IR 05000282/2008002

IR 05000282-08-002, 05000306-08-002, on 01/01/2008 - 03/31/2008, Prairie Island Nuclear Generating Plant, Units 1 & 2, Operability Evaluations, Access Control to Radiologically Significant Areas

ML081350356
Person / Time
Site:	Prairie Island
Issue date:	05/14/2008
From:	Richard Skokowski Region 3 Branch 3
To:	Wadley M Nuclear Management Co
References
IR-08-002
Download: ML081350356 (63)

Text

May 14, 2008

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000282/2008002 AND 05000306/2008002

Dear Mr. Wadley:

On March 31, 2008, 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 April 8, 2008, with Mr. J. Sorensen and other members of your staff.

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

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

Based on the results of this inspection, two findings were noted during the inspection.

These findings were considered to be of very low safety significance. In addition, two licensee identified violations which were determined to be of very low safety significance are listed in this report. Because of the very low safety significance, and because these issues were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations (NCVs) in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest the subject or severity of a NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant. 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/

Richard A. Skokowski, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-282; 50-306;72-010 License Nos. DPR-42; DPR-60; SNM-2506 Enclosure: Inspection Report 05000282/2008002 and 05000306/2008002 w/Attachment: Supplemental Information cc w/encl: D. Koehl, Chief Nuclear Officer Regulatory Affairs Manager P. Glass, Assistant General Counsel Nuclear Asset Manager John Linc Stine, Division Director, Minnesota Department of Health Tribal Council, Prairie Island Indian Community Administrator, Goodhue County Courthouse Commissioner, Minnesota Department of Commerce Manager, Environmental Protection Division Office of the Attorney General of Minnesota

SUMMARY OF FINDINGS

IR 05000282/2008002, 05000306/2008002; 01/01/2008 - 03/31/2008; Prairie Island Nuclear

Generating Plant, Units 1 & 2; Operability Evaluations, Access Control to Radiologically Significant Areas.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were identified. These findings were considered Non-Cited Violations (NCVs) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Emergency Preparedness

Green.

The inspectors identified a NCV of 10 CFR 50.54(q), associated with 10 CFR 50.47(b)(8), for failing to maintain adequate emergency facilities to support emergency response. Specifically, the licensee failed to maintain control of the Technical Support Center ventilation system. As a result, the system was frequently found to be in a degraded condition that may not have provided adequate protection for emergency response personnel.

This finding was more than minor because it was associated with the attribute of meeting the planning standards of 10 CFR 50.47(b). In addition, the finding affected the cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. In accordance with the SDP Phase 1 Screening Worksheet of IMC 0609, the inspectors applied Appendix B, Emergency Preparedness Significance Determination Process, Section 4.8 and determined that this issue was of very low safety significance. Specifically, the Technical Support Center ventilation system was degraded for a period of longer than seven days from the time of original discovery. In addition, the degradation was to the extent that key emergency response organization members may not have been able to perform their assigned plan functions without compensatory measures. The finding was determined to be cross-cutting in the corrective action program aspect of the Problem Identification and Resolution cross-cutting area because the licensee failed to thoroughly evaluate repeated problems with the Technical Support Center ventilation system such that the causes of the problems were identified and addressed (P.1(c)). (Section 1R15)

Cornerstone: Occupational Radiation Safety

Green.

A self-revealing finding of very low safety significance and an associated NCV were identified for the licensees failure to comply with Technical Specification 5.7.1.b for access control to high radiation areas of the plant. As a result of poor human performance, a contract radiation worker received an electronic dosimeter high dose-rate alarm while performing steam generator set-up activities, when he inappropriately entered a high radiation area of the plant on a non-high radiation area radiation work permit. As corrective actions, the licensee provided additional training to the individuals involved and reinforced the expectations for high radiation area access control.

The finding was more than minor because it was associated with the Program/Process attribute of the Occupational Radiation Safety Cornerstone and potentially affected the cornerstone objective to ensure adequate protection of worker health and safety from exposure to radiation, in that the failure to implement controls for high radiation area entry may result in unplanned dose. The finding was determined to be of very low safety significance because the finding did not involve As-Low-As-Is-Reasonably-Achievable (ALARA) planning; it did not involve an overexposure; there was not a substantial potential for a worker overexposure; and the licensee=s ability to assess worker dose was not compromised. The cause of the finding is related to a cross-cutting aspect of human performance in work control (H.3(b)). (Section 2OS1)

Licensee-Identified Violations

Violations of very low safety significance that were identified by the licensee have been reviewed by the inspectors. Corrective actions planned or taken by the licensee have been entered into the 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 was operated at or near full power until January 27, 2008, when a gradual power coast down was initiated. The unit reached about 83 percent power prior to the generator being taken offline and the reactor being shut down for a refueling outage on February 12, 2008. The reactor was made critical on March 21, 2008, and the generator was placed online on March 23, 2008. Unit 1 power was gradually increased to allow for testing of a new digital turbine control system and other post-refueling outage testing. Unit 1 reached full power on March 28, 2008.

Unit 2 was operated at or near full power until March 28, 2008, when reactor power was lowered to perform routine turbine valve testing and waterbox cleaning. Unit 2 returned to full power on March 30, 2008, and remained there for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• 22 residual heat removal train;

• 11 turbine-driven auxiliary feedwater pump and 12 motor-driven auxiliary feedwater pump;

• 12 containment spray train; and

• D2 diesel generator.

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report (USAR), Technical Specification (TS)requirements, administrative TS, outstanding work orders (WOs), corrective action documents (CAPs), and the impact of ongoing work activities on redundant trains of equipment. These items were reviewed to identify conditions that could have rendered the selected systems incapable of performing their intended functions. The inspectors walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved any equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

These activities constituted four partial system walkdown samples as defined by Inspection Procedure 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 Area 7, Technical Support Center (TSC) and Work Control Center;

• Fire Area 3, 121 Control Room Chiller Room;

• Fire Area 92, 122 Control Room Chiller Room;

• Fire Area 90, Emergency Generator Building; and

• Fire Areas 31, 32 Auxiliary Feedwater Pump Rooms 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 had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features in accordance with the 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 plants ability to respond to a security event. Using the documents listed in the Attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed, that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.

These activities constituted five quarterly fire protection inspection samples as defined by Inspection Procedure 71111.05-05.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the Unit 1 component cooling heat exchangers to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees test results and compared the results against the acceptance criteria. The inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing criteria. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one sample as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection (ISI) Activities

From March 3, 2008, through March 7, 2008, the inspectors conducted a review of the implementation of the licensees ISI program for monitoring degradation of the reactor coolant system, steam generator tubes, emergency feedwater systems, risk significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, 1R08.3, IR08.4, and 1R08.5 below count as one inspection sample as defined by Inspection Procedure 71111.08-05.

Documents reviewed are listed in the Attachment to this report.

.1 Piping Systems ISI

a. Inspection Scope

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

• Ultrasonic Examination of the residual heat removal (RHR) heat exchanger pipe to elbow weld, W-11, Summary No. 302258-R1;

• Ultrasonic Examination of the safety injection pipe to elbow weld, W-4, Summary No. 300132-R1;

• Ultrasonic Examination of the safety injection pipe to 65 degree elbow weld, W-5, Summary No. 300601-R1;

• Magnetic Particle Examination of the reactor coolant system integral attachment weld, H-1/IA, Summary No. 321738; and

• Liquid Penetrant Examination of the residual heat removal heat exchanger integral attachment (Hanger Lugs) welds, H-9/IA, Summary No. 320182.

During the prior outage non-destructive surface and volumetric examinations, the licensee did not identify any relevant/recordable indications. Therefore, no NRC review was completed for this inspection procedure attribute.

The licensee had not performed pressure boundary welding since the beginning of the preceding outage for Unit 1. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings of significance were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the Unit 1 vessel head, no examination was required and the licensee did not conduct a bare metal visual or non-visual examination pursuant to NRC Order EA-03-009 during the current refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors performed an independent walkdown of portions of the system(s) that had received a recent licensee boric acid walkdown to determine if the licensees boric acid corrosion control visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components.

• The inspectors reviewed licensee evaluations of reactor coolant system components with boric acid deposits and verified that degraded components were documented in the corrective action system;

• The inspectors also evaluated corrective actions for any degraded reactor coolant system components to determine if they met the ASME Section XI Code, and 10 CFR Part 50, Appendix B, Criterion XVI; and

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

b. Findings

No findings of significance were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The NRC inspectors reviewed documentation related to the SG eddy current (ET)

ISI program to determine if:

• In-situ SG tube pressure testing screening criteria used were consistent with those identified in the Electric Power Research Institute (EPRI) TR-107620, SG In-Situ Pressure Test Guidelines, and that these criteria were properly applied to screen degraded SG tubes for in-situ pressure testing;

• The number and size of SG tube flaws/degradation identified was bound by the licensees previous outage Operational Assessment predictions;

• The SG tube ET examination scope and expansion criteria were sufficient to meet the TSs, and the EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• The SG tube ET examination scope included potential areas of tube degradation identified in prior outage SG tube inspections and/or as identified in NRC generic industry operating experience applicable to these SG tubes;

• The licensee identified new tube degradation mechanisms and implemented adequate extent of condition inspection scope and repairs for the new tube degradation mechanism;

• The licensee implemented repair methods that were consistent with the repair processes allowed in the plant TS requirements and to determine if qualified depth sizing methods were applied to degraded tubes accepted for continued service;

• The licensee implemented an inappropriate plug on detection tube repair threshold (e.g., no attempt at sizing of flaws to confirm tube integrity);

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

• The ET probes and equipment configurations used to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• The licensee performed secondary side SG inspections for location and removal of foreign materials; and

• The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

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

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

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

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

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the attachment to this report. In addition, the inspectors verified that the licensee correctly assessed operating experience for applicability to the ISI group.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On February 4, 2008, 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;

• 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 Inspection Procedure 71111.11.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• radiation monitoring system.

The inspectors reviewed events where ineffective equipment maintenance resulted in invalid automatic actuations of Engineered Safeguards Systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

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

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

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

• verifying appropriate performance criteria for structures, systems, and components/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 corrective action program 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 Inspection Procedure 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• emergent work on D2 diesel generator lube oil cooler due to leakage with concurrent unavailability of the 121 auxiliary building special ventilation system;

• performance of D2 diesel generator surveillance testing while D2 was considered protected; and

• emergent work on the 11 turbine-driven auxiliary feedwater pump and the 11 containment spray pump.

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

These activities constituted three samples as defined by Inspection Procedure 71111.13-05.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• bus 111/121 steam exclusion dampers (CD-34201/CD-34202) failed to fully close;

• multiple issues with Unit 2 charging pumps;

• Unit 2 auxiliary feedwater pumps flow questions;

• TSC ventilation damper issues;

• reactor vessel stress analysis;

• 122 auxiliary building special ventilation filter heater issues; and

• failure of Containment Spray Check Valve CS-16 during testing.

The inspectors selected these potential operability issues based on the risk-significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and USAR to the licensees evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors 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 inspection constituted seven samples as defined in Inspection Procedure 71111.15.-05

b. Findings

Technical Support Center Ventilation System Issues

Introduction:

The inspectors identified a Non-Cited Violation (NCV) of 10 CFR 50.47(b)(8) having a very low safety significance (Green) for failing to maintain adequate emergency facilities to support emergency response. Specifically, the licensee failed to maintain control of the TSC ventilation system. As a result, the system was frequently found to be in a degraded condition that may not have provided adequate protection for emergency response personnel from a release of airborne radioactivity.

Description:

On January 31, 2008, licensee operators identified that the normal outside air damper for the lower level of the TSC, MD-34602, was stuck partially open after they had switched the TSC ventilation system to the emergency mode in an attempt to control temperature. The shift manager concluded that the system remained operable with the damper stuck partially open because the TSC ventilation system is passing its required surveillances. The inspectors reviewed the results of Periodic Test Procedure (TP) 1689, TSC Ventilation System Operability Check, for the last seven years and determined that the semiannual test had failed on 9 of the 13 initial attempts. The test also failed on some second attempts after repairs and/or adjustments were made.

Lastly, the system had been found in a condition where the test would have failed on two occasions during operation in the emergency mode. Between November 2001 and February 2008, the inspectors identified a total of 11 test failures and 9 other times where the system was discovered to be in an improper configuration.

The inspectors reviewed corrective action documents, logs, and work orders for the system failures and determined that the majority of the failures were due to the inability of the system to maintain the specified 0.125 inches of water positive differential pressure between the TSC and turbine building atmosphere when in the emergency mode as described in Section 10.3.9.3 of the USAR. The causes were usually due to misalignment of various flow control dampers or failure of one of the two normal outside air dampers to close. For those occasions where a root cause was determined, the cause was usually that operators had repositioned dampers or disconnected damper control mechanisms in an attempt to maintain a comfortable environment in the Work Control Center (WCC) located on the bottom floor of the TSC.

The TSC was a two story structure within the turbine building. The upper floor was the TSC proper and the lower floor was an overflow area, which was used as the WCC during normal operation. The ventilation system consisted of separate upper and lower trains that, in the normal mode, draws in outside air through a large damper in each train, blows the air through an air handler for heating or cooling, and then recirculates the air through the structure and back to the air handlers through return ducts. When switched to the emergency mode, which was required during TSC activation, the normal outside air dampers would close, and a smaller outside air damper would modulate open to supply air through particulate and charcoal filters to the air handlers. In addition, some of the air in the return ducts would also be directed through the filters. The air handler fans remain on to recirculate the air.

The normal air handling unit heaters and coolers were frequently found to be incapable of providing enough heating during extremely cold weather or enough cooling during hot weather to maintain a comfortable temperature in the TSC/WCC. In those cases, operations personnel disconnected the operating rods from the normal outside air dampers to cause them to go closed to limit the introduction of outside air into the system. Other adjustments to the flow control dampers were sometimes made. There was no procedure that allowed these actions and the operators did not always use configuration control procedures to record and control the system configuration changes.

When the damper operators were reconnected, the work control process was not always followed and post maintenance testing was not performed.

When the inspectors concerns regarding past system functionality were brought to the licensees attention, licensee engineers concluded that the system had always been capable of performing its function because some positive pressure was available in the emergency mode, even if it did not meet the specified 0.125 inches. The inspectors determined that the licensee failed to understand the design of the system. Three functions were necessary to provide adequate protection; 1) positive pressure with regard to atmosphere to prevent the introduction of contaminated turbine building air, 2) isolation of unfiltered outside air to prevent the introduction of contaminated outside air, and 3) proper routing of the outside makeup and recirculated air through operable particulate and charcoal filters, at the design flow rates, to remove contamination. The licensee had focused its operability determination on only one portion of the design.

With the outside air dampers failing to properly close, the air handling fans would continue to draw in unfiltered outside air even with a positive system pressure. This was demonstrated on January 31, 2008, when WCC temperature remained too cold after operators switched the system to the emergency mode. The system continued to draw in cold outside air through the partially open MD-34602 even though the overall system was at a positive pressure with respect to atmosphere.

The licensee entered the inspectors concerns into its corrective action program, established interim measures for control of the system configuration, and took actions to improve normal temperature controls. As a result of the inspectors concerns, the licensee performed additional investigation, troubleshooting, and testing of the system and determined there were additional long-standing problems with the emergency filter flow control dampers, flow settings, and flow instrumentation. These issues were also considered NRC-identified because the licensee would not have conducted the investigations absent the inspectors concerns.

Analysis:

Due to the large number of test failures, improper configurations and flow issues, the inspectors concluded that the TSC ventilation system could not be reliably depended upon to adequately protect emergency response personnel from airborne contamination and maintain habitability from late 2001 to early 2008. The causes were inadequate understanding of the system design, inadequate system configuration control, and inadequate operating procedures. Each of the above was considered to be a performance deficiency.

The inspectors concluded that the finding did not have actual safety consequences because there was no accident that resulted in a radioactive release between 2001 and 2008. The finding did not affect the NRCs ability to perform its regulatory function and was not willful. The inspectors applied the Significance Determination Process (SDP) to the finding and determined it was associated with a failure to meet a regulatory requirement in the emergency preparedness cornerstone. The finding was more than minor because it was associated with the attribute of meeting the planning standards of 10 CFR 50.47(b) and affected the cornerstone objective of ensuring that the licensee was capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency.

In accordance with the SDP Phase 1 Screening Worksheet of Inspection Manual Chapter (IMC) 0609, the inspectors applied Appendix B, Emergency Preparedness Significance Determination Process, and determined that Section 4.8 applied. The TSC function was degraded for several periods of longer than seven days from the time the licensee first discovered the problems. The level of degradation was to the extent that key emergency response organization members may have had to employ compensatory measures or move to the pre-designated backup facility during an event involving a release of airborne contamination. Although not specifically discussed in Section 4.8 of the SDP, a finding involving a degraded planning standard was one color lower in significance than a finding involving a loss of the planning standard. Since loss of the TSC for more than seven days from the time of discovery would have been a White finding under Section 4.8, a degraded TSC was determined to be a Green finding. This was supported by the flow chart on Sheet 1 of Section 4.8 by answering yes to the planning standard problem decision point, no to the risk significant planning standard problem decision point, no to the planning standard functional failure decision point, and thus arriving at the Green result box.

This finding was related to the cross-cutting area of Problem Identification and Resolution associated with the aspect of the corrective action program. Specifically the licensee failed to thoroughly evaluate repeated problems with the TSC ventilation system such that the operability was evaluated against the design functions of the system and the causes of the problems were identified and addressed (P.1(c)).

Enforcement:

Part 50.54(q) of 10 CFR required that the licensee follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b). Part 50.47(b)(8)of 10 CFR required that adequate emergency facilities and equipment to support the emergency response be provided and maintained. Prairie Island Nuclear Generating Plant Emergency Plan, Revision 36, Section 7.1.1.B, required that the TSC have a shielding and ventilation cleanup system to provide habitability under accident conditions. Contrary to this, on several occasions between November 2001 and January 2008, the licensee failed to maintain an adequate TSC because the ventilation system was frequently found to be in a condition where it could not have adequately supported TSC habitability during an emergency. The licensee entered this issue into its corrective action system as CAPs 01137344 and 01128432 and took interim actions to maintain an acceptable configuration of the system. Because this violation was of very low safety significance and was entered into the licensees corrective action program, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy. (NCV 05000282/2008002-01; 05000306/2008002-01)

1R18 Plant Modifications

.1 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification:

• EC 11877; In-situ Testing of the Main Steam Safety Valves.

The inspectors compared the temporary configuration change and associated 10 CFR 50.59 screening and evaluation information 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 operated as expected; modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modification did not impact the operability of any interfacing systems. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one sample as defined in Inspection Procedure 71111.18.

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:

• 121 screenwash pump for qualification as a fire pump following rebuilding;

• 11 station battery discharge capacity test following replacement;

• Unit 1 containment vacuum breaker tests following maintenance;

• 11 turbine-driven auxiliary feedwater pump following outage 1R25;

• SI-26-1 RHR heat exchanger to reactor vessel loop A relief valve to pressurizer relief tank; and

• D5 diesel generator following maintenance.

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

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 the TS, 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 corrective action program 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 samples as defined in Inspection Procedure 71111.19.

b. Findings

No findings of significance were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan and contingency plans for the Unit 1 refueling outage, conducted February 13 through March 23, 2008, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below:

• Configuration management, including maintenance of defense-in-depth commensurate with the Outage Safety Plan key safety functions and compliance with the applicable TS;

• Implementation of clearance order activities including confirmation that tags were properly hung and equipment appropriately configured to safely support the associated outage activity;

• Installation and configuration of reactor coolant pressure, level, and temperature instruments;

• Configuration of electrical systems to ensure that TS requirements were met;

• Monitoring of decay heat removal processes;

• Implementation of reactor water inventory controls including the verification of flow paths, alternative means for inventory addition, and controls to prevent inventory loss;

• Implementation of reactivity controls;

• Maintenance of secondary containment TS requirements;

• Completion of refueling activities including fuel movement;

• Reactor startup and power ascension activities;

• Portions of reactor physics testing;

• Identification and resolution of problems related to refueling outage activities;

• Implementation of the licensees boric acid corrosion control program for equipment located in containment;

• Reactor head removal;

• Verification of the Unit 1 Cycle 25 core inventory; and

• Control of heavy loads including the movement of the 12 reactor coolant pump into containment.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings of significance were identified.

.2 Review of Operating Experience Smart Sample (OpESS) FY2007-03, Revision 1, Crane

and Heavy Lift Inspection, Supplemental Guidance for IP-71111.20

a. Inspection Scope

As part of the Unit 1 refueling outage, the inspectors performed a review of the licensees containment polar crane heavy lift procedures and processes using the guidance of OpESS FY2007-03. The inspectors reviewed the following aspects:

• Whether the containment polar crane was considered single-failure proof; it was not;

• Whether the licensee had a preventive maintenance program in place based on vendor recommendations and whether crane testing and inspection procedures were completed prior to use; they had preventative maintenance, testing, and inspection procedures that were implemented prior to crane use;

• Whether the reactor vessel head lift procedures conformed to an acceptable safety basis; they conformed with a valid load drop analysis, which the inspectors reviewed;

• Whether the licensees load drop analysis bounded their lifting procedures with regard to maximum lift height of the reactor vessel head over the reactor vessel; they do, the load drop analysis was for 27 feet over the vessel flange and the lifting procedure limited the height to 26.75 feet;

• Whether the load drop analysis had been updated to reflect any significant change in the weight of the heavy load to be lifted; the analysis was updated when new reactor heads were installed; and

• Whether the load drop analysis bounded the lifting procedure with regard to the medium through which the drop would occur; it does, the medium analyzed was air which was the actual medium used in the lifts.

In addition to documentation reviews, the inspectors observed the initial Unit 1 head removal lift as well as the final head reinstallation. The inspectors verified that the height limitations were maintained during the lifts. Documents reviewed are listed in the to this report.

This inspection was considered part of the refueling outage sample discussed in Section 1R20.1 of this report and did not constitute a separate sample.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

.1 Routine 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:

• train A safeguards logic test at power;

• D5 diesel generator 6-month fast start and monthly slow start test; and

• D2 diesel generator slow start test.

The inspectors observed in plant activities and reviewed procedures and associated records to determine whether: preconditioning occurred; effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis; plant equipment calibration was correct, accurate, and properly documented; as left setpoints were within required ranges; the calibration frequency was in accordance with TSs, the USAR, procedures, and applicable commitments; measuring and test equipment calibration was current; test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied; test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used; test data and results were accurate, complete, within limits, and valid; test equipment was removed after testing; where applicable, 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 corrective action program. Documents reviewed are listed in the Attachment to this report.

This inspection constituted three routine surveillance testing samples as defined in Inspection Procedure 71111.22.

b. Findings

No findings of significance were identified.

.2 In-service 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:

• 11 containment spray pump quarterly test, and

• 22 turbine-driven auxiliary feedwater pump test.

The inspectors observed in plant activities and reviewed procedures and associated records to determine whether: preconditioning occurred; effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; acceptance criteria were clearly stated, demonstrated operational readiness, and were 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 in-service 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 corrective action program.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two in-service inspection samples as defined in Inspection Procedure 71111.22.

b. Findings

No findings of significance were identified.

.3 Reactor Coolant System Leak Detection Inspection

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

• SI-9-5, Hi/Lo Head Safety Injection to 12 Reactor Vessel Check Valve.

The inspectors reviewed procedures and associated records to determine whether:

preconditioning occurred; effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis; 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, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable; 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 corrective action program. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one reactor coolant system leak detection inspection sample as defined in Inspection Procedure 71111.22.

b. Findings

Introduction:

One unresolved item was identified due to concerns regarding the past operability of Safety Injection Check Valve SI-9-5.

Description:

During surveillance testing on March 16, 2008, Safety Injection Check Valve SI-9-5 did not seat. The failure of the check valve to properly seat resulted in bypass flow greater than the 3 gallons per minute allowed by the TS. The licensee initiated CAP 01131266 to document the surveillance test failure. When open, Check Valve SI-9-5 provided a flow path for low head safety injection and long-term low head recirculation. This valve prevented over-pressurization of the residual heat removal system when in the closed position.

Flow testing of the check valve was performed in accordance with an operational surveillance procedure. This procedure required the installation of a jumper connected between two drain valves. Operations personnel manipulated the valves to create a drain path on the low pressure side of the check valve. The flow through this drain path was measured and then compared against the TS requirements.

Initial surveillance testing resulted in a flow measurement that exceeded the TS requirements. Licensee individuals proceeded to re-test the check valve seven additional times. Each time the measured flow rate exceeded the TS requirements.

After the seventh test failure, the licensee stopped the testing and developed a trouble shooting plan, which included raising reactor pressure above the pressure band specified in the test procedure and hitting the valve with a hammer. The licensee developed the plan based on the assumption that the check valve was unable to pass the surveillance test due to the inability to establish enough differential pressure across the valve to ensure the valve was closed.

Once approved, licensee personnel implemented the troubleshooting plan by raising reactor pressure, opening the drain path, tapping on the valve with a 1 pound hammer, and monitoring leakage for a few minutes. After tapping on the valve, leakage decreased to within the surveillance and TS requirements. Operations personnel then lowered reactor pressure within the pressure band specified in the surveillance procedure. Licensee personnel observed that the check valve leakage remained within the specified requirements. Following these actions, the licensee re-performed the surveillance test and documented that there was zero leakage past the check valve.

Operations personnel then concluded that the valve was operable based on the test methodology implemented and results achieved.

The inspectors reviewed SI-9-5s maintenance history. The inspectors determined that the licensee had trouble getting SI-9-5 to pass the same surveillance test discussed above during the 2006 Unit 1 refueling outage. The licensee documented this in CAP 01033504. After several additional surveillance test attempts, the licensee again tapped on the valve body with a hammer to get the valve to seat. Following this action, SI-9-5 passed the surveillance test. Corrective actions for CAP 01033504 included developing an improved test procedure to resolve the previous test difficulties; however this task was not completed. The licensee also added a task to open and inspect SI-9-5 during the February 2008 Unit 1 refueling. The inspectors discussed this action with licensee personnel and determined that the licensee had originally planned to open and inspect Check Valve SI-9-5 during the February 2008 Unit 1 refueling outage. However, the licensee subsequently eliminated the check valve inspection from the outage scope to improve resource utilization and reduce overall outage duration.

Following the check valve testing, the NRC monitored the licensees re-start activities.

During this time the NRC expressed several concerns to licensee management relating to the testing of Check Valve SI-9-5. These concerns included:

• Potential preconditioning due to increasing reactor pressure and tapping on the valve prior to the valve passing the surveillance test. The NRC believed that the licensees actions were preconditioning because increasing reactor pressure and hitting the valve with a hammer were not actions that were considered to be permanent maintenance. In addition, these actions failed to provide reasonable assurance that the check valve would remain closed if the valve was disturbed or the differential pressure conditions changed during the next operating cycle;

• Use of a hammer on safety-related equipment was unacceptable;

• Failure to implement corrective actions to resolve previous testing difficulties following the 2006 Unit 1 refueling outage;

• Removal of the valve inspection from the outage scope;

• The failure to recognize the need for an operability determination once the inspectors concerns were known;

• Technical inadequacies in the licensees subsequent operability determination; and

• The need to implement additional compensatory measures/corrective actions to ensure that SI-9-5 was re-tested if the valve was disturbed or the differential pressure conditions changed during the next operating cycle.

At the conclusion of the inspection period, the licensee had initiated three CAPs to document the information discussed above (01132288, 01131266, and 01033504).

Based upon the information known to date, it appears that several weaknesses in licensee performance contributed to the difficulties experienced when testing SI-9-5.

The licensee was continuing to evaluate the inspectors concerns and provide plant specific probabilistic risk assessment and historical testing information to the NRC at the conclusion of the inspection period. As a result, the inspectors were unable to fully evaluate this issue for potential performance deficiencies and safety significance. This issue will be tracked as an unresolved item (URI) pending the receipt and review of the probabilistic risk assessment and testing information discussed above.

(URI 05000282/2008002-02)

.4 Containment Isolation Valve Testing

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

• Volumetric leakage rate test of the Unit 1 containment personnel airlock.

The inspectors observed in-plant activities and reviewed procedures and associated records to determine whether: preconditioning occurred; effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; acceptance criteria were clearly stated, demonstrated operational readiness, and were 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, 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 corrective action program. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one containment isolation valve inspection sample as defined in Inspection Procedure 71111.22.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspectors reviewed a sample of EP items and corrective actions related to the facilitys EP program and activities to determine whether corrective actions were completed in accordance with the sites corrective action program.

This inspection does not constitute a sample as defined in Inspection Procedure 71114.05-05.

b. Findings

A find related to corrective actions for the TSC is described in Section 1R15 of this report.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine emergency drill on January 22, 2008, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Simulated Control Room, Technical Support Center, and Emergency Operating Facility to verify that event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensees critique to compare any inspector-observed weakness with those identified by the licensee staff in order to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program.

This inspection constituted one sample as defined in Inspection Procedure 71114.06-05.

b. Findings

No findings of significance were identified.

.2 Training Observation

a. Inspection Scope

The inspectors observed a simulator training evolution on February 4, 2008, which required emergency plan implementation by an operations crew. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the corrective action program.

This inspection constituted one sample as defined in Inspection Procedure 71114.06-05.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Review of Licensee Performance Indicators for the Occupational Exposure Cornerstone

a. Inspection Scope

The inspectors reviewed the licensees occupational exposure control cornerstone performance indicators (PIs) to determine whether the conditions resulting in any PI occurrences had been evaluated and identified problems had been entered into the corrective action program for resolution. Documents reviewed are listed in the to this report.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

b. Findings

No findings of significance were identified.

.2 Plant Walkdowns and Radiation Work Permit Reviews (RWP)

a. Inspection Scope

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

• Containment radiation areas, HRAs, locked HRAs and very HRAs;

• C- Sump Very HRA Lock Change Out;

• Reactor Head Set (placement from the stand to the reactor vessel) and cavity decontamination;

• Regenerative Heat Exchangers Room;

• Hydrogen Monitoring System Calibration;

• Sandbox Cover and Gasket Material Removal; and

• Steam Generator No. 11 Hot Leg Nozzle Dam Removal.

This inspection constituted one sample as defined by Inspection Procedure 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 constituted one sample as defined by Inspection Procedure 71121.01-5.

The inspectors reviewed the RWPs and work packages used to access these areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm set points for both integrated dose and dose-rate were evaluated for conformity with survey indications and plant policy. Workers were interviewed to verify that they were aware of the actions required when their electronic dosimeters noticeably malfunctioned or alarmed.

This inspection constituted one sample as defined by Inspection Procedure 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 exposures of >50 millirem committed effective dose equivalent:

• Reactor Head Set (placement from the stand to the reactor vessel) and cavity decontamination;

• Sandbox Cover and Gasket Material Removal; and

• Steam Generator No. 11 Hot Leg Nozzle Dam Removal.

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 provided appropriate worker protection.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

Documents reviewed are listed in the Attachment to this report.

Findings

Introduction:

A self-revealing finding of very low safety significance (Green) and associated NCV were identified for the failure to comply with TS 5.7.1.b for access control to HRAs of the plant. As a result of poor human performance, a contract radiation worker received an electronic dosimeter (ED) high dose-rate alarm while performing steam generator set-up activities when he inappropriately entered a HRA of the plant on a non-high radiation area RWP.

Description:

On February 19, 2008, a group of workers associated with the steam generator set-up work entered the Unit 1 containment. Some of the workers were on a HRA RWP, and two of the workers were on a non-HRA RWP. The work crew of two individuals assigned to work in the low dose area was comprised of one experience worker and one inexperienced worker. After completing their job assignment, the experienced worker told the inexperienced worker to go help the remaining crew members that were performing steam generator set-up activities inside the HRAs. The experienced worker then left the containment. Without contacting radiation protection and while remaining on the non-HRA RWP, the inexperienced worker inappropriately entered the HRAs to assist the other group of steam generator set-up workers. The worker failed to recognize that the RWP he was assigned did not allow access into the HRA. Upon exit the inexperience worker alarmed his ED on high dose-rate conditions.

The worker did not receive any appreciable dose from the HRA entry.

Analysis:

The inspectors determined that the licensees failure to adequately implement HRA controls defined in TS 5.7.1.b constituted a performance deficiency and a finding, as described in IMC 0612, Appendix B, Issue Screening. The issue was more than minor because it was associated with the Program/Process attribute of the Occupational Radiation Safety Cornerstone and potentially affected the cornerstone objective to ensure worker health and safety from exposure to radiation, in that the individuals entry into the HRA could have resolved in an unplanned exposure. The finding does not involve the application of traditional enforcement, because it did not result in actual safety consequences or the potential to impact the NRCs regulatory function, and was not the result of willful actions. The finding was evaluated using the SDP in accordance with IMC 0609 Appendix C for the Occupational Radiation Safety Cornerstone. The finding was determined to be of very low safety significance because the finding did not involve As-Low-As-Is-Reasonably-Achievable (ALARA) planning; it did not involve an overexposure; there was not a substantial potential for a worker overexposure; and the licensees ability to assess worker dose was not compromised.

The inspectors determined that there was a cross-cutting aspect associated with this finding in the area of human performance in work control. The inspectors concluded that a substantial cause of this finding was the failure to appropriately coordinate work activities by incorporating actions to address the impact of changes to the work activities on human performance. Specifically in this case, the inexperienced worker was reassigned work in the field without addressing the impact on established radiological controls (H.3.b). Licensee corrective actions for this issue included counseling the individuals involved and reinforcing expectations for HRA access control with the plant staff.

Enforcement:

Station TS 5.7.1.b required, in part, that access to and activities in each HRA shall be controlled by means of a RWP or equivalent that includes specification of radiation dose-rates in the immediate work area(s) and other appropriate radiation protection equipment and measures. Contrary to the above, on February 19, 2008, a worker on a non-HRA RWP entered a HRA to support steam generator set-up work activities. Since the finding is of very low safety significance and had been entered into the corrective action system as CAP Report (AR 01128001), the associated violation is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2008002-03; 05000306/2008002-03).

.3 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed a sample of the licensees self-assessments, audits, Licensee Event Reports, and Special Reports related to the access control program to verify that identified problems were entered into the corrective action program for resolution.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

The inspectors reviewed corrective action reports related to access controls and HRA radiological incidents (non-Performance Indicator incidents identified by the licensee in HRA <1R/hr). Staff members were interviewed and corrective action documents were reviewed to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:

• 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 corrective action system; and

• Implementation/consideration of risk significant operational experience feedback.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

The inspectors evaluated the licensees process for problem identification, characterization, prioritization, and assessed whether problems that were entered into the corrective action program and resolved. For repetitive deficiencies and/or significant individual deficiencies in problem identification and resolution, the inspectors verified that the licensees self-assessment activities were capable of identifying and addressing these deficiencies.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.4 Job-In-Progress Reviews

a. Inspection Scope

The inspectors observed the following jobs that were being performed in radiation areas, airborne radioactivity areas, or HRAs for observation of work activities that presented the greatest radiological risk to workers:

• C- Sump Very HRA Lock Change Out;

• Reactor Head Set (placement from the stand to the reactor vessel) and cavity decontamination;

• Hydrogen Monitoring System Calibration;

• Sandbox Cover and Gasket Material Removal; and

• Steam Generator No. 11 Hot Leg Nozzle Dam Removal.

The inspectors reviewed radiological job requirements for these activities, including RWP requirements and work procedure requirements, and attended the ALARA pre-job briefing for the reactor head set (placement from the stand to the reactor vessel) and cavity decontamination.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

Job performance was observed with respect to these requirements to assess whether radiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors also 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 constitutes one sample as defined by Inspection Procedure 71121.01-5.

Radiological work in high radiation work areas having significant dose rate gradients was reviewed to evaluate the application of dosimetry to effectively monitor exposure to personnel and to assess the adequacy of licensee controls.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.5 High Risk Significant, High Dose Rate High Radiation Area and Very High Radiation

Area Controls

a. Inspection Scope

The inspectors held discussions with the Radiation Protection Manager concerning high dose rate/high radiation area and very high radiation area controls and procedures, including procedural changes that had occurred since the last inspection in order to assess whether any procedure modifications substantially reduced the effectiveness and level of worker protection.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

The inspectors discussed with radiation protection supervisors the controls that were in place for special areas that had the potential to become very high radiation areas during certain plant operations to determine if these plant operations required communication beforehand with the radiation protection group, so as to allow corresponding timely actions to properly post and control the radiation hazards.

This inspection constitutes one sample as defined by Inspection Procedure 71121.01-5.

The inspectors conducted plant walkdowns to assess the posting and locking of entrances to high dose rate HRAs and very high radiation areas.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified

.6 Radiation Worker Performance

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation protection work requirements and evaluated whether workers were aware of the significant radiological conditions in their workplace, the RWP controls and limits in place, and that their performance had accounted for the level of radiological hazards present.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

The inspectors reviewed radiological problem reports for which the cause of the event was due to radiation worker errors to determine if there was an observable pattern traceable to a similar cause and to determine if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. Problems or issues with planned and completed corrective actions were discussed with the Radiation Protection Manager.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.7 Radiation Protection Technician (RPT) Proficiency

a. Inspection Scope

During job performance observations, the inspectors evaluated RPT performance with respect to radiation protection work requirements and evaluated whether RPTs 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 constituted one sample as defined by Inspection Procedure 71121.01-5.

The inspectors reviewed radiological problem reports for which the cause of the event was RPT error to determine if there was an observable pattern traceable to a similar cause and to determine if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

This inspection constituted one sample as defined by Inspection Procedure 71121.01-5.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

2OS2 As-Low-As-Reasonably-Achievable (ALARA) Planning And Controls (71121.02)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed plant collective exposure history, current exposure trends, and ongoing and planned activities in order to assess current performance and exposure challenges. This included determining the plants current three-year rolling average for collective exposure in order to help establish resource allocations and to provide a perspective of significance for any resulting inspection finding assessment.

This inspection constituted one required sample as defined by Inspection Procedure 71121.02-5.

The inspectors reviewed the outage work scheduled during the inspection period and associated work activity exposure estimates for the following work activities that were likely to result in the highest personnel collective exposures:

• C-Sump Very HRA Lock Change Out;

• Reactor Head Set (placement from the stand to the reactor vessel) and cavity decontamination;

• Hydrogen Monitoring System Calibration;

• Sandbox Cover and Gasket Material Removal; and

• Steam Generator No. 11 Hot Leg Nozzle Dam Removal.

This inspection constituted one required sample as defined by Inspection Procedure 71121.02-5.

The inspectors reviewed documents to determine if there were site specific trends in collective exposures and source-term measurements.

This inspection constituted one required sample as defined by Inspection Procedure 71121.02-5.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.2 Job Site Inspections and ALARA Control

a. Inspection Scope

The inspectors observed the following five jobs that were being performed in radiation areas, airborne radioactivity areas, or HRAs for observation of work activities that presented the greatest radiological risk to workers:

• C-Sump Very HRA Lock Change Out;

• Reactor Head Set (placement from the stand to the reactor vessel) and cavity decontamination;

• Hydrogen Monitoring System Calibration;

• Sandbox Cover and Gasket Material Removal; and

• Steam Generator No. 11 Hot Leg Nozzle Dam Removal.

The licensees use of ALARA controls for these work activities was evaluated.

Specifically, the licensees use of engineering controls to achieve dose reductions was evaluated to verify that procedures and controls were consistent with the licensees ALARA reviews and that sufficient shielding of radiation sources was provided for and that the dose expended to install/remove the shielding did not exceed the dose reduction benefits afforded by the shielding.

This inspection constituted one required sample as defined by Inspection Procedure 71121.02-5.

Job sites were observed to determine if workers were utilizing the low dose waiting areas and were effective in maintaining their doses ALARA by moving to the low dose waiting area when subjected to temporary work delays.

This inspection constituted one optional sample as defined by Inspection Procedure 71121.02-5.

The inspectors attended work briefings and observed ongoing work activities to determine if workers received appropriate on-the-job supervision to ensure the ALARA requirements are met. This included verification that the first-line job supervisor ensured that the work activity was conducted in a dose efficient manner by minimizing work crew size and by ensuring that workers were properly trained and that proper tools and equipment were available when the job started.

This inspection constituted one optional sample as defined by Inspection Procedure 71121.02-5.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

.3 Radiation Worker Performance

a. Inspection Scope

Radiation worker and RPT performance was observed during work activities being performed in radiation areas, airborne radioactivity areas, and HRAs that presented the greatest radiological risk to workers. The inspectors evaluated whether workers demonstrated the ALARA philosophy in practice by being familiar with the work activity scope and tools to be used, by utilizing ALARA low dose waiting areas, and by complying with work activity controls. Also, radiation worker training and skill levels were reviewed to determine if they were sufficient relative to the radiological hazards and the work involved. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one required sample as defined by Inspection Procedure 71121.02-5.

b. Findings

No findings of significance were identified.

.4 Problem Identification and Resolutions

a. Inspection Scope

The inspectors reviewed the licensees self-assessments, audits, and Special Reports related to the ALARA program since the last inspection to determine if the licensees overall audit programs scope and frequency for all applicable areas under the Occupational Cornerstone met the requirements of 10 CFR 20.1101(c).

This inspection constituted one required sample as defined by Inspection Procedure 71121.02-5.

The inspectors verified that identified problems were entered into the corrective action program for resolution and that they had been properly characterized, prioritized, and resolved. This verification included dose significant post-job (work activity) reviews and post-outage ALARA report critiques of exposure performance.

This inspection constituted one optional sample as defined by Inspection Procedure 71121.02-5.

Corrective action reports related to the ALARA program were reviewed and staff members were interviewed to verify that follow-up activities had been conducted in an effective and timely manner commensurate with their importance to safety and risk using the following criteria:

• 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 NCV tracked in the corrective action system; and

• Implementation/consideration of risk significant operational experience feedback.

This inspection constituted one optional sample as defined by Inspection Procedure 71121.02-5.

The licensees corrective action program was also reviewed to determine if repetitive deficiencies and/or significant individual deficiencies in problem identification and resolution had been addressed.

This inspection constituted one required sample as defined by Inspection Procedure 71121.02-5.

Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the fourth quarter 2007 performance indicators for any obvious inconsistencies prior to its public release in accordance with IMC 0608, Performance Indicator Program.

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings of significance were identified.

.2 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours performance indicator for Units 1 and 2 for the period from the first quarter 2007 through the fourth quarter 2007. To determine the accuracy of the performance indicator (PI) data reported during those periods, PI definitions and guidance contained in Revision 5 of the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of January 1 through December 31, 2007, to validate the accuracy of the submittals. 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.

This inspection constituted two unplanned scrams per 7000 critical hours samples as defined by Inspection Procedure 71151.

b. Findings

No findings of significance were identified.

.3 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications performance indicator for Units 1 and 2 for the period from the first quarter 2007 through the fourth quarter 2007. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in Revision 5 of NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of January 1 through December 31, 2007, to validate the accuracy of the submittals. 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.

This inspection constituted two unplanned scrams with complications samples as defined by Inspection Procedure 71151.

b. Findings

No findings of significance were identified.

.4 Unplanned Power Changes per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Power Changes Transients per 7000 Critical Hours performance indicator for Units 1 and 2 for the period from the first quarter 2007 through the fourth quarter 2007. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in Revision 5 of NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports and NRC Integrated Inspection reports for the period of January 1 through December 31, 2007, to validate the accuracy of the submittals. 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. Specific documents reviewed are described in the Appendix to this report.

This inspection constituted two unplanned power changes per 7000 critical hours samples as defined by Inspection Procedure 71151.

b. Findings

No findings of significance were identified.

4OA2 Problem Identification and Resolution

1. Routine Quarterly Review

a. Inspection Scope

As 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 corrective action program at an appropriate threshold, that adequate attention was given to timely corrective actions, and that adverse trends were identified and addressed. In addition, the inspectors performed a daily screening of items entered into the licensees corrective action program as a means of identifying repetitive equipment issues or human performance issues which required follow-up inspection.

This inspection was not counted as an inspection sample due to its routine nature.

b. Findings

No findings of significance were identified.

.2 Identification and Resolution of Unit 1 Charging Pump Issue

a. Inspection Scope

On March 3, 2008, operations personnel identified that the 13 Charging Pump had been operated without establishing a discharge flow path. The licensee initiated CAP 01129612 to document this issue. The inspectors reviewed the CAP and found that the licensee had not documented the cause of this issue. The inspectors were concerned that human performance weaknesses may have caused or contributed to this issue. The inspectors were also concerned that the licensees lack of a documented cause could be indicative of a weak corrective action investigation process. Based upon this information, the inspectors selected this item for additional review.

b. Issues The inspectors reviewed CAP 01129612 to verify that the licensees identification of the problem was complete, accurate, and timely, and that the extent of condition, generic implications, common cause, and previous occurrences were considered. The inspectors determined that the licensee conducted a timely and accurate human performance event investigation. The investigation resulted in identifying the following human performance issues:

• the 13 Charging Pump was operated without a discharge flow path due to an error in executing the removal of a clearance order four days earlier. This error resulted in the failure to reposition Valve RC-1-18, Loop Isolation for Charging, although the clearance order tag was removed;

• the operator tasked with executing the clearance order was also tasked with three other jobs to perform; and

• the operator tasked with performing the independent verification of the clearance order removal failed to identify that Valve RC-1-18 had not been repositioned as required by the clearance order checklist.

Although the licensee identified several clearance order execution issues, the inspectors found no information regarding whether the clearance order process was inappropriately implemented. The inspectors reviewed Procedure FP-OP-TAG-01, Fleet Tagging, to determine the licensees clearance order process requirements. The inspectors also discussed the implementation of Procedure FP-OP-TAG-01 with operations management. Through these discussions the inspectors learned that both the operator and the independent verifier used the clearance order checklist when they entered containment to execute the clearance order. Because the containment was a contaminated area, operations personnel were expected to execute the clearance order, ensure all steps had been completed and independently verified as required, sign that the clearance order steps were completed in Passport, and then throw the original clearance order checklist and tags in the trash. Step 5.8.7 of Procedure FP-OP-TAG-01 required that authorized operations department personnel ensure that all steps of a final clear checklist were completed. In addition, the same step required that this individual verify that all clearance order tags were removed. The inspectors questioned operations management to determine how Step 5.8.7 of Procedure FP-OP-TAG-01 was being implemented if the clearance order checklists and tags were being placed in the trash.

The licensee stated that this step was currently being accomplished by reviewing the electronic checklist contained within the Passport system. The inspectors considered this to be a potential error trap since it did not allow for a physical accounting of the clearance order tags. Based upon discussions with the inspectors, the licensee decided to include this issue as part of their ongoing tagging common cause investigation.

The licensee also conducted an extent of condition review as part of the human performance event investigation. The inspectors assessed the extent of condition review results and concluded that the review was narrowly focused. Specifically, the review only considered other operations department independent verification issues that had occurred during the recent Unit 1 refueling outage rather than considering the performance of all departments involved in the clearance order process.

Although the inspectors identified weaknesses in the licensees clearance order process, the inspectors determined no violation of NRC requirements occurred because the clearance order procedural requirements were met. Furthermore, the 13 charging pump is not safety-related, therefore, the failure of this pump is within the design basis of the plant.

The corrective actions for this event consisted of coaching the operators involved and conducting an operations department stand down. While these initial actions appeared appropriate, additional corrective actions to address the discrepancies between the licensees current performance and the requirements of Procedure FP-OP-TAG-01 may be required once the common cause investigation is completed.

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

.1 (Closed) Licensee Event Report (LER) 05000282/2007-003-01; 05000306/2007-003-01:

Unanalyzed Condition Due to Breached Fire Barrier This issue was initially discussed in Inspection Report 05000282/2007004; 05000306/2007004, Section 4OA7.1, and was dispositioned as a licensee-identified finding of very low safety significance (Green) and an NCV. This LER was a supplement to the original LER, which was discussed and closed in Inspection Report 05000282/2007005; 05000306/2007005, Section 4OA3.2. This supplement added information regarding the licensees root cause determination and associated corrective actions. The inspectors had no new concerns with this issue. This LER is closed. This review represented one sample. Documents reviewed are listed in the Attachment to this report.

.2 (Closed) LER 05000282/2007-004-00: Technical Specification Required Shutdown Due

to Both Emergency Diesel Generators Being Inoperable This event was previously discussed in Inspection Report 05000282/2007004; 05000306/2007004, Sections 1R20 and 4OA4.4, where no findings of significance were identified. The NRC reviewed the event risk in accordance with Management Directive 8.3, NRC Incident Investigation Program, and determined that the conditional core damage probability did not warrant additional inspection. The inspectors reviewed the LER and had no additional concerns with the event. The licensee was performing a root cause evaluation for the associated load sequencer failure that they intended to report on in a supplement to the LER. This LER is closed. This review represented one sample. Documents reviewed are listed in the Attachment to this report.

.3 (Closed) LER 05000282/2007-005-00; 05000306/2007-005-00: One Train of

Safeguards Chilled Water System Inoperable Longer than Allowed by TSs The LER describes an event on December 12, 2007, where the 121 control room chiller was declared inoperable due to a very small pressure boundary leak on a flexible spool piece. The leakage was first identified on October 1, 2007. However, the licensee believed the leak was from a mechanical flange and thus would not have affected operability. After the licensee removed the insulation on December 11, they identified that the leak was from an ASME Code Class III boundary. The chiller was declared inoperable after a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> engineering review of the condition. Licensee corrective actions consisted of replacing the leaking spool piece on December 15, 2007. The licensee entered the issue into its corrective action program as CAP 01120914 and was performing a root cause evaluation that they intended to report on in a supplement to the LER. The enforcement aspects of this issue are discussed in Section 4OA7 of this report. This LER is closed. This review represented one sample. Documents reviewed are listed in the Attachment to this report.

4OA5 Other Activities

.1 Reactor Coolant System Dissimilar Metal Butt Welds (TI 2515/172, Revision 0)

a. Inspection Scope

The inspectors conducted a review of the licensees activities regarding licensee dissimilar metal butt weld (DMBW) mitigation and inspection implemented in accordance with the industry self-imposed mandatory requirements of Materials Reliability Program (MRP)-139, Primary System Piping Butt Weld Inspection and Evaluation Guidelines.

Temporary Instruction (TI) 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds was issued February 21, 2008, to support the evaluation of the licensees implementation of MRP -139. This review was conducted for both Units 1 and 2 unless otherwise noted.

From March 3, 2008, through March 7, 2008, the inspectors performed a review in accordance with TI-172 which included the following:

(1) Licensees Implementation of the MRP-139 Baseline Inspections The inspectors verified that the licensees inspection program included inspections of the pressurizer, hot let and cold leg temperature DMBWs, and that the schedules for these baseline inspections are consistent with the requirements stated in MRP-139. If any baseline inspection schedules deviated from MRP-139 guidelines, the inspectors also determined what deviations were planned and what was the general basis for the deviation.

The inspectors verified that the licensee had completed MRP-139 baseline inspections of all pressurizer DMBWs by December 31, 2007.

(2) Volumetric Examinations The inspectors reviewed the volumetric examination of the Unit 2 pressurizer surge line safe end to nozzle weld baseline inspection completed in 2006 and verified the examination was performed in accordance with the guidelines in MRP-139, Section 5.1.

The inspectors verified that this examination was performed by qualified personnel and that any deficiencies identified were appropriately dispositioned and resolved. Unit 1 did not have any welds pertinent to MRP-139, so inspection of volumetric examinations for such welds was not applicable.

No weld overlays pertinent to MRP-139 were performed during the current or previous outages. Hence, NRC inspection of weld overlay volumetric examinations was not applicable. (Note that the licensee plans a weld overlay on Unit 2 during the Fall 2008 refueling outage and hence the TI remains open on that unit pending NRC inspection of that activity.)

(3) Weld Overlays No weld overlays pertinent to MRP-139 have been performed on either unit as of this inspection. Hence, NRC inspection of weld overlays was not applicable. (Note that the licensee plans a weld overlay on Unit 2 during the Fall 2008 refueling outage and hence the TI remains open on that unit pending NRC inspection of that activity.)

(4) Mechanical Stress Improvement There were no mechanical stress improvement activities performed or planned by the licensee to comply with their MRP-139 commitments. Hence, NRC inspection of such mechanical stress improvements was not applicable.

(5) Inservice Inspection Program The inspectors verified that the licensees MRP-139 inservice inspection program includes the applicable welds and that the welds are included in categories consistent with MRP-139 guidelines. The inspectors verified that the licensees inspection program and procedures specified inspection frequencies consistent with Tables 6-1 and 6-2 of MRP-139. The inspectors also determined if any welds are categorized as H or I, and for those welds reviewed the licensees basis for the categorization and the licensees plans for addressing potential post weld stress corrosion cracking. The inspector also determined if any deviations were planned from the inspection guidelines of MRP-139.

b. Observations Summary: Prairie Island Unit 1 is a Westinghouse two loop design plant and was verified during the inspection to contain no susceptible welds as described in MRP-139 (i.e., no Alloy 600/82/182 butt welds). Prairie Island Unit 2 is also a Westinghouse two loop design and was verified to contain one susceptible weld (pressurizer surge line nozzle weld). This weld received a Performance Demonstration Initiative (PDI)qualified ultrasonic baseline examination of approximately 94 percent of the required volume in November of 2006. The licensee has submitted a 10 CFR 50.55a, Request for Relief to NRC, (June 2007) and planned to mitigate this weld with weld overlay during the Fall 2008 refuel outage. The licensee has complied with the MRP-139 categorization of welds and baseline inspection requirements. No deviations from MRP-139 requirements have been taken or are planned for Unit 1 or Unit 2. This TI is considered complete for Unit 1 since no susceptible welds have been identified and the licensee's risk based ISI program includes primary system welds. Completion of the TI for Unit 2 is pending NRC inspection of the weld overlay planned for the Fall 2008 refueling outage.

In accordance with requirements of TI 2515/172, Revision 0, the inspectors evaluated and answered the following questions:

(1) Licensees Implementation of the MRP-139 Baseline Inspections 1a. Have the baseline inspection been performed or are they scheduled to be performed in accordance with MRP-139 guidance?

Yes. For Unit 1, no susceptible welds have been identified and primary system welds are included in the licensee's risk based ISI program. For Unit 2, the pressurizer surge line safe end to nozzle weld baseline inspection was performed in November of 2006 in accordance with MRP-139 guidance.

1b. Is the licensee planning to take any deviations from the MRP-139 baseline inspection requirements of MRP-139? If so, what deviations are planned, what is the general basis for the deviation, and was the NEI-03-08 process for filing a deviation followed?

No. Deviations have not been taken and are not planned to be taken for either unit.

(2) Volumetric Examinations 2a. Performed in accordance with the examination guidelines in MRP-139, Section 5.1, for unmitigated welds or mechanical stress improvement welds and consistent with NRC staff relief request authorization for weld overlaid welds?

Yes. Documentation of the Unit 2 pressurizer surge line safe end to nozzle weld baseline inspection completed in 2006 was reviewed. The examination was performed using PDI qualified procedures and personnel. Approximately 94 percent (averaged) of the required weld/base metal volume was documented as examined.

2b. Performed by qualified personnel? (Briefly describe the personnel training/qualification process used by the licensee for this activity.)

Yes. The ultrasonic examiners were qualified to the applicable PDI requirements 2c. Performed such that deficiencies were identified, dispositioned, and resolved?

Yes. No deficiencies were identified.

(3) Weld Overlays No weld overlays have been performed as of this inspection. The licensee has submitted a relief request and planned to apply a weld overlay of the Unit 2 pressurizer surge line nozzle to safe end weld.

(4) Mechanical Stress Improvement There were no stress improvement activities performed or planned by this licensee to comply with their MRP-139 commitments.

(5) Inservice Inspection Program 1. Has the licensee prepared an MRP-139 inservice inspection program? If not, briefly summarize the licensees basis for not having a documented program and when the licensee plans to complete preparation of the program.

The licensee=s Risk Informed ISI programs for both units contain all the DMBW=s.

They are not uniquely identified as welds within the scope of MRP-139. As of this inspection, only the Unit 2 pressurizer surge line nozzle to safe end weld is considered to be within the scope of MRP-139. This weld is planned to be overlayed during the Fall 2008 outage. There are no additional plans to develop a separate MRP-139 program.

2. In the MRP-139 inservice inspection program, are the welds appropriately categorized in accordance with MRP-139? If any welds are not appropriately categorized, briefly explain the discrepancies.

The only weld considered to be within the scope of MRP-139 (see above) was verified to be properly categorized 3. In the MRP-139 inservice inspection program, are the inservice inspection frequencies, which may differ between the first and second intervals after the MRP-139 baseline inspection, consistent with the inservice inspections frequencies called for by MRP-139?

The inspection frequency for the single weld included within the scope of MRP-139 has not been identified as of this inspection as the licensee plans to apply an overlay in Fall 2008. The licensee did not indicate any plans to deviate from the frequencies specified in MRP-139.

4. If any welds are categorized as H or I, briefly explain the licensees basis of the categorization and the licensees plans for addressing potential post weld stress corrosion cracking.

Although there are no MRP-139 categories assigned, the inspectors verified there are no welds that would be categorized as H or I on either unit.

5. If the licensee is planning to take deviations from the inservice inspection requirements of MRP-139, what are the deviations and what are the general bases for the deviations? Was the NEI 03-08 process for filing deviations followed?

No MRP-139 deviations were taken or are planned by the licensee for either unit.

c. Findings

No findings of significance were identified.

.2 (Closed) URI 05000306/2007005-02: Potential Inadequate Corrective Actions to

Prevent Unnecessary D5 Diesel Generator Unavailability A URI was documented in Inspection Report 05000282/2007005; 05000306/2007005, Section 1R15, concerning the unavailability of the D5 diesel generator due to the need to investigate and repair a problem with high crankcase pressure. The inspectors reviewed root cause evaluations (RCEs) for both the equipment technical issues and the organizational issues which contributed to the problem.

On October 22, 2007, about 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> into a 24-hour test of the D5 diesel generator, crankcase pressure rose to 40-50 millimeters of water pressure. In accordance with the surveillance procedure, D5 was declared inoperable, the engine was shut down for investigation, and CAP 0115585 was initiated to enter the issue into the corrective action program. The licensees investigation determined that 1 cylinder of engine #2 met its requirements for replacement due to full length polishing. However, a total of 5 cylinder pairs (10 cylinders) were replaced as a precautionary measure. Following the repairs and post maintenance testing, D5 was declared operable on November 3, 2007.

Although D5 was out of service for less than the 14 days allowed by TSs, it incurred about 232 hours0.00269 days <br />0.0644 hours <br />3.835979e-4 weeks <br />8.8276e-5 months <br /> of unavailability due to this event.

The D5 and D6 diesel generators have had a history of problems with crankcase pressure caused by damage to cylinder liners. The engines, installed in 1993, had no problems until D6 experienced high crankcase pressure in May 2001. The problem was attributed to incompatibility of the lubricating oil with the fuel oil because the sulfur content of the fuel oil had slowly been reduced due to changing regulations and supplier availability. Corrective actions included changing the lubricating oil on both diesels to one that was more compatible with the lower sulfur fuel. In April 2005, D5 experienced high crankcase pressure. The cause was attributed to residual carbon deposits from the previous lubricating oil. A corrective action was initiated to establish a long-term plan for the continued reduction of fuel oil sulfur content. D6 again experienced high crankcase pressure problems in February 2006. Corrective action for that event was to lower the oil level in the crankcase.

The licensees equipment root cause report for the October 2007 event determined that previous corrective actions were inadequate to keep up with the continued reduction of fuel oil sulfur content. Two other proposed corrective actions from the previous events, to reroute the crankcase vents to atmosphere instead of the turbocharger and combustion chambers, and to obtain a TS Amendment to reduce the electrical load requirements of the diesel generators were never completed. The licensee concluded that had one or both of those corrective actions been accomplished, the problem in October 2007 would probably not have happened.

The licensees organizational issues root cause report determined that the failure to complete the corrective actions was due, in part, to leadership weaknesses, lack of a strategic focus, and failure to enforce accountability. The licensee concluded that the high crankcase pressure issues would not have affected diesel generator operability in response to an actual event, so the only risk significant issue was the unplanned unavailability time used to investigate and repair the problem.

Licensee corrective actions for the October event included instituting a program to dope the D5 and D6 diesel generator fuel oil to maintain a relatively constant and higher sulfur content known to be compatible with the lubricating oil, placing priority on completing the modification to reroute the crankcase vents, and additional longer-termed planned actions.

Since the issue did not affect diesel generator operability, and the resulting unavailability was less than the allowed outage time, this issue was not considered to be a significant condition adverse to quality. Thus the failure to take actions to prevent recurrence of crankcase pressure problems was not considered to be a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. The unavailability time will be tracked and classified in accordance with the NRCs Mitigating Systems Performance Index.

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 8, 2008, the inspectors presented the inspection results to Mr. J. Sorensen and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit Meetings

Interim exits were conducted for:

On March 7, 2008, the inspector presented the results for the Access to Radiologically Significant Areas (IP 71121.01) and ALARA Planning and Controls (IP 71121.02)inspection to Mr. Paul Huffman and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On March 6, 2008, the inspectors presented the results for the Inservice Inspection (IP 71111.08) and Temporary Instruction (TI 2515/172) inspections, with Mr. J. Sorensen and other members of licensee staff. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.3 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted the following 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.

• Multiple tours of operations within the security alarm stations;

• Tours of selected security officer response posts;

• Direct observation of personnel entry screening operations within the plants Main Access Facility; and

• Security force shift turnover activities.

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.

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 NCVs.

• Technical Specification 3.7.11, Condition A, required that an inoperable safeguards chiller water system (SCWS) loop be returned to operable status within 30 days. Technical Specification 3.7.11, Condition B, required that if Condition A was not met, both units must be in Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. As discussed in Section 4OA3.3 of this report and CAP 01120914, the 121 loop of SCWS was inoperable from October 1, 2007, through the time it was repaired on December 15, 2007, and neither unit was shut down. Since the leak was small enough not to affect functionality of the system, had not grown significantly, and was repaired in a timely manner once it was determined to be pressure boundary leakage, the violation was of very low safety significance.

• Part 50.54(q) of 10 CFR required that the licensee follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b). Part 50.47(b)(8)of 10 CFR required that adequate emergency facilities and equipment to support the emergency response are provided and maintained. Prairie Island Nuclear Generating Plant Emergency Plan, Revision 36, Section 7.1.1.B required that the TSC have a shielding and ventilation cleanup system to provide habitability under accident conditions. As reported by the licensee in Event Notification 44057, on March 12, 2008, the licensee completed a preliminary review of a revised dose analysis for the TSC that showed that the whole body dose acceptance criteria of NUREG-0696 could have been exceeded during an event and compensatory measures might be required. The licensee entered the issue into its corrective action program as CAP 01130807. By the same logic as used for another TSC finding discussed in Section 1R15 of this report, the TSC function was considered to be degraded for more than seven days from time of discovery, but still functional, and the violation was determined to be of very low safety significance.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Wadley, Site Vice President

T. Allen, Nuclear Safety Assurance Manager

J. Anderson, Regulatory Affairs Manager

M. Carlson, former Director of Engineering

L. Clewett, Operations Manager

M. Davis, Regulatory Affairs Analyst

K. Den Herder, GL 89-13 Program Owner

T. Downing, ISI Programs Engineer

P. Gorman, Employee Concerns Manager

S. Northard, Plant Manager

R. Hite, Radiation Protection and Chemistry Manager

P. Huffman, former Plant Manager

T. Jones, NDE Coordinator

J. Kivi, Regulatory Compliance Engineer

C. Mundt, General Supervisor, Instrument and Control Maintenance

S. Redner, Project Manager

C. Sansome, former GL 89-13 Program Owner

M. Schimmel, Director of Engineering

S. Skoyen, Engineering Project Manager

J. Sorensen, Director Site Operations

E. Weinkam, NMC Licensing Director

P. Wiltse, Maintenance Manager

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000282/2008002-01; NCV TSC Ventilation Issues Resulted in Inadequate Emergency

05000306/2008002-01 Response Facility (Section 1R15)

05000282/2008002-02 URI Concerns Regarding Testing of Check Valve SI-9-5 (Section 1R22)

05000282/2008002-03; NCV Worker not in compliance with TS 5.7.1.b received an ED

05000306/2008002-03 dose-rate alarm when he inappropriately entered a HRA of the plant during steam generator set-up work.

(Section 2OS1)

Closed

05000282/2007-003-01; LER Unanalyzed Condition Due to Breached Fire Barrier

05000306/2007-003-01 (Section 4OA3.1)

Attachment

05000282/2007-004-00 LER Technical Specification Required Shutdown Due to Both Emergency Diesel Generators Being Inoperable (Section 4OA3.2)

05000282/2007-005-00; LER One Train of Safeguards Chilled Water System (SCWS)

05000306/2007-005-00 Inoperable Longer than Allowed by TSs (Section 4OA3.3)

05000306/2007005-02 URI Potential Inadequate Corrective Actions to Prevent Unnecessary D5 Diesel Generator Unavailability (Section 4OA5.1)

05000282/2008002-01; NCV TSC Ventilation Issues Resulted in Inadequate Emergency

05000306/2008002-01 Response Facility (Section 1R15)

05000282/2008002-03; NCV Worker not in compliance with TS 5.7.1.b received an ED

05000306/2008002-03 dose-rate alarm when he inappropriately entered a HRA of the plant during steam generator set-up work.

(Section 2OS1)

Attachment