IR 05000282/2004007

IR 05000282-04-007, 05000306-04-007; 07/01/2004 - 09/30/2004; Prairie Island Nuclear Generating Plant, Units 1 and 2; Licensed Operator Requalification Program, and Problem Identification and Resolution

ML043060489
Person / Time
Site:	Prairie Island
Issue date:	10/29/2004
From:	Ann Marie Stone NRC/RGN-III/DRP/RPB3
To:	Solymossy J Nuclear Management Co
References
IR-04-007
Download: ML043060489 (64)

Text

ber 29, 2004

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000282/2004007; 05000306/2004007

Dear Mr. Solymossy:

On September 30, 2004, 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 October 8, 2004, with you 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, the inspectors identified two NRC-identified findings of very low significance (Green). One of the findings also resulted in a violation of NRC requirements. Because this violation was of very low safety significance and was entered into your corrective action program, the NRC is treating the finding as Non-Cited Violation in accordance with Section VI.A.1 of the NRCs Enforcement Policy. In addition, one licensee-identified violation is listed in Section 4OA7 of this report.

If you contest the subject or severity of the Non-Cited Violation, 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). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Ann Marie Stone, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-282; 50-306 License Nos. DPR-42; DPR-60

Enclosure:

Inspection Report 05000282/2004007; 05000306/2004007 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-282; 50-306 License Nos: DPR-42; DPR-60 Report No: 05000282/2004007; 05000306/2004007 Licensee: Nuclear Management Company, LLC Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: 1717 Wakonade Drive East Welch, MN 55089 Dates: July 1 through September 30, 2004 Inspectors: J. Adams, Senior Resident Inspector D. Karjala, Resident Inspector J. Cameron, Project Engineer D. McNeil, Senior Operations Engineer B. Orlikowski, Resident Inspector, Monticello M. Mitchell, Radiation Specialist L. Haeg, Reactor Inspector C. Zoia, Operations Engineer F. Ramirez, Reactor Inspector Approved by: Ann Marie Stone, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000282/2004007, 05000306/2004007; 07/01/04 - 09/30/04; Prairie Island Nuclear

Generating Plant, Units 1 and 2; Licensed Operator Requalification Program, and Problem Identification and Resolution.

This report covers a 3-month period of baseline resident inspection and an announced baseline inspection on radiation protection. The inspection was conducted by the resident inspectors and inspectors from the Region III office. Two green findings with one associated violation were identified by the inspectors. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,

Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

A. Inspector-Identified and Self-Revealed Findings

Cornerstone: Mitigating Systems

C

Green.

The inspectors identified that the facility licensee failed to notify the NRC of a permanent change in the medical status of a licensed operator within 30 days of identification. This was considered to be a violation of 10 CFR 50.74(c), Notification of Change in Operator or Senior Operator Status.

This finding was more than minor because this could have resulted in a medically disqualified operator executing licensed operator duties in the control room. This could, therefore, potentially affect the health and safety of the public. The finding was of very low safety significance because no actual consequences were noted due to the adverse medical condition, and no adverse operational events were observed to have occurred due to inadequate medical conditioning of the operators license (Section 1R11).

Cornerstone: Barrier Integrity

Green.

A finding of very low safety significance was identified by the inspectors for untimely corrective actions to meet a regulatory commitment. In response to Generic Letter (GL) 89-13, Service Water System Problems Affecting Safety-Related Equipment, the licensee committed to test the containment fan coil units (CFCUs) at the maximum recommended frequency of every 5 years. The Unit 1 CFCUs were last tested in 1995. The primary cause of this finding was related to the cross-cutting area of Corrective Action. Despite three Corrective Action Program (CAP) documents in 2003 and two CAPs in 2004, the testing was postponed to December of 2004, 9 years since the previous test.

The finding was more than minor because if left uncorrected it would become a more significant safety concern and it affected the barrier integrity cornerstone objective of providing assurance that the containment will protect the public from releases caused by accidents or events. The finding was of very low safety significance because it did not represent an actual reduction of the containment pressure control function. No violations of NRC requirements were identified. (Section 4OA2.2)

Licensee-Identified Violations

A violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation 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 August 12, 2004, when the unit commenced coastdown in preparation for refueling outage 1R23. Power decreased to approximately 78 percent of full power. On October 10, 2004, the unit was shut down for a refueling and steam generator replacement outage. The unit remained shut down for the remainder of the inspection period.

