted the analytical basis for demonstrating compliance with the acceptance criteria in 10 CFR 50.46(b)(5), Long-Term Cooling. This LER culminated in a Request for Additional Information from the Office of Nuclear Reactor Regulation (NRR), which, in turn, resulted in the licensee making several licensing commitments to the NRC.

The inspectors verified completion of the required commitments prior to the resolution of Generic Safety Issue (GSI)-191 for Point Beach. The inspectors also verified that the licensees remaining commitments were captured in the licensees resolution to GSI-191 through licensing commitments made as part of Generic Letter 2004-02. The inspectors reviewed all the available information, including condition reports and the past operability assessments associated with this LER, and did not identify any new concerns or performance deficiencies. Documents reviewed are listed in the Attachment to this report. This LER is closed.

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

.3 (Closed) LER 05000266(301)/2006-002-00: Fuel Assemblies in Spent Fuel Pool Do Not

Meet Technical Specification Requirements This event, which occurred on June 26, 2006, involved the failure to meet TS 4.3 requirements for the discovery of 12 spent fuel assemblies stored in the spent fuel pool that had an initial enrichment of 4.70 weight percent but contained no integral fuel burnable absorber rods. In April 2010, the licensee received a license amendment that revised fuel pool storage limits and now allowed this configuration. Because an amendment was received authorizing operation with this configuration, the prior non-compliance with TS is considered minor. Documents reviewed are listed in the to this report. This LER is closed.

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

4OA5 Other Activities

.1 (Closed) URI 05000266(301)/2009005-04: Potential Failure to Evaluate Seismic II/I

Concerns for Units 1 and 2 B Containment Sump Strainers

a. Inspection Scope

The NRC documented an URI during the fourth quarter of 2009 (ML100410106)involving the Seismic II/I evaluations of the B containment sump strainers for Units 1 and 2. Specifically, on October 27, 2009, the inspectors performed a walkdown of the containment sump strainers during the Unit 2 refueling outage and noted a ventilation duct located above the B containment sump strainer. The inspectors were concerned that during a seismic event the structure could collapse, affecting the containment sump strainer ability to fulfill its accident mitigating function. Specifically, if the ventilation work collapsed, it could compromise the structural integrity of the sump strainer or represent a source of debris blockage. The licensees immediate search for documentation on the seismic evaluation of the ventilation duct was unsuccessful. Subsequently, the licensee concluded that:

(1) the ventilation ducts were seismically evaluated by a SQUG walkdown performed prior to the installation of the strainers;

(2) the walkdown determined that there were no Seismic II/I concerns; and

(3) that the walkdown was not properly documented. The same conclusions applied to Unit 1. However, the inspectors questioned if:

(1) the SQUG methodology could be applied to ventilation ducts;

(2) the NRC approved the use of the SQUG methodology for all new modifications as opposed to replacement of previously SQUG verified equipment with similar equipment; and

(3) if the level of detail typically documented by the licensee permitted an independent verification of the work performed. The inspectors identified this issue as an URI pending further NRC review of the licensing basis for the use of SQUG methodology and determination of the NRC course of action for resolution of the issues (URI 05000266(301)/2009005-04(DRS)).

During this inspection, the inspectors reviewed corrective action program documents and licensing basis documents. In addition, the inspectors discussed the issues with NRR.

This review did not represent an inspection sample. The documents reviewed are included in the Attachment to this report. This URI is closed.

b. Findings

Procedures Not Appropriate to Verify and Document the Design of New or Modified SSCs with Respect to Seismic II/I Interactions

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure to provide procedures that were appropriate to:

(1) verify the design of new or modified SSCs with respect to Seismic II/I interactions; and

(2) document this design verification activity.

Description:

The inspectors discussed the concerns with the NRR and reviewed applicable licensing basis documents and procedures. It was determined that:

• The SQUG methodology could not be used for the verification of seismic adequacy of ventilation ducts. Specifically, Section A5.6 of the FSAR, Seismic Design and Verification of Modified, New, or Replacement Equipment, stated that the scope of equipment to which the SQUG methodology could be applied included certain classes of active mechanical and electrical equipment as specified in generic implementation procedure (GIP)-2, electrical relays, cable trays and conduit, heat exchangers, and modification of existing tanks.

This limitation was also explicitly stated in GIP-2, Part I, Section 2.3.3, Revision of Plant Licensing Basis. Specifically, GIP-2 stated that, for A-46 plants, the SQUG methodology could be used to verify the seismic adequacy of equipment within the scope of GIP-2, Part II. The GIP-2, Part II, Section 3.3, Scope of Equipment, listed the equipment, which was included within the scope of review for resolution of Unresolved Safety Issue (USI) A-46.

Ventilation ducts and strainers were not part of the SQUG equipment classes specified in the FSAR or GIP-2.

• The SQUG methodology could be used for all new modifications involving equipment that is within the scope of GIP-2. Specifically, Supplemental Safety Evaluation Report No. 2 (SSER 2), dated May 22, 1992, stated that the NRC staff agreed that it was impractical and inconsistent with the USI A-46 philosophy to require that new equipment meet current seismic qualification requirements, whereas the seismic adequacy of all other safe shutdown equipment was verified through the USI A-46 procedures. Therefore, the staff concluded that the SQUG criteria and procedures was an acceptable evaluation method for verifying the seismic adequacy of new equipment in USI A-46 plants.

• The documentation of seismic verification activities, including, but not limited to, SQUG-related activities, must provide sufficient detail to allow for an independent verification of the work performed. Specifically,Section II.9 of the SSER 2, Documentation, stated that, although GIP-2 recommended documentation of only the results from several evaluations and not the assumptions and judgments used for the respective evaluations, the NRC staff recommended documentation of the assumptions and the judgments to facilitate the reconstruction of relevant basis for the licensees evaluations. In addition, GIP-2, Part I, Section 2.3.5, Quality Assurance and Quality Control, stated that if the USI A-46 criteria were used to verify the seismic adequacy of any new or replacement equipment or parts, the modifications or verifications of seismic adequacy shall be performed in accordance with the licensees Quality Assurance (QA) program. The licensees Quality Assurance Topical Report, FPL-1, Section B.2, Design Control, stated that the QA program included provisions to assure that design inputs were correctly translated into design outputs such that the final design output could be related to the design input in sufficient detail to permit verification. Further, it stated that the licensee maintained records sufficient to provide evidence that the design was properly accomplished.

As a result, the licensee performed ACE 01163219, which determined that there was a misunderstanding of the provisions for the use of the SQUG methodology in applications other than the resolution of USI A-46. Specifically, the ACE concluded that the lack of documentation for the Seismic II/I interaction evaluation for the containment sump strainers modification was due to the use of an exceptions documentation method used by the USI A-46 resolution as opposed to the complete documentation of all potential SSC interactions consistent with the plants QA program. The licensee determined that the misunderstanding originated because GIP-2 stated that the USI A-46 response program was outside the scope of commitments made in the plants FSAR and TSs because GIP-2 itself provided steps to ensure the quality of SQUG-related activities.

The methodology employed by GIP-2 allowed documentation of II/I issues by exception instead of inclusion of all observed components. However, the ACE also determined that the USI A-46 resolution involved a review process and not a process to install new plant equipment. Because the licensee had not recognized this, no formal documentation requirements were incorporated in modification and seismic procedures after the USI A-46 program was completed.

Additionally, as a result of the inspectors questions, the licensee determined that it lacked procedural guidance to perform seismic II/I evaluations when the method of seismic qualification/verification was other than SQUG. Procedure NP 7.7.2, Seismic Qualification of Equipment, provided direction and control of activities involving seismic qualification of equipment. Procedure Step 4.2.4 stated that Step 4.2.1.c provided guidance for the seismic interaction verification of passive equipment (e.g., ventilation ducts). Step 4.2.1.c referred to GIP-2 (i.e., SQUG methodology) for detailed guidance. However, this procedure neither advised on the limitations of the GIP-2 nor offered alternate seismic verification methodologies when the SQUG methodology could not be applied.

The licensees ACE concluded that if the USI A-46 criteria were used to verify the seismic adequacy of new or replacement equipment or parts, the verification must be done in accordance with the requirements of the plants QA program as described by FPL-1. FPL-1 was developed to implement the requirements of 10 CFR Part 50, Appendix B. Therefore, the implementing documents (e.g., procedures) for processes that were defined in FPL-1, such as design control, must meet the requirements described by the plants QA program.

As a result of the inspectors concerns, the licensee performed EC 14790 and concluded that the Unit 1 B sump strainer was operable. This EC performed a structural analysis that concluded that the ventilation duct support structure would be able to support loads induced by a seismic event. The inspectors had no further comments regarding this new evaluation.

The licensee captured the issues in their corrective action program as AR 0116319 and AR 01160941. The licensees corrective actions include briefing plant personnel on the correct application of documentation requirements, reviewing open modification for compliance with the correct interpretation of GIP-2, developing a plan and schedule for identifying and reconciling potential documentation issues associated with post-USI A-46 SQUG evaluations, and revising modification and seismic procedures.

Analysis:

The inspectors determined that the failure to provide procedures that were appropriate to verify the design of new or modified SSCs with respect to Seismic II/I interactions and document this design verification activity was contrary to the licensees QA program requirements and was a performance deficiency.

Using IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated December 24, 2009, the inspectors determined that the performance deficiency more than minor because it was associated with the Mitigating Systems Cornerstone attribute of protection against external events and adversely affected the cornerstone objective of ensuring the capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not perform an evaluation that was in accordance with their licensing basis to verify the design of the B containment sump strainers of Units 1 and 2 with respect to potential seismic II/I interactions due to a lack of procedural guidance.

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 3b, dated January 10, 2008, for the Mitigating Systems Cornerstone. The finding screened as of very low safety significance (Green) because the finding was a qualification deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee performed an engineering evaluation, which concluded that the ventilation duct support structure would be able to withstand seismically-induced loads. The inspectors did not have further concerns.

The inspectors determined that the finding had a cross-cutting aspect in the area of problem identification and resolution because the licensee did not conduct self-assessments of the SQUG program. Specifically, because the licensee viewed SQUG as an implementing methodology as opposed to a program, it did not assess its performance (P.3(a)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances.

Contrary to this, from the implementation of the SQUG program in 1995 to the time of this inspection, the licensee did not have procedures that were appropriate to the circumstances as evidenced by the following examples:

(1) the procedures used for seismic II/I interaction evaluations of new or modified SSCs did not provide guidance for evaluating equipment that was not represented in the earthquake experience or generic testing equipment classes included in GIP-2; and

(2) no formal guidance was incorporated in modification and seismic procedures on the documentation necessary for seismic II/I interaction evaluations. Because this violation was of very low safety significance and was entered into the licensees corrective action program, as AR 01163219 and AR 01160941, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000266/2010003-06; 05000301/2010003-06, Procedures Were Not Appropriate to Adequately Verify and Document the Design of New or Modified SSCs With Respect to Seismic II/I Interactions).

.2 (Closed) URI 05000266/2010002-04; 05000301/2010002-04; Potential Failure to

Adequately Assess Risk During Condensate Storage Tank (CST) Modifications The NRC documented an URI during the first quarter of 2010 (ML101310428) due to the licensee using a temporary CST system that was installed as an alternate water supply for the permanent CST to accommodate several plant modifications for several issues including coating refurbishment, license renewal inspection, and installation of new motor-driven auxiliary feedwater system mechanical piping connections. During this evolution, the licensee credited the out-of-service CST as available from a risk perspective through the use of the temporary CST modification. The inspectors reviewed the risk management aspects of this issue and found that for the maintenance activities on the permanent CST, procedures did not exist to support this risk mitigation activity. Additionally, the design of the system did not appear to meet the established guidance for risk mitigation.

The inspectors reviewed the licensees modeling of the out-of-service CST as available from a risk perspective through the use of the temporary CST modification. The licensee performed a condition evaluation (CAP 01170616) to address the inspector's questions.

The inspectors reviewed the evaluation and found the modeling of the out-of-service CST as available to be acceptable. This URI is closed. Documents reviewed are listed in the Attachment to this report.

4OA6 Management Meetings

.1 Exit Meeting Summary

On July 1, 2010, the inspectors presented the inspection results to Mr. L. Meyer and other members of the licensee staff. The licensee acknowledged the issues presented.

.2 Interim Exit Meetings

Interim exits were conducted for:

• On April 14, 2010, the inspectors presented the inspection results of the actions taken to close open inspection items related to the licensees response to GL 2004-02, to Ms. F. Flentje. The licensee acknowledged the issues presented.

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

L. Meyer, Site Vice President

F. Flentje, Regulatory Assurance

Nuclear Regulatory Commission

M. Kunowski, Chief, Division of Reactor Projects, Branch 5

LIST OF ITEMS

Opened

05000266/2010003-01; NCV Failure to Enter Abnormal Operating Procedure During

05000301/2010003-01 Tornado Warning (1R01)

05000266/2010003-02; NCV Failure to Control the Design of Partially Installed

05000301/2010003-02 Modifications for Seismic Requirements (1R04)

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

05000301/2010003-03 Equipment Operability with Hazard Barriers Out-Of-Service (1R15)

05000266/2010003-04; URI Potential Degradation of Reactor Protection System P-9

05000301/2010003-04 Permissive Operability (1R20)

05000266/2010003-05; URI Unit 2 Battery Inverter Transfers to Nonsafety-Related

05000301/2010003-05 Power During Unit 1 Testing (4OA2)

05000266/2010003-06; NCV Procedures Were Not Appropriate to Adequately Verify

05000301/2010003-06 and Document the Design of New or Modified SSCs With Respect to Seismic II/I Interactions (4OA5)

Closed

05000266/2005-006-00 LER Calculation Errors in Model for ECCS Long Term

05000301/2005-006-00 Cooling (Section 4OA3.2)

05000266/2006-002-00 LER Fuel Assemblies in Spent Fuel Pool Do Not Meet

05000301/2006-002-00 Technical Specification Requirements (4OA3.3)

05000266/2009005-04; URI Potential Failure to Adequately Evaluate Seismic II/I

05000301/2009005-04 Concerns for Units 1 and 2 B Containment Sump Strainers (4OA5)

05000266/2010002-04; URI Potential Failure to Adequately Assess Risk During

05000301/2010002-04 CST Modifications (4OA5)

05000266/2010003-01; NCV Failure to Enter Abnormal Operating Procedure During

05000301/2010003-01 Tornado Warning (1R01)

05000266/2010003-02; NCV Failure to Control the Design of Partially Installed

05000301/2010003-02 Modifications for Seismic Requirements (1R04)

Attachment

Closed

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

05000301/2010003-03 Equipment Operability with Hazard Barriers Out-Of-Service (1R15)

05000266/2010003-06; NCV Procedures Were Not Appropriate to Adequately Verify

05000301/2010003-06 and Document the Design of New or Modified SSCs With Respect to Seismic II/I Interactions (4OA5)

Discussed

None Attachment