IR 05000282/2009005

IR 05000282-09-005, 05000306-09-005; 10/1/2009-12/31/2009; Prairie Island Nuclear Generating Plant, Units 1 & 2; Access Control to Radiologically Significant Areas; Radioactive Gaseous & Liquid Effluent Treatment and Monitoring Systems; Eve

ML100390013
Person / Time
Site:	Prairie Island
Issue date:	02/08/2010
From:	Jack Giessner Reactor Projects Region 3 Branch 4
To:	Schimmel M Northern States Power Co
References
3-2009-025 IR-09-005
Download: ML100390013 (53)

Text

uary 8, 2010

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000282/2009005; 05000306/2009005 AND OFFICE OF INVESTIGATIONS REPORT NO. 3-2009-025

Dear Mr. Schimmel:

On December 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the inspection findings, which were discussed on January 6, 2010, with you and other members of your staff. This also refers to the investigation completed by the NRC Office of Investigations on November 24, 2009.

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

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

Based on the results of this inspection, three NRC-identified and two self-revealed findings of very low safety significance were identified. Four of these 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. The NRC has also determined through information developed during previous inspections and a subsequent investigation, that the failure to provide accurate information in a 2008 Licensee Event Report was not willful. Notwithstanding this conclusion, the NRC has determined that a Severity Level IV violation of NRC requirements occurred. This violation is also being treated as an NCV, consistent with Section VI.A of the Enforcement Policy. Additionally, two licensee-identified violations are discussed in Section 4OA7 of this report.

If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S.

Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant. In addition, if you disagree with the characterization of 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 Prairie Island Nuclear Generating Plant. The information that you provide will be considered in accordance with Inspection Manual Chapter 0305.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

John B. Giessner, Chief Projects Branch 4 Division of Reactor Projects Docket Nos. 50-282; 50-306;72-010 License Nos. DPR-42; DPR-60; SNM-2506

Enclosure:

Inspection Report 05000282/2009005; 05000306/2009005 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report No: 05000282/2009005; 05000306/2009005 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: October 1 through December 31, 2009 Inspectors: K. Stoedter, Senior Resident Inspector P. Zurawski, Resident Inspector D. Betancourt, Reactor Engineer L. Haeg, Resident Inspector - Monticello R. Jickling, Senior Emergency Preparedness Inspector G. ODwyer, Reactor Inspector M. Phalen, Health Physics Inspector C. Tilton, Senior Engineering Inspector F. Tran, Reactor Engineer Approved by: J. Giessner, Chief Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000282/2009005, 05000306/2009005; 10/1/2009 - 12/31/2009; Prairie Island Nuclear

Generating Plant, Units 1 and 2; Access Control to Radiologically Significant Areas; Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems; Event Followup.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Severity Level IV Non-Cited Violation (NCV)and five Green findings associated with four NCVs were identified by the inspectors. 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 self-revealed finding of very low safety significance was identified on May 18, 2009, due to the licensees failure to replace an electrical cable associated with the 12 circulating water pump after identifying that the cable was susceptible to failure.

Consequently, the electrical cable failed and the sequence of events that followed resulted in a Unit 1 automatic reactor trip. Corrective actions for this issue included replacing the electrical cabling for the 12 circulating water pump and scheduling the cable replacements for other susceptible components. No violation of NRC requirements occurred.

This finding was determined to be more than minor because it was associated with the protection against external factors and the equipment performance attributes of the Initiating Events cornerstone. In addition, the finding impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as at power operations. The inspectors determined that this finding was of very low safety significance because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment would not be available. The inspectors concluded that this issue was cross-cutting in the Human Performance, Decision Making area, because the licensee failed to use conservative assumptions during their decisions regarding the need for cable replacements even after receiving numerous pieces of operating experience information (H.1.(b)). (Section 4OA3.2)

Cornerstone: Mitigating Systems

• Severity Level IV A NRC-identified issue and a NCV of 10 CFR 50.9 was identified when the inspectors discovered that Licensee Event Report (LER)05000306/2008-001-00 was not complete and accurate in all material aspects.

Specifically, the LER omitted information regarding when and how the licensee became aware that the Unit 2 component cooling water system was susceptible to failure following a postulated high energy line break in the turbine building. The omitted information was considered to be material to the NRC because it potentially affected the

NRC's determination as to whether this issue would be characterized as an old design issue per Inspection Manual Chapter 0305. Subsequent to discovery of the deficiency, the licensee submitted Revision 1 to LER 05000306/2008-001-00, on January 19, 2009, which documented the originally omitted information.

This issue was determined to be more than minor because it affected the NRCs ability to perform its regulatory function. As a result, this finding was evaluated with the traditional enforcement process. Using the information provided in IMC 0612,

Appendix B, Issue Screening, this issue was determined to be a Severity Level IV NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. This finding was determined to be cross-cutting in the Human Performance, Work Control area, because the licensee failed to properly plan and coordinate work activities to address the impact of work on different job activities and the need for groups to communicate, coordinate, and cooperate with others during work activities (H.3(b)). (Section 4OA3.1)

• Green The inspectors identified a finding of very low safety significance and an NCV of 10 CFR Part 50 Appendix B, Criterion V, due to the licensees failure to accomplish an activity affecting quality in accordance with procedures. Specifically, licensee personnel failed to identify repeated blocking of the diesel-driven cooling water pumps right angle drive gear oil coolers with debris as an adverse trend even though blockages had been identified four times between July 2005 and August 2009. As a result, the adverse trend was not characterized as a significant condition adverse to quality as required by Procedure FP-PA-ARP-01, Corrective Action Program Action Request Process. The failure to identify this issue as an adverse trend and a significant condition adverse to quality resulted in the untimely implementation of corrective actions to prevent recurrence and contributed to the August 27, 2009, inoperability of the 12 diesel-driven cooling water pumps. Corrective actions for this issue included the continued installation of ultrasonic flow meters to monitor flow to the right angle drive gear oil coolers and the implementation of a modification to strain the cooling water flow to the right angle drive gear oil coolers prior to performing the next zebra mussel treatment.

The finding was more than minor because the failure to properly implement the corrective action procedure impacted the equipment performance attribute of the Mitigating Systems cornerstone and the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance because it did not involve a loss of safety function of a single train for greater than technical specification allowed outage time, did not involve a loss of system safety function and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors concluded that this finding was cross-cutting in the Human Performance, Decision Making area because the licensee failed to appropriately use systematic processes (i.e., the corrective action, engineering change, and the preventive maintenance processes) when making safety-significant decisions regarding the repeated blockage of the right angle drive gear oil coolers (H.1(a)). (Section 4OA3.3)

Cornerstone: Occupational Radiation Safety

• Green A self-revealed finding of very low safety-significance and an NCV of Technical Specification 5.4.1 was identified for the failure to implement written procedures in the area of radiation protection. Specifically, the licensee failed to meet radiation work permit requirements during a valve breach. As a result, a valve technician became internally and externally contaminated. Corrective actions for this issue included performance management of the personnel involved.

This finding was more than minor because it was associated with the program and process attribute of the Occupational Radiation Safety cornerstone. In addition, the finding impacted the cornerstone objective of protecting worker health and safety from exposure to radiation. The inspectors determined that the finding was of very low safety significance, because the finding did not involve As-Low-As-Is-Reasonably Achievable planning or work controls, there was no overexposure or substantial potential for an overexposure, nor was the licensee's ability to assess worker dose compromised. The inspectors concluded that this finding was cross-cutting in the Human Performance,

Work Practices area because personnel failed to follow procedures during the valve breach (H.4(b)). (Section 2OS1.1)

Cornerstone: Public Radiation Safety

• Green An inspector-identified finding of very low safety-significance and an NCV of 10 CFR Part 20.1501 was identified for the failure to evaluate the potential radiological environmental dose impact associated with the extended non-functionality of the radioactive waste building ventilation system and its radiation detector. As a result, compensatory measures were not established to compensate for the non-functional equipment. Corrective actions for this issue included instituting compensatory radiological sampling and increasing the priority of the radwaste building ventilation system repairs.

This finding was more than minor because it was associated with the program and process attribute of the Public Radiation Safety cornerstone. In addition, this finding impacted the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. The inspectors determined that the finding was of very low safety significance because it did not involve radioactive material control, there was not a substantial failure to implement the radiological effluent program, and public dose was less than Appendix I criteria and 10 CFR 20.1301. The inspectors concluded that this finding was cross-cutting in the Problem Identification and Resolution, Corrective Action area, because although this long-standing equipment issue had been documented in the licensees corrective action program, the issue had not been fully evaluated nor had actions been taken to address the equipment deficiency in a timely manner (P.1(c)). (Section 2PS1.2)

Licensee-Identified Violations

Violations of very low safety significance that were identified by the licensee have been reviewed by inspectors. Corrective actions planned or taken by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period shutdown for Refueling Outage 1R26. Operations personnel returned Unit 1 to power on November 22, 2009. The generator was synchronized with the electrical grid on November 23, 2009. Unit 1 was returned to full power on November 30, 2009.

Unit 1 operated at this power level for the remainder of the inspection period.

Unit 2 operated at or near full power levels until November 20, 2009, when power was lowered to 95 percent to allow maintenance on the 1B moisture separator reheater. Unit 2 was restored to full power levels on November 22, 2009. Unit 2 continued to operate at full power until December 18 when operations personnel lowered reactor power 47 percent to conduct periodic turbine valve testing. Operations personnel restored Unit 2 to full power levels the next day.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

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

• Deicing Pumps, and

• Screenhouse Ventilation System.

This inspection constituted one winter seasonal readiness preparation sample as defined in Inspection Procedure (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 a partial system walkdown of the following risk-significant system:

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

.

This activity constituted one partial system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings of significance were identified.

.2 Semiannual Complete System Walkdown

a. Inspection Scope

During December 2009, the inspectors performed a complete system alignment inspection of the Unit 1 and Unit 2 safety-related batteries 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 configuration, electric power availability, temperature indications, component labeling, component lubrication, equipment cooling, supports, operability of support systems, electrolyte levels, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.

Documents reviewed are listed in the Attachment.

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

b. Findings

No findings 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 Areas 31 and 32 - Unit 1 and Unit 2 Auxiliary Feedwater Pump Rooms;

• Fire Area 18 - Relay Room;

• Fire Area 16 - Train B Event Monitoring Equipment Room;

• Fire Area 17 - Unit 2 Rod Drive Room; and

• Fire Area 20 - Bus 16 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 licensees 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 licensees ability to respond to a security event.

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

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

b. Findings

No findings of significance were identified.

1R06 Flooding

.1 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors verified if cables were submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions. See Section 4OA3 of this report for additional information regarding cables that were degraded due to the presence of moisture. The inspectors also reviewed the CAP database with respect to past submerged cable issues to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground bunkers/manholes subject to water intrusion:

• 12 circulating water pump underground cable conduit, and

• manhole near thermal walkway containing 13.8 kilovolt (kV) cables.

This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On November 23, 2009, the inspectors observed a crew of licensed operators in the 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 system:

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

• implementing appropriate work practices;

• identifying and addressing common cause failures;

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

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

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

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

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

This inspection constituted one quarterly maintenance effectiveness sample 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 item listed below to verify that the appropriate risk assessment was performed prior to changing reactor operating modes or removing equipment from service for maintenance:

• Unit 1 Mode Change with the 12 Component Cooling Water Train Inoperable This activity was selected based on its potential risk significance relative to the Reactor Safety Cornerstones. The inspectors verified that the risk assessment was performed as required by 10 CFR 50.65(a)(4) and the TS. In addition, the inspectors validated that the risk assessment was accurate and complete. 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.

This maintenance risk assessment and emergent work control activity constituted one sample 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:

• Operability Review (OPR) 1203628-01, Revision 1 - Effects of Gas Void Found in Residual Heat Removal Piping at Location 1SI-23;

• OPR 1203173-01, Revision 0 - Auxiliary Feedwater Pump Room Heat Up Concerns Post High Energy Line Break;

• OPR 1178236-04; Revision 2 - Internal Flooding Impacts in Turbine Building;

• OPR 1203777-01, Revision 1 - Effects of Multiple Gas Voids Found in Caustic Addition and Containment Spray Systems;

• OPR 1206060-01, Revision 0 - Effects of Concurrent High Energy Line Break, Loss of Offsite Power, and a Single Failure;

• OPR 1162055-01, Revision 0 - Non-conservatism Discovered in Evaluation of Previously Identified Void;

• OPR 1202820-01, Revision 0 - Impacts on D1 and D2 Combustion Air Supply Following a High Energy Line Break;

• OPR 1206719-01, Revision 0 - Manufacturing Defect on D5 and D6 Bearings; and

• Engineering Change 14901, Revision 0 - Sump B Past Operability Evaluation Due to Latent Debris in Excess of Program Limitations.

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 TSs and the USAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also 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 nine samples as defined in IP 71111.15-05.

b. Findings

No findings of significance were identified. See Section 4OA5 of this report regarding information associated with the inspectors review of OPR 1178236-04, Revision 2, Internal Flooding Impacts in Turbine Building.

.2 Operability Evaluations Associated with Temporary Instruction 2515/177, Managing

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

a. Inspection Scope

and Documentation The inspectors reviewed the following issues associated with the scope of Generic Letter (GL) 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems:

• OPR 1203628-01, Revision 1 - Effects of Gas Void Found in Residual Heat Removal Piping at Location 1SI-23;

• OPR 1203777-01, Revision 1 - Effects of Multiple Gas Voids Found in Caustic Addition and Containment Spray Systems; and

• OPR 1162055-01, Revision 0 - Non-Conservatism Discovered in Evaluation of Previously Identified Void.

The inspectors verified that the licensee had acceptably identified the gas intrusion mechanisms that applied to the plant. If the licensees evaluation was incomplete, the inspectors verified that corrective actions were placed into the CAP (Temporary Instruction (TI) 2515/177, Section 04.02.e). In addition, the inspectors verified that the licensees void acceptance criteria were consistent with the Office of Nuclear Reactor Regulations (NRR) void acceptance criteria. If NRRs acceptance criteria were not met, then the inspectors verified that the licensee has justified the deviations. Also, the inspectors confirmed that

(1) the licensee addressed the effect of pressure changes during system startup and operation since such changes could significantly affect the void fraction from the initial value; and

(2) the range of flow conditions evaluated by the licensee was consistent with the full range of design basis and expected flow rates for various break sizes and locations (TI 2515/177, Section 04.02.f).

Documents reviewed are listed in the Attachment to this report.

This inspection effort counts towards the completion of TI 2515/177 which will be closed in a later inspection report (IR).

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

.1 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification:

• Engineering Change 15102 - Temporary Flood Control Barrier for D1 and D2 Emergency Diesel Generator Rooms.

The inspectors compared the temporary configuration change and associated 10 CFR 50.59 screening against the design basis, the USAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system. 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 performed field verifications to ensure that the modification was installed as directed; the modification adequately supported the continued operability of the D1 and D2 emergency diesel generators; and that the modification did not impact the operability of any interfacing systems. Documents reviewed in the course of this inspection are listed in the Attachment to this report.

This inspection constituted one temporary modification sample 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 activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• D2 Diesel Generator Post-Maintenance Testing;

• 12 Component Cooling Water Pump Return Check Valve Testing following check valve replacement;

• Unit 1 Reactor Coolant System Integrity Test following refueling outage activities;

• Safety Injection and Loss of Offsite Power Actuation Circuitry Restoration Testing;

• 11 Turbine-Driven Auxiliary Feedwater Pump Post-Maintenance Testing; and

• Unit 2 Boric Acid Flow Integrator Post-Maintenance Testing.

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

This inspection constituted six 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 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 outage safety plan for key safety functions and compliance with the applicable TS when taking equipment out of service;

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

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

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

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

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

• Controls over activities that could affect reactivity;

• Maintenance of secondary containment as required by TSs;

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

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

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

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• 21 Containment Spray Pump Quarterly Test (routine);

• Bus 26 Undervoltage Relay Test (routine);

• 11 Turbine-Driven Auxiliary Feedwater Pump Test (routine);

• Reactor Coolant System Integrity Test (reactor coolant system leakage); and

• D1 Diesel Generator Monthly Slow Start Test (inservice test).

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

• did preconditioning occur;

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

• were acceptance criteria clearly stated 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 USAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

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

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures;

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

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

• test equipment was removed after testing;

• where applicable for inservice testing 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, one inservice testing sample, and one reactor coolant system leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

.1 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

Since the last NRC inspection of this program area, emergency action level and Emergency Plan changes were implemented based on your determination, in accordance with 10 CFR 50.54(q), that the changes resulted in no decrease in effectiveness of the Plan, and that the revised Plan as changed continues to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. Revisions to the emergency action levels and Emergency Plan reviewed by the inspectors included:

• EPIP F3-2.1, Revisions 3 and 4; and

• Emergency Plan, Revisions 3 and 4.

The inspectors conducted a sampling review of the Emergency Plan changes and a review of the Emergency Action Level changes to evaluate for potential decreases in effectiveness of the Plan. However, this review does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety.

This emergency action level and emergency plan changes inspection constituted one sample as defined in IP 71114.04-05.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed licensee controls and surveys in the following radiologically significant work areas within radiation areas, high radiation areas, and airborne radioactivity areas in the plant to determine if radiological controls including surveys, postings, and barricades were acceptable:

• Unit 1 Containment B Sump and

• Unit 1 Containment C Sump (In-core Shaft).

This inspection supplemented inspections in IR 05000282/2009003; 05000306/2009003 and constituted one sample as defined in IP 71121.01-5.

The inspectors reviewed the radiation work permits (RWPs) and work packages used to access these areas and other high radiation work areas. The inspectors assessed the work control instructions and control barriers specified by the licensee. Electronic dosimeter alarm setpoints for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. The inspectors interviewed workers to verify that they were aware of the actions required if their electronic dosimeters noticeably malfunctioned or alarmed.

This inspection supplemented inspections in IR 05000282/2009003; 05000306/2009003 and constituted one sample as defined in IP 71121.01-5.

The inspectors walked down and surveyed (using an NRC survey meter) these areas to verify that the prescribed RWP, procedure, and engineering controls were in place; that licensee surveys and postings were complete and accurate; and that air samplers were properly located.

This inspection supplemented inspections in IR 05000282/2009003; 05000306/2009003 and constituted one sample as defined in IP 71121.01-5.

The inspectors reviewed RWPs for airborne radioactivity areas to verify barrier integrity and engineering controls performance (e.g., high-efficiency particulate air ventilation system operation) and to determine if there was a potential for individual worker internal exposure in excess of 50 millirem committed effective dose equivalent. There were no airborne radioactivity work areas during the inspection period.

Work areas having a history of, or the potential for, airborne transuranics were evaluated to verify that the licensee had considered the potential for transuranic isotopes and had provided appropriate worker protection.

This inspection constituted one sample as defined in IP 71121.01-5.

b. Findings

Introduction:

A self-revealed finding of very low safety-significance and an NCV of TS 5.4.1 was identified for the failure to meet RWP requirements during a valve breach.

As a result, a valve technician became internally and externally contaminated.

Description:

On September 29, 2009, a valve technician (VT) arrived at the radiologically controlled area access control point for a briefing with the radiation protection staff. A radiological control briefing occurred between the VT and a radiation protection technician (RPT); however, the briefing was ineffective in that the VT left the briefing believing that he was authorized to breach the RH-2-1 valve in the residual heat removal (RHR) valve pit. The RPT understood the scope of work to be preparation activities for the actual valve breach. The RWP that established the radiological controls for this work stated that continuous radiation protection (RP) coverage was required during system breaches. When the VT arrived at the job site, he proceeded to breach the RHR system by disassembling valve RH-2-1. During the course of these activities the VT became internally and externally contaminated and inadvertently spread radiological contamination in the RHR valve pit. The workers dose from the internal contamination was calculated to be 1 millirem committed effective dose equivalent.

Analysis:

The inspectors determined that the inappropriate breach of the RH-2-1 valve that resulted in the inadvertent internal and external contamination of the VT and the spread of contamination in the RHR valve pit was a performance deficiency.

Specifically, the licensee failed to meet the requirements of the applicable RWP. This activity was within the licensees ability to foresee and should have been prevented, in that, if a successful briefing had occurred between the RP staff and the VT prior to the worker entering the area the issue could have been prevented.

The inspectors determined that this finding was more than minor, because it was associated with the program and process for procedures attribute of the Occupational Radiation Safety cornerstone. In addition, the finding impacted the cornerstone objective of protecting worker health and safety from exposure to radiation, in that, if left uncorrected additional unplanned or more significant radiological exposures could occur.

The inspectors determined that this finding was of very low safety significance in accordance with IMC 0609, Appendix C, AOccupational Radiation Safety SDP,@ because the finding did not involve As-Low-As-Is-Reasonably-Achievable (ALARA) planning or work controls, there was no overexposure or substantial potential for an overexposure, nor was the licensee's ability to assess worker dose compromised. The inspectors concluded that the primary cause of this finding was related to the Human Performance, Work Practices area because personnel failed to follow procedures (i.e., the RWP)

(H.4(b)).

Enforcement:

Technical Specification 5.4.1 requires that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Revision 2, Appendix A, Section 7 requires procedures for the control of radioactivity, including limiting personnel exposure. Radiation Protection Implementing Procedure (RPIP) 1135 RWP Coverage, Step 8.4 requires that RP perform job coverage requirements consistent with the RWP. Radiation Work Permit 956 stated that continuous RP coverage was required during system breaches.

Contrary to the above, on September 29, 2009, a VT failed to implement RPIP 1135 consistent with RWP 956. As a result, the VT breached valve RH-2-1 without RP presence at the job site. Because this violation was of very low safety significance, and it was entered into the licensees CAP as CAP 1200237, this violation is being treated as an NCV consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2009005-01; 05000306/2009005-01). Corrective actions for this issue included coaching the individuals involved in accordance with station management protocol for performance management.

.2 Job-In-Progress Reviews

a. Inspection Scope

The inspectors observed the following two jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers: Unit 1 Containment B Sump Coatings and access controls for Sump C. The inspectors reviewed radiological job requirements for these activities, including RWP requirements and work procedure requirements.

This inspection supplemented inspections in IR 05000282/2009003; 05000306/2009003 and constituted one sample as defined in IP 71121.01-5.

Job performance was observed with respect to the radiological control requirements to assess whether radiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors evaluated the adequacy of radiological controls, including required radiation, contamination, and airborne surveys for system breaches; radiation protection job coverage, including any applicable audio and visual surveillance for remote job coverage; and contamination controls.

This inspection supplemented inspections in IR 05000282/2009003; 05000306/2009003 and constituted one sample as defined in IP 71121.01-5.

The inspectors reviewed radiological work in high radiation work areas having significant dose rate gradients to evaluate whether the licensee adequately monitored exposure to personnel and to assess the adequacy of licensee controls. These work areas involved areas where the dose rate gradients were severe, thereby increasing the necessity of providing multiple dosimeters or enhanced job controls.

This inspection supplemented inspections in IR 05000282/2009003; 05000306/2009003 and constituted one sample as defined in IP 71121.01-5.

b. Findings

No findings of significance were identified.

.3 Radiation Worker Performance

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation safety work requirements. The inspectors evaluated whether workers were aware of any significant radiological conditions in their workplace, of the RWP controls and limits in place, and of the level of radiological hazards present. The inspectors also observed worker performance to determine if workers accounted for these radiological hazards.

This inspection supplemented inspections in IR 05000282/2009003; 05000306/2009003 and constituted one sample as defined in IP 71121.01-5.

b. Findings

No findings of significance were identified.

.4 Radiation Protection Technician Proficiency

a. Inspection Scope

During job performance observations, the inspectors evaluated RPT performance with respect to radiation safety work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace, the RWP controls and limits in place, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

This inspection supplemented inspections in IR 05000282/2009003; 05000306/2009003 and constituted one sample as defined in IP 71121.01-5.

b. Findings

No findings of significance were identified.

2OS2 As-Low-As-Is-Reasonably-Achievable Planning and Controls (71121.02)

.1 Verification of Dose Estimates and Exposure Tracking Systems

a. Inspection Scope

The inspectors reviewed the assumptions and bases for the current annual collective exposure estimate, including the applicable procedures, in order to evaluate the licensees method for estimating work activity-specific exposures and the intended dose outcome. Dose rate and man-hour estimates were evaluated for reasonable accuracy.

This inspection constituted one required sample as defined in IP 71121.02-5.

The licensees process for adjusting exposure estimates or re-planning work (when unexpected changes in scope, emergent work or higher than anticipated radiation levels were encountered) was evaluated. This included determining whether adjustments to estimated exposure (intended dose) were based on sound radiation protection and ALARA principles or whether they resulted from failures to adequately plan or to control the work. The frequency of these adjustments was reviewed to evaluate the adequacy of the original ALARA planning process.

This inspection constituted one required sample as defined in IP 71121.02-5.

b. Findings

No findings of significance were identified.

.2 Source-Term Reduction and Control

a. Inspection Scope

The inspectors reviewed licensee records to evaluate the historical trends and the current status of tracked plant source terms. The inspectors determined if the licensee was making allowances and had developed contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry.

This inspection constituted one required sample as defined in IP 71121.02-5.

b. Findings

No findings of significance were identified.

Cornerstone: Public Radiation Safety

2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems (71122.01)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the configuration of the licensees gaseous and liquid effluent processing systems to confirm that radiological discharges were properly mitigated, monitored, and evaluated with respect to public exposure. The inspectors reviewed the performance requirements contained in General Design Criteria 60 and 64 of Appendix A to 10 CFR Part 50 and in the licensees Radiological Effluent Technical Specifications (RETS) and Offsite Dose Calculation Manual (ODCM). The inspectors also reviewed any abnormal radioactive gaseous or liquid discharges and any conditions since the last inspection when effluent radiation monitors were out-of-service to verify that the required compensatory measures were implemented. Additionally, the inspectors reviewed the licensee=s quality control program to verify that the radioactive effluent sampling and analysis requirements were satisfied and that discharges of radioactive materials were adequately quantified and evaluated.

The inspectors reviewed each of the radiological effluent controls program requirements to verify that the requirements were implemented as described in the licensees RETS.

For selected system modification (since the last inspection), the inspectors reviewed changes to the liquid or gaseous radioactive waste system design, procedures, or operation, as described in the USAR and plant procedures.

The inspectors reviewed changes to the ODCM made by the licensee since the last inspection to ensure consistency was maintained with respect to guidance in NUREG-1301, 1302, and 0133 and Regulatory Guides 1.109, 1.21, and 4.1. If differences were identified, the inspectors reviewed the licensees technical basis or evaluations to verify that the changes were technically justified and documented.

The inspectors reviewed the radiological effluent release reports for 2007 and 2008 in order to determine if anomalous or unexpected results were identified by the licensee, entered into the CAP, and adequately resolved.

The inspectors reviewed any significant changes in reported dose values from the previous radiological effluent release report, and the inspectors evaluated the factors which may have resulted in the change. If the change was not explained as being influenced by an operational issue (e.g., fuel integrity, extended outage, or major decontamination efforts), the inspectors independently assessed the licensee=s offsite dose calculations to verify that the licensees calculations were adequately performed and were consistent with regulatory requirements.

The inspectors reviewed the licensees correlation between the effluent release reports and the environmental monitoring results, as provided in Section IV.B.2 of Appendix I to 10 CFR Part 50.

This inspection constituted one sample as defined by IP 71122.01-5.

b. Findings

No findings of significance were identified.

.2 Onsite Inspection

a. Inspection Scope

The inspectors performed a walkdown of selected components of the gaseous and liquid discharge systems (e.g., gas compressors, demineralizers and filters (in use or in standby), tanks, and vessels) and reviewed current system configuration with respect to the description in the USAR. The inspectors evaluated temporary waste processing activities, system modifications, and the equipment material condition. For equipment or areas that were not readily accessible, the inspectors reviewed the licensee's material condition surveillance records, as applicable. The inspectors reviewed any changes that were made to the liquid or gaseous waste systems to verify that the licensee adequately evaluated the changes and maintained effluent releases ALARA.

During system walkdowns, the inspectors assessed the operability of selected point of discharge effluent radiation monitoring instruments and flow measurement devices. The effluent radiation monitor alarm setpoint values were reviewed to verify that the setpoints were consistent with RETS/ODCM requirements.

For effluent monitoring instrumentation, the inspectors reviewed documentation to verify the adequacy of methods and monitoring of effluents, including any changes to effluent radiation monitor set-points. The inspectors evaluated the calculation methodology and the basis for the changes to verify the adequacy of the licensees justification.

The inspectors observed the licensees sampling of liquid and gaseous radioactive waste (e.g., sampling of waste steams) and observed selected portions of the routine processing and discharge of radioactive effluents if those activities occurred during the onsite inspection. Additionally, the inspectors reviewed several radioactive effluent discharge permits, assessed whether the appropriate treatment equipment was used, and whether the radioactive effluent was processed and discharged in accordance with RETS/ODCM requirements, including the projected doses to members of the public.

The inspectors interviewed staff concerning effluent discharges made with inoperable (declared out-of-service) effluent radiation monitors to determine if appropriate compensatory sampling and radiological analyses were conducted at the frequency specified in the RETS/ODCM. For compensatory sampling methods, the inspectors reviewed the licensees practices to determine if representative samples were obtained and if the licensee routinely relied on the use of compensatory sampling in lieu of adequate system maintenance or calibration of effluent monitors.

The inspectors reviewed surveillance test results for non-safety-related ventilation and gaseous discharge systems (high efficiency particulate air and charcoal filtration) to verify that the systems were operating within the specified acceptance criteria. In addition, the inspectors assessed the methodology the licensee used to determine the stack/vent flow rates to verify that the flow rates were consistent with the RETS/ODCM.

The inspectors reviewed the licensees program for identifying any normally non-radioactive systems that may have become radioactively contaminated to determine if evaluations (e.g., 10 CFR 50.59 evaluations) were performed per NRC Bulletin 80-10.

The inspectors did not identify unidentified contaminated systems that may have been unmonitored discharge pathways to the environment.

The inspectors reviewed instrument maintenance and calibration records (i.e.,

both installed and counting room equipment) associated with effluent monitoring and reviewed quality control records for the radiation measurement instruments. The inspectors performed this review to identify any degraded equipment performance and to assess corrective actions, as applicable.

The inspectors reviewed the radionuclides that were included by the licensee in its effluent source term to determine if all applicable radionuclides were included (within detectability standards) in the licensees evaluation of effluents. The inspectors reviewed waste stream analyses (10 CFR Part 61 analyses) to determine if hard-to-detect radionuclides were also included in the source term analysis.

The inspectors reviewed a selection of monthly, quarterly, and annual dose calculations to ensure that the licensee had properly demonstrated compliance with 10 CFR Part 50, Appendix I, and RETS dose criteria.

The inspectors reviewed licensee records to identify any abnormal gaseous or liquid tank discharges (e.g., discharges resulting from misaligned valves, valve leak-by, etc.)

to determine if the licensee had implemented the required actions. The inspectors determined if abnormal discharges were assessed and reported as part of the Annual Radioactive Effluent Release Report consistent with Regulatory Guide 1.21.

The inspectors reviewed the licensees effluent sampling records (sampling locations, sample analyses results, flow rates, and source term) for radioactive liquid and gaseous effluents to verify that the licensees information satisfied the requirements of 10 CFR 20.1501.

This inspection constituted one sample as defined by IP 71122.01-5.

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 20.1501 for the failure to evaluate the potential radiological environmental dose impact associated with the extended non-functionality of the radioactive waste building ventilation system and its radiation detector.

Description:

The radioactive waste building (or radwaste building) houses resin disposal and processing equipment and radioactive waste handling, treatment, and storage facilities for both units. The radwaste building ventilation system is a monitored radioactive effluent release point by plant design. The radwaste building ventilation system radiation monitor (R-35) is a component of the radioactive gaseous effluent monitoring instrumentation program as described in the ODCM and is provided to monitor the releases of radioactive materials in gaseous effluents during actual or potential releases to the environment. The effluent release point is monitored for beta-gamma radioactivity through the exhaust stack with a gaseous detector in an off-line sampler. The radiation monitor is equipped with remote indication that provides a high radiation alarm function and is intended to alert plant personnel in the event of a radwaste building effluent discharge with elevated radioactivity. The radiation monitor is required by the ODCM to be operational when the radwaste building ventilation system is operational. It is intended that the radwaste building ventilation system is operational when the radwaste building is operational, in that, the radwaste building ventilation radiation monitor is a point of discharge effluent radiation monitor and is used in establishing entry conditions for emergency action levels in the licensees emergency plan.

The radwaste building ventilation system was taken out-of-service to repair the ventilation duct heater. When the ventilation system is out-of-service, the associated radiation monitor (R-35) is also out-of-service because of low-flow conditions in the ventilation duct. In 2008 and 2009, the radwaste ventilation system had been repaired, placed into service, and taken back out-of-service repeatedly for various reasons.

During that time period, the ventilation system was out-of-service for 93 of 105 weeks.

With the ventilation system out-of-service, the building was at atmospheric pressure and conditions. Normal and routine radwaste building operations continued unabated while the ventilation system was out-of-service. Any building out-leakage (effluent discharge)was a function of the radwaste processing and work activities that occurred within the building.

The licensee instituted no compensatory measures when the ventilation system was taken out-of-service. Specifically, the licensee did not institute administrative controls, engineering controls, or compensatory radioactive sampling to control or evaluate airborne generating activities within the building. Once brought to their attention, the licensee conducted a review of the operational conditions and calculated the radiological release from the building based upon operational parameters of the radwaste building over the last 2 years. The inspectors reviewed this data and confirmed that any releases were well below the applicable regulatory requirements.

Analysis:

The failure to evaluate the potential radiological hazards and associated effluent release paths with the radwaste building ventilation system out-of-service represented a performance deficiency as defined in IMC 0612, APower Reactor Inspection Reports,@ Appendix B, AIssue Screening.@ The inspectors determined that the cause of the performance deficiency was reasonably within the licensees ability to foresee and correct and should have been prevented. This finding was more than minor because it was associated with the program/process attribute of the Public Radiation Safety cornerstone. In addition, the finding impacted the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian nuclear reactor operation. Since the finding involved the ability to assess dose from radioactive effluents and maintain radiation doses to a member of the public within Appendix I design objectives, the inspectors utilized IMC 0609, Appendix D, APublic Radiation Safety SDP,@

to assess its significance. The inspectors determined that the finding was of very low safety significance because it did not involve radioactive material control, there was not a substantial failure to implement the radiological effluent program, and public dose was less than Appendix I criteria and 10 CFR 20.1301. The condition of the radwaste building ventilation system was a long-standing, uncorrected issue that was repeatedly documented in the licensees CAP. Consequently, the primary cause of the finding was related to the cross-cutting aspect of Problem Identification and Resolution, in that, the licensee failed to thoroughly evaluate this problem commensurate with its significance and take corrective action in a timely manner. (P.1(c)).

Enforcement:

Title 10 CFR 20.1501 requires that each licensee make or cause to be made surveys that may be necessary for the licensee to comply with the regulations in 10 CFR Part 20 and that are reasonable under the circumstances to evaluate the extent of radiation levels, concentrations or quantities of radioactive materials, and the potential radiological hazards that could be present.

• Pursuant to 10 CFR 20.1003, survey means an evaluation of the radiological conditions and potential hazards incident to the production, use, transfer, release, disposal, or presence of radioactive material or other sources of radiation.

Contrary to the above, for an approximate 2-year period, the licensee did not make adequate surveys to assure compliance with 10 CFR 20.1301, which limits radiation exposure to a member of the public to 0.1 rem. However, because this finding was of very low safety significance and documented in the licensees CAP as CAP 1201838, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy (NCV 05000282/2009005-02; 05000306/2009005-02). Corrective actions for this issue included performing surveys to assure compliance to the applicable regulations and instituting supplemental sampling in the radwaste building when the ventilation system is out-of-service.

.3 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed the licensees self-assessments, audits, Licensee Event Reports, and Special Reports related to the radioactive effluent treatment and monitoring program since the last inspection to determine if identified problems were entered into the CAP for resolution. The inspectors also assessed whether the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

The inspectors reviewed CAPs from the radioactive effluent treatment and monitoring program since the previous inspection, interviewed staff, and reviewed documents to determine if the following activities were conducted in an effective and timely manner commensurate with their importance to safety and risk:

• initial problem identification, characterization, and tracking;

• disposition of operability/reportability issues;

• evaluation of safety significance/risk and priority for resolution;

• identification of repetitive problems;

• identification of contributing causes;

• identification and implementation of effective corrective actions;

• resolution of NCVs tracked in the CAP system;

• implementation/consideration of risk significant operational experience feedback; and

• ensuring problems were identified, characterized, prioritized, entered into a corrective action, and resolved.

This inspection constituted one sample as defined by IP 71122.01-5.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Residual Heat Removal System Performance Indicator (PI) for Units 1 and 2 for the period of the fourth quarter 2008 through the third quarter of 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, CAPs, MSPI derivation reports, event reports, and NRC Integrated IRs for the time period discussed above to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP 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 MSPI residual heat removal system samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.2 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems PI for Units 1 and 2 for the period of the fourth quarter 2008 through the third quarter of 2009.

To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, CAPs, MSPI derivation reports, event reports, and NRC Integrated IRs for the time period discussed above to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP 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 MSPI cooling water system samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.3 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the RETS/ ODCM Radiological Effluent Occurrences PI for the period of June 2008 through August 2009. The inspectors used PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees CAP database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates between June 2008 and August 2009 to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose.

This inspection constituted one RETS/ODCM radiological effluent occurrences sample 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 attached List of Documents Reviewed.

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

In order to assist with the identification of repetitive equipment failures and specific human performance issues for followup, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the licensees daily CAP 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 Semiannual 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 screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6 month period of July 2009 through December 2009, although some examples expanded beyond those dates where the scope of the trend warranted.

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

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

b. Findings

(1) Previously Identified Trend - Ability to Identify and Thoroughly Evaluate Problems In June 2008, the inspectors identified an adverse trend regarding the licensees ability to identify and thoroughly evaluate problems. Several examples of this trend were documented in IR 05000282/2009003; 05000306/2009003. In August 2009, the NRC completed their biennial Problem Identification and Resolution (PI&R) team inspection.

The inspection team identified that overall problem identification was adequate.

However, several previous NRC identified findings demonstrated elements of failure to identify an issue through generation of a CAP. The inspectors concluded that further improvement was needed in regards to standards, expectations, and accountability.

With respect to the evaluation of problems, the inspection team found that overall performance was acceptable, but marginal. While most evaluations were good, some evaluation weaknesses observed by the inspectors could be characterized as addressing the symptoms rather than the causes. Most weaknesses identified by the inspectors could be attributed to a lack of rigor during the problem analysis.

Based upon the results of the PI&R inspection, the NRC has decided to perform another inspection during 2010. The information developed during the 2009 PI&R inspection, and in this adverse trend, will be reviewed during the 2010 PI&R inspection. Therefore, this adverse trend is closed.

(2) Previously Identified Trend - Untimely Implementation of Actions Following Operating Experience Reviews In June 2009, the inspectors identified an adverse trend regarding the untimely implementation of actions to address operating experience information. In August 2009, the NRC completed their biennial PI&R team inspection. The inspection team determined that there was a weakness related to the implementation of operating experience that could lead to additional equipment failures or the failure to identify an adverse condition. The licensee documented this issue in a CAP. Based upon the results of the PI&R inspection, the NRC has decided to perform another inspection during 2010. The information developed during the 2009 PI&R inspection, and in this adverse trend, will be reviewed during the 2010 PI&R inspection. Therefore, this adverse trend is closed.

(3) New Trend - Fouling of Cooling Water Pump Right Angle Drive Coolers As part of the inspection documented in Section 4OA3.3 of this report, the inspectors identified an adverse trend regarding fouling of the right angle drive gear oil coolers for the diesel-driven cooling water pumps. See Section 4OA3.3 for further details.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report 05000306/2008-001-00: Unanalyzed Condition Due to

Both Trains of Component Cooling Susceptible to a Postulated High Energy Line Break

a. Inspection Scope

From December 2008 through November 24, 2009, the NRC conducted an inspection which reviewed the licensees actions regarding the Unit 2 component cooling water system being susceptible to failure following a high energy line break (HELB) in the turbine building. The purpose of this inspection was to determine whether reasonable confidence existed that docketed information was complete and accurate in all material aspects and that the licensee had taken appropriate corrective actions to ensure that future regulatory submittals were complete and accurate. The inspectors also reviewed the technical adequacy of the information provided in the Licensee Event Report (LER).

The equipment issue discussed in the LER was evaluated by the inspectors and documented as a White finding in NRC IRs 05000282/2008005; 05000306/2008005, 05000306/2009010, and 05000306/2009013. Documents reviewed as part of this inspection are listed in the attachment.

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

b. Findings

Introduction:

A Severity Level IV NCV was identified by the inspectors due to the licensee submitting an LER (LER 05000306/2008-001-00) which was determined not to be accurate or complete in all material aspects.

Description:

On July 29, 2008, the licensee initiated CAP 1145695 to document that the Unit 2 component cooling water (CC) system was vulnerable to failure following a HELB in the turbine building. As a result of the licensees operability evaluation, the Unit 2 CC system was declared inoperable on July 31, 2008. The licensee reported the inoperability of the CC system to the NRC via LER 05000306/2008-001-00, Unanalyzed Condition Due to Both Trains of Component Cooling Being Susceptible to a Postulated High Energy Line Break. This LER was issued on September 29, 2008; page 1 of the LER documented that the Unit 2 CC system issue was an original design issue uncovered during walkdowns performed in support of turbine building CC system seismic qualification.

In October 2008, inspectors discussed the applicability of the old design issue criteria established in IMC 0305 with the licensee management and engineering staff. During these discussions, the licensee indicated they felt the CC system issue met the criteria for being considered an old design issue. Over the next several months the inspectors continued to review licensee actions associated with the LER. In early December 2008, inspectors found several documents which conflicted with the LER in regard to the timeframe when the licensee had become aware of the CC system vulnerability and the HELB susceptibility. Specifically, the walkdowns referred to in the LER were performed on approximately July 29, 2008. However, the inspectors found both a January 2008 Sargent and Lundy report and an apparent cause evaluation report which indicated that the CC system vulnerability to turbine building HELBs was known by the licensee in July 2006.

Based on this new information, the inspectors concluded that the characterization of this issue as an old design was incorrect. In December 2008, the inspectors notified the licensee of the potential incomplete information included in the LER. On January 19, 2009, the licensee issued a supplement to the LER to address the inspectors comments. The inspectors reviewed the LER supplement and were satisfied with the revision.

Due to the potential willful aspects associated with the LER information, the inspectors provided information to the Office of Investigations for review. On April 29, 2009, a review was initiated to determine if licensee personnel willfully failed to provide complete and accurate information to the NRC in LER 05000306/2008-001-00. The investigation was completed November 24, 2009, and based upon the evidence, did not substantiate that personnel willfully failed to provide complete and accurate information to the NRC.

However, information included in LER 05000306/2008-001-00 was not complete and accurate in all material respects.

Analysis:

Because violations of 10 CFR 50.9 are considered to potentially impede or impact the regulatory process, they are dispositioned using the traditional enforcement process. The inspectors concluded that the licensee had reasonable opportunity to foresee and correct the inaccurate/incomplete information prior to the information being submitted to the NRC. As a result, this issue was considered a performance deficiency.

The issue was more than minor since it had the potential to impact the NRCs ability to perform its regulatory function. Using the information provided in IMC 0612, Appendix B, Issue Screening, this issue was determined to be a Severity Level IV NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy since it did not amount to a Severity Level I,II or III violation. The inspectors determined the primary cause of this issue was related to Human Performance, Work Control since work activities were not coordinated to address the impact of work on different job activities and the need for groups to communicate, coordinate, and cooperate with others during work activities (H.3(b)).

Specifically, the lack of communication and coordination between the licensees Engineering and Regulatory Affairs Departments did not afford Engineering knowledge to be incorporated into the LER prior to submittal to the NRC.

Enforcement:

Title 10 of the Code of Federal Regulations Section 50.9(a) requires, in part, that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Additionally 10CFR50.73 establishes requirements for licensee submittal of LERs for events described there within.

Contrary to the above, on September 29, 2008, the licensee submitted LER 05000306/2008-001-00 which was not complete and accurate in all material aspects. Specifically, the LER documented that the condition was an original design issue uncovered during walkdowns (e.g. July 2008) completed in support of turbine building CC system seismic qualification. However, the LER did not include information that the licensee had knowledge of this issue as far back as 2006. This information was material to the NRC because it affected the NRC's determination as to whether this issue could be characterized as an old design issue per IMC 0305. This issue was entered in the licensees CAP as CAP 1212435 and the licensee planned to perform an apparent cause evaluation. Since the violation was non-willful and non-repetitive, it is being treated as a Severity Level IV NCV consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000306/2009005-03).

This LER is closed.

.2 (Closed) Licensee Event Report 05000282/2009-005-00: Reactor Trip Due to 12

Circulating Water Pump Trip Caused by Electrical Ground Fault

Introduction:

A self-revealed Green finding occurred on May 18, 2009, due to the licensees failure to replace electrical cable in accordance with the standards documented in their corrective action procedure. Specifically, in December 2002 the licensee identified that electrical cable associated with the 12 circulating water pump motor and five additional pump motors was susceptible to failure due to a manufacturing defect and moisture intrusion. Although the licensee had planned to replace the electrical cable, and had received six other examples of operating experience from the industry and the NRC, the cable was not replaced. As a result, the 12 circulating water pump motor cables degraded to the point that the cables experienced a ground fault.

This ground fault tripped the 12 circulating water pump. A Unit 1 automatic reactor trip also occurred.

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

Description:

On May 18, 2009, at 1:04 p.m., the Unit 1 control room operators received several unexpected annunciators indicating that the 12 circulating water pump had shut down. The loss of the 12 circulating water pump caused a subsequent reduction in circulating water system flows and an increase in condenser differential pressure.

Approximately 1 minute later, the Unit 1 reactor automatically tripped from 100 percent power due to a sensed high differential pressure condition. The inspectors responded to the control room and verified that all safety systems operated as expected following the trip. The inspectors also confirmed that the control room operators actions following the reactor trip were in accordance with procedures.

The inspectors monitored the licensees troubleshooting activities which included electrical cable and motor testing, testing of the pumps motor breaker, boroscopic inspection of conduit containing the electrical cables for the 12 circulating water pump motor, and a visual inspection of the 12 circulating water pump motor cables. During the boroscopic inspection, the inspectors saw several areas where water had accumulated inside the conduit. During the visual inspection of the motor cables, the inspectors identified multiple areas of cable degradation. The licensee also determined that the main condenser high differential pressure condition sensed during this event was caused by degraded protective circuitry. Had this circuitry been functioning appropriately an automatic reactor trip may not have occurred.

The inspectors reviewed the licensees root cause report for this event. In March 1995, the licensee experienced a failure of a 4 kV Okonite EPR cable to the 123 cooling tower pump. During a subsequent review of the 1995 cable failure, the licensee identified that Okonite EPR cable manufactured prior to 1974 was susceptible to failure due to water intrusion and contaminates introduced during the manufacturing process. This specific 4 kV cable was replaced but an extent of condition review was not performed.

In 2002, the licensee received NRC Information Notice 2002-12, Submerged Safety-Related Electrical Cables, and operating experience information from the Diablo Canyon Nuclear Plant regarding 4 kV cable failures. The licensee reviewed this operating experience and determined that the non-safeguards cooling water pump motor cables and the circulating water pump motor cables were susceptible to failure. The licensee initiated WOs to replace the cables associated with these pumps. Between December 2002 and July 2003, the licensee received operating experience from two additional nuclear plants regarding failures of similar cables. In addition, Prairie Island experienced a momentary loss of power to a safety-related electrical bus due to the presence of water in a cable and age-related degradation. Lastly, the licensee identified and repaired a degraded cable jacket for the 22 circulating water pump motor. Although specific deficiencies were corrected, no actions were taken to replace the pump motor cables discussed above in an expedited manner.

In April 2005, the licensee canceled the WOs initiated to replace the motor cables for the non-safeguards cooling water pumps and the circulating water pumps. Instead, the licensee initiated an action to incorporate the cable replacement into their 5-year plan.

The action to incorporate the cable replacement into the 5-year plan was modified in October 2005 to add the development of a cable condition monitoring program. In 2007, the NRC issued GL 2007-01, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigating or Cause Plant Transients. The licensee responded to this Generic Letter and indicated that an underground cable maintenance program would be implemented by the end of 2007. During an NRC inspection conducted in early 2008, the inspectors identified that the underground cable maintenance program had not been implemented. As a result, appropriate testing had not been performed to evaluate the material condition of underground power cables. The licensee implemented their underground cable maintenance program in December 2008.

Analysis:

The inspectors determined that the licensees decision regarding the motor cable replacements failed to meet standards for correcting equipment deficiencies that have a reasonable potential to affect the functionality of critical (maintenance rule)systems. Specifically, Step 4.10 of Procedure FP-PA-ARP-01, CAP Action Request Process, defined equipment deficiencies that have a reasonable potential to affect the functionality of critical (maintenance rule) systems as conditions adverse to quality. The licensees self-imposed standard is that conditions adverse to quality be identified and corrected in a timely manner commensurate with their safety significance. Due to the potential for creating a reactor trip, and the potential for affecting the functionality of a maintenance rule system, the inspectors determined that the 7 years that had elapsed since the licensees discovery of the cable failure vulnerability was not commensurate with the safety significance of the issue. As a result, the failure to replace the cables was determined to be a performance deficiency that required evaluation using the SDP.

The inspectors determined that this issue impacted the Initiating Events cornerstone.

This issue was determined to be more than minor because it was associated with the protection against external factors and equipment performance attributes of the initiating events cornerstone. This issue also impacted the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors determined that this finding was of very low safety significance because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available (FIN 05000282/2009005-04). The inspectors concluded that this issue was cross-cutting in the Human Performance, Decision Making area, because the licensee failed to use conservative assumptions during their decisions regarding the need for cable replacements even after receiving numerous pieces of operating experience information (H.1.(b)).

Enforcement:

No violation of NRC requirements was identified during this inspection due to the 12 circulating water pump being non-safety related. Corrective actions for this issue included replacing the motor cables and scheduling the cable replacement for other susceptible pumps.

This LER is closed.

.3 Inoperability of 12 Diesel-Driven Cooling Water Pump Due to Debris Blockage

a. Inspection Scope

The inspectors reviewed the circumstances surrounding the inoperability of the 12 diesel-driven cooling water pump (DDCLP) identified on August 27, 2009.

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

b. Findings

Introduction:

The inspectors identified a finding of very low safety significance and an NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, due to the licensees failure to accomplish activities affecting quality in accordance with procedures appropriate to the circumstance. Specifically, licensee personnel failed to identify repeated blocking of the DDCLP right angle drive gear oil coolers with debris as an adverse trend even though blockages had been identified four different times between July 2005 and August 2009. As a result, the adverse trend was not characterized as a significant condition adverse to quality as required by Procedure FP-PA-ARP-01, Corrective Action Program. The failure to identify this issue as an adverse trend and a significant condition adverse to quality resulted in the untimely implementation of corrective actions to prevent recurrence. The lack of actions also contributed to the August 27, 2009, inoperability of the 12 DDCLP.

Description:

On August 27, 2009, the licensee identified a low flow condition on the 12 DDCLP right angle drive gear oil cooler via CAP 1195413. The inspectors discussed this CAP with operations and engineering personnel and learned that ultrasonic flow instrumentation had been installed on the 12 and 22 DDCLPs in order to monitor flow to the right angle drive gear oil coolers during an on-going zebra mussel treatment.

The ultrasonic flow instrumentation was typically installed several days prior to the zebra mussel treatment. Flow monitoring continued for 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after the treatment. After this time period, the ultrasonic flow instruments were removed and no means were available to monitor coolant flow to the right angle drive gear oil coolers.

Technical Manual XH-48-71 required 15 to 20 gallons of cooling water flow per minute be provided to each right angle drive gear oil cooler to ensure continued operability of the respective DDCLP. However, on August 27, 2009, the ultrasonic flow meter indicated that only 15.1 gallons per minute were available to the right angle drive gear oil cooler for the 12 DDCLP. After validating the accuracy of the flow meter, the licensee evaluated the impact of this low flow condition on the continued operability of the 12 DDCLP. Operations personnel concluded that although the flow rate met the requirements of the technical manual, any start of the 12 DDCLP would cause a pressure drop such that the flow available to the right angle drive gear oil cooler would decrease below 15 gallons per minute. As a result, operations personnel declared the 12 DDCLP inoperable. Maintenance personnel opened and inspected the right angle drive gear oil cooler. The inspection revealed that debris blockage (primarily zebra mussel shells) was the cause of the flow reduction. The licensee conducted an apparent cause evaluation which concluded that the ultrasonic flow meters were to be re-installed to allow continued flow monitoring to the coolers. In addition, operating instructions were developed to ensure that flow to the right angle drive gear oil coolers were monitored and recorded each shift. Lastly, the licensee quarantined the zebra mussel treatment procedure until a modification was installed to protect the right angle drive gear oil coolers from further debris blockage.

Based upon the results of the maintenance, the inspectors questioned the licensee regarding the rate of debris intrusion for the 12 DDCLP right angle drive gear oil cooler and the potential for a similar thing to occur on the 22 DDCLP. The inspectors also searched the licensees CAP database to determine whether other blockages had occurred. The inspectors found that in July 2005 the licensee experienced a complete loss of DDCLP safety function after the common right angle drive gear cooling water supply line became blocked with a stick. Corrective actions for this issue included the development and implementation of a modification to strain the cooling water supplied to the right angle drive gear coolers. However, the modification had not been accomplished as of August 2009.

On January 16, 2007, the licensee initiated CAP 1072185 to document debris found in one of the right angle drive gear oil coolers during annual preventive maintenance (PM). In addition, the licensee identified that debris (e.g. primarily zebra mussel shells)had blocked a number of the right angle drive gear oil cooler heat exchanger tubes.

Licensee evaluation determined that the tube blockage was bounded by an engineering analysis documented in ENG-ME-604, Tube Plugging Limits for DDCLP Right Angle Drive Gear Oil Cooler. The CAP further recommended that the licensee consider increasing the frequency of the annual PM and to provide a strained water supply to the DDCLP right angle drive gear oil coolers. The CAP was closed based on a recommendation to issue an engineering change request (ECR) for the strained water supply and to investigate funding the ECR so the modification could be installed.

On March 16, 2009, the licensee identified debris blockage on the 12 DDCLP right angle drive gear oil cooler during performance of the annual PM. This issue was documented by the licensee under CAP 1173205. Engineering evaluation of this condition determined the blockage was bounded by the acceptance criteria of ENG-ME-604. To address longer term corrective actions, the CAP recommended changing the frequency of the PM from annually to semi-annually. The CAP also recommended providing funding to install the strainers requested by the previously generated ECR. This ECR action remained open as of the close of this inspection period. The PM frequency change was closed to a procedure change request implemented on January 4, 2010.

The inspectors determined that none of the CAPs previously initiated to document the debris blockage issues had been characterized as significant under the licensees CAP.

The inspectors reviewed Procedure FP-PA-ARP-01, CAP Action Request Process, and identified that Attachment 1 to this procedure identified adverse trends of recurring safety significant equipment as a Level A issue. Step 4.28.1 of FP-PA-ARP-01 defined Level A issues as significant conditions adverse to quality. NRC regulations require that licensees implement corrective actions to prevent recurrence for all significant conditions adverse to quality. The inspectors concluded that if the licensee had followed FP-PA-ARP-01 the debris blockage issues would have been identified as an adverse trend and a significant condition adverse to quality. In addition, corrective actions to prevent recurrence would have been required to be implemented and the August 27, 2009, inoperability of the 12 DDCLP would not have occurred.

Analysis:

The inspectors determined that the licensees failure to follow the corrective action procedure was a performance deficiency requiring evaluation using IMC 0609, Appendix A Significance Determination Process. The inspectors concluded that the finding was more than minor because the failure to properly implement the corrective action procedure and identify this adverse trend impacted the equipment performance attribute of the Mitigating Systems cornerstone and impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding was of very low safety significance because it did not involve a loss of safety function of a single train for greater than TS allowed outage time, did not involve a loss of system of safety function and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors concluded that this finding was cross-cutting in the Human Performance, Decision Making area because the licensee failed to appropriately use systematic processes (i.e., the corrective action and the preventive maintenance processes) when making safety-significant decisions regarding the repeated blockage of the right angle drive gear oil coolers (H.1(a)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be accomplished in accordance with procedures appropriate to the circumstances. Attachment 1 of FP-PA-ARP-01 identified an adverse trend of recurring safety significant equipment as a Level A issue. Step 4.28.1 of FP-PA-ARP-01 defined Level A issues as significant conditions adverse to quality. The NRC requires that licensees implement corrective actions to prevent recurrence for all significant conditions adverse to quality. Contrary to the above, both prior to and on August 27, 2009, the licensee failed to implement their corrective action procedure, an activity affecting quality, appropriate to the circumstance.

Specifically, licensee personnel failed to identify the debris blockage of the 12 and 22 DDCLP right angle drive gear oil coolers as an adverse trend despite numerous opportunities. As a result, the repeated debris blockage events were not characterized as a significant condition adverse to quality and corrective actions to prevent recurrence were not implemented. The lack of action resulted in the inoperability of the 12 DDCLP on August 27, 2009. Because this violation was of very low safety significance, and it was entered into the CAP as CAP 1196214, it is being treated as an NCV consistent with VI.A.1 of the NRC Enforcement Policy (NCV 05000282/2009005-05; 05000306/2009005-05). Corrective actions for this issue included the continued installation of ultrasonic flow meters to monitor flow to the right angle drive gear oil coolers and the implementation of a modification to strain the cooling water flow to the right angle drive gear oil coolers prior to performing the next zebra mussel treatment.

.4 Waste Gas System Leakage

a. Inspection Scope

The inspectors reviewed the circumstances associated with the in-plant leakage of the radioactive waste decay system components as documented in the Prairie Island Annual Radioactive Effluent Release Reports for 2006, 2007, and 2008.

The inspectors reviewed the licensee's radiological assessment of each of these abnormal releases to determine if the isotopic concentrations and volumes released were accurately calculated. The inspectors also reviewed the licensee's offsite dose analyses to verify that the environmental impact was small compared to regulatory limits, as reported by the licensee. The dose impact from each unmonitored release was less than 1 percent of the 10 CFR Part 50, Appendix I, design objective.

Minor computational errors in the gamma and beta dose values in the corrective action section of the waste gas system in the 2007 Annual Radioactive Effluent Report were identified by the inspectors and brought to the licensees attention. Once informed of the errors by the inspectors, the licensee initiated CAP 1176252 and has since submitted corrected information to the NRC. The inspectors reviewed the licensees corrected data and confirmed that the isotopic concentrations and volumes released were accurately calculated.

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

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

b. Findings

No findings of significance were identified.

.2 (Open) Temporary Instruction 2515/177, Managing Gas Accumulation in

Emergency Core Cooling, Decay Heat Removal and Containment Spray Systems (NRC GL 2008-01)

As documented in Section 1R15 of this report, the inspectors confirmed the acceptability of the licensees described actions. This inspection effort counts towards the completion of TI 2515/177 which will be closed in a later IR.

.3 (Open) Unresolved Item 05000282/2009003-01; 05000306/2009003-01: Potential

Turbine Building Flooding Issue As discussed in Section 1R15 of this report, the inspectors reviewed OPR 1178236-04, Revision 2, Internal Flooding Impacts in Turbine Building. During this review, the inspectors questioned the accuracy of the licensees determination which showed that manual operator actions to address a turbine building flooding event would be completed approximately 5 minutes prior to the flood waters reaching levels that could impact the operability of safety-related equipment. In response to the inspectors questions, the licensee constructed a temporary flood barrier to protect the D1 and D2 emergency diesel generators. The licensee planned to keep the temporary barrier in place until additional analysis was available to demonstrate that the timeliness of the manual operator actions was adequate to protect this equipment. As a result, this issue is considered unresolved pending a review of the licensees analysis.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 6, 2010, the inspectors presented the inspection results to Mr. Mark Schimmel and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• On October 9, 2009, the inspectors presented the results of the inspections performed under the radiation safety section of this report to Mr. Mark Schimmel. An additional teleconference was held on December 22, 2009, with Mr. Robert Hite and other members of the licensee staff.

• The annual review of Emergency Action Level and Emergency Plan changes with the licensee's Emergency Preparedness Manager, Ms. K. DeFusco, via telephone on December 22, 2009.

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.

.3 Regulatory Performance Meeting

On September 4, 2009, J. Giessner, Chief, Branch 4, DRP, Region III, and staff met with the licensee to discuss performance in accordance with IMC 0305, Section 10.01.a.

During this meeting, the NRC and the licensee discussed the issues related to the White finding that resulted in Prairie Island Nuclear Generating Plant, Unit 1 being placed in the Regulatory Response Column of the NRC Action Matrix. This discussion included the causes, corrective actions, extent of condition, extent of cause, and other planned licensee actions.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as Non-Cited Violations.

Cornerstone: Initiating Events

• Technical Specification 5.4.1 requires that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Sections 1.b, 1.c, and 1.g of Regulatory Guide 1.33 require procedures governing authorities and responsibilities for safe operation and shutdown, equipment control, and shift relief and turnover respectively. The licensee used Procedure FP-OP-COO-01, Conduct of Operations, to satisfy those sections of Regulatory Guide 1.33.

Contrary to the above, on November 3, 2009, the licensee failed to implement procedures associated with Sections 1.b, 1.c, and 1.g of Regulatory Guide 1.33.

Specifically, the failure to implement these procedures resulted in the untimely identification of an abnormal seal leak off condition on the 12 reactor coolant pump (RCP), that entry into Abnormal Operating Procedure (AOP) 1C3 AOP3, Failure of a Reactor Coolant Pump Seal, was required, and that the 12 RCP needed to be shut down due to the low flow condition existing for greater than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The licensee documented this issue in CAP 1206681. Corrective actions for this issue included entering the AOP, shutting down the 12 RCP, replacing the 12 RCP seal package, and improving control room panel monitoring, equipment control and shift turnover activities. The finding is of very low significance because no transient resulted from the abnormal seal leak off condition.

Cornerstone: Public Radiation Safety

• Technical Specification 5.7.1 requires that high radiation areas be barricaded and conspicuously posted. Contrary to the above, on September 18, 2009, a vacuum cleaner used for reactor cavity clean up was discovered next to the reactor cavity. Radiation levels emitting from the materials collected in the vacuum cleaner were measured at 700 millirem per hour at 30 centimeters. The licensee determined through its investigation that the elevated radiation levels existed for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. This was documented in the licensees CAP as CAP 1198503. Corrective actions included performance management of the individuals involved in accordance with station protocol. The finding was determined to be of very low safety significance because it was not an ALARA planning issue, there was no overexposure nor potential for overexposure, and the licensees ability to assess dose was not compromised.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Schimmel, Site Vice President

B. Sawatzke, Director Site Operations

K. Ryan, Plant Manager

J. Anderson, Regulatory Affairs Manager

K. DeFusco, Emergency Preparedness Manager

B. Flynn, Safety and Human Performance Manager

R. Hite, Radiation Protection and Chemistry Manager

D. Kettering, Site Engineering Director

J. Lash, Operations Manager

R. Madjerich, Production Planning Manager

J. Muth, Nuclear Oversight Manager

S. Northard, Performance Improvement Manager

K. Peterson, Acting Business Support Manager

M. Schmidt, Maintenance Manager

J. Sternisha, Training Manager

Nuclear Regulatory Commission

J. Giessner, Reactor Projects Branch 4 Chief

T. Wengert, Office of Nuclear Reactor Regulation Project Manager

LIST OF ITEMS

Opened

05000282/2009005-01; NCV Valve technician became internally and externally

05000306/2009005-01 contaminated when he breached the RH-2-1 valve contrary to the requirements of the RWP. (Section 2OS1.1)

05000282/2009005-02; NCV Radioactive waste building ventilation system and the

05000306/2009005-02 associated radiation detector being out of service for extended periods of time without instituting compensatory actions. (Section 2PS1.2)

05000306/2009005-03 NCV Failure to Provide Complete and Accurate Information for LER

05000306/2008-001-00. (Section 4OA3.1)

05000282/2009005-04 FIN 12 Circulating Water Pump Trip and Unit 1 Automatic Reactor Trip. (Section 4OA3.2)

05000282/2009005-05; NCV Failure to Follow Procedure Results in Failure to Identify

05000306/2009005-05 Adverse Trend Regarding Cooling Water Pump Right Angle Drive Fouling. (Section 4OA3.3)

Attachment

Closed

05000282/2009005-01; NCV Valve Technician Became Internally and Externally

05000306/2009005-01 Contaminated When He Breached the RH-2-1 Valve Contrary to the Requirements of the RWP

05000282/2009005-02; NCV Radioactive Waste Building Ventilation System and the

05000306/2009005-02 Associated Radiation Detector Being Out of Service for Extended Periods of Time Without Instituting Compensatory Actions

05000306/2009005-03 NCV Failure to Provide Complete and Accurate Information for LER

05000306/2008-001-00

05000282/2009005-04 FIN 12 Circulating Water Pump Trip and Unit 1 Automatic Reactor Trip

05000282/2009005-05; NCV Failure to Follow Procedure Results in Failure to Identify

05000306/2009005-05 Adverse Trend Regarding Cooling Water Pump Right Angle Drive Fouling

05000306/2008-001-00 LER Unanalyzed Condition Due to Both Trains of Component Cooling Susceptible to a Postulated High Energy Line Break

05000282/2009-005-00 LER Reactor Trip Due to 12 Circulating Water Pump Trip Caused by Electrical Ground Fault

Discussed

05000282/2009003-01; URI Potential Turbine Building Flooding Issue

05000306/2009003-01 2515/177 TI Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems Attachment