Unit 2 was operated at or near full power throughout the inspection period except that power was reduced to approximately 88 percent of full power on July 8, 2004, due to an inadvertent addition of boric acid to the reactor coolant system. During the performance of corrective maintenance a control valve was slightly open because of a mal-adjusted stop nut which allowed boric acid into the Volume Control Tank. The unit was returned to full power within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> from the start of the event. On August 29, 2004, power was reduced to approximately 44 percent of full power for quarterly turbine valve testing. The unit was returned to full power within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and operated at or near full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

1RST Post-Maintenance and Surveillance Testing (71111.ST) (Pilot)

.1 Post-Maintenance Testing

a. Inspection Scope

During this inspection period, the inspectors completed five post-maintenance inspection samples, comprised of the following post-maintenance testing activities:

• Unit 2 over power delta temperature (OPDT) circuit changes on July 7, 2004;

• boric acid isolation valve 2VC-15-38 leakage on July 8, 2004;

• 4.16 kilo-Volt (kV) circuit breaker 26-2 following replacement of the control device on July 22, 2004;

• emergency safety feature actuation system relay 1CSB associated with the B train of containment spray following its replacement on July 30, 2004; and

• D6 radiator fans weekly run test following inspection of fan shaft for damage on September 15, 2004; During the performance of these inspections, the inspectors conducted in-plant observations and/or in-office reviews of documentation to ensure that testing activities met the following attributes:

• testing activities satisfied the test procedure acceptance criteria;

• effects of the testing had been adequately addressed prior to the commencement of the testing;

• measurement and test equipment calibrations were current;

• test equipment was used within the required range and accuracy;

• applicable prerequisites described in the test procedures were satisfied;

• affected systems or components were removed from service in accordance with approved procedures;

• testing activities were performed in accordance with the test procedures and other applicable procedures;

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

• test data/results were accurate, complete, and valid;

• test equipment was removed after testing;

• equipment was returned to a position or status required to support the operability of the system in accordance with approved procedures; and

• all problems identified during the testing were appropriately documented in the corrective action program.

The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Surveillance Testing

a. Inspection Scope

During this inspection period, the inspectors completed nine inspection samples, comprised of the following surveillance testing activities:

• Surveillance Procedure (SP) 2295, D5 Diesel Generator 6 Month Fast Start Test, on August 2, 2004;

• SP 1055.1, 121 Control Room Clean Up Ventilation System Filter Removal Efficiency Test, on August 11, 2004;

• SP 1102, 11 Turbine-Driven Auxiliary Feedwater Pump Monthly Test; on August 13, 2004;

• A Unit 2 reactor coolant system (RCS) chemistry sample and analysis on September 13, 2004;

• SP 2305, D6 Diesel Generator Monthly Slow Start Test, on September 14, 2004;

• SP 1092A; Safety Injection Check Valve Test (Head Off) Part A: High Head Injection Flow Path Verification, on September 15, 2004;

• SP 1092B; Safety Injection Check Valve Test (Head Off) Part B: RWST

[Refueling Water Storage Tank] to RHR [Residual Heat Removal] Flow Path Verification; on September 15, 2004;

• SP 1072.21, Unit 1 Local Leak-Rate Test (LLRT) of Reactor Coolant Drain Tank (RCDT) to Gas Analyzer Penetration 21 performed on September 22, 2004; and

• SP 1834; Unit 1 Containment Coating Inspection on September 23, 2004.

Observation of surveillance testing activities associated with SP 1102, SP 1092A, and SP 1092B completed the quarterly baseline inspection requirement to observe an inservice testing activity for a risk significant pump or valve. Observation of SP 1072.21 completed the requirement to observe a LLRT during each refueling outage.

Observation of the Unit 2 RCS chemistry sample completed the annual baseline inspection requirement to observe a chemistry technician obtain and analyze an RCS sample for the RCS Specific Activity performance indicator as required by Inspection Procedure 71151.

During completion of the inspection samples, the inspectors observed in-plant activities and reviewed procedures and associated records to verify that:

• preconditioning does not occur;

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

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

• plant equipment calibration was correct, accurate, properly documented, and the calibration frequency was in accordance with Technical Specifications (TS), the Updated Safety Analysis Report (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 frequency met TS requirements to demonstrate operability and reliability;

• the 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/results were accurate, complete, 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 (ASME) Code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data have been accurately incorporated in the test procedure;

• 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 in the corrective action program.

The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed three inspection samples comprised of partial system walkdowns of accessible portions of trains of risk-significant mitigating systems equipment during times when the trains were of increased importance due to the redundant trains or other related equipment being unavailable. The inspectors utilized the valve and electric breaker checklists listed in the Attachment to verify that the components were properly positioned and that support systems were lined up as needed. The inspectors also examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors reviewed outstanding work orders (WOs) and CAPs associated with the trains to verify that those documents did not reveal issues that could affect train function. The inspectors used the information in the appropriate sections of the USAR to determine the functional requirements of the systems.

The inspectors verified the alignment of the following trains:

• diesel generator D5 during the unavailability of diesel generator D6 on July 19, 2004;

• 11 safety injection pump during the unavailability of the 12 safety injection pump for planned maintenance on July 29, 2004; and

• 12 diesel-driven cooling water pump (DDCLP) during the unavailability of the 22 DDCLP on August 23, 2004;

b. Findings

No findings of significance were identified.

.2 Complete System Walkdowns

a. Inspection Scope

During the week of September 13, 2004, the inspectors performed a detailed in-plant walkdown of the alignment and condition of the Unit 1 diesel generator system, a risk significant system that provides electrical power during off-normal and accident modes of operation. This inspection effort constituted one complete system alignment inspection sample. As part of this inspection, the inspectors reviewed the documents listed in the Attachment.

The inspectors conducted in-plant walkdowns using the applicable alignment checklists to verify that system components were properly positioned to support the operation of the diesel generator systems and to verify that the as-found system configuration matched the configuration specified in the system alignment checklist. The inspectors examined the material condition of the components, such as diesel engines, generators, pumps, motors, valves, instrumentation, controls, and electrical panels. The inspectors observed operating parameters of equipment to verify that there were no obvious deficiencies and examined all applicable outstanding design issues, temporary modifications, and operator workarounds. The inspectors verified that tagging clearances were appropriate and attached to the specified equipment. The inspectors reviewed outstanding WOs and CAPs associated with the trains to determine if any degraded conditions existed that could affect the accomplishment of the systems safety functions. The inspectors referred to the TS, USAR, and other design basis documents to determine the functional requirements of the systems and verified those functions could be performed if needed. In addition, the inspectors reviewed the CAPs to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures.

b. Findings

No findings of significance were identified.

1R05 Fire Protection Area Walkdowns

a. Inspection Scope

The inspectors conducted in-office and in-plant reviews of portions of the licensees Fire Hazards Analysis and Fire Strategies to verify consistency between these documents and the as-found configuration of the installed fire protection equipment and features in the fire protection areas listed below. The inspectors selected fire areas for inspection based on their overall contribution to internal fire risk, as documented in the Individual Plant Examination of External Events; their potential to impact equipment which could initiate a plant transient; or their impact on the plants ability to respond to a security event. The inspectors assessed the control of transient combustibles and ignition sources, the material and operational condition of fire protection systems and equipment, and the status of fire barriers. The following nine fire areas were inspected by in-plant walkdowns supporting the completion of nine fire protection zone walkdown samples:

• Fire Area 13, Unit 1 and 2 control room on July 19, 2004;

• Fire Area 18, Unit 1 and 2 cable spreading room on July 20, 2004;

• Fire Area 22, bus 121, 480 volt safeguards switchgear room on July 20, 2004;

• Fire Area 26, D2 diesel generator room on July 20, 2004;

• Fire Area 33, 11 125 volt battery room on July 20, 2004;

• Fire Area 34, 12 125 volt battery room on July 20, 2004;

• Fire Area 68, Unit 1 containment annulus on September 22, 2004.

• Fire Area 101, D5 diesel generator room on July 20, 2004; and

• Fire Area 116, D6 lube oil make-up tank room on July 20, 2004.

The inspectors also reviewed the CAPs listed in the Attachment to verify that the licensee was identifying fire protection issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. As appropriate, the corrective actions were reviewed to determine if the actions taken were sufficient.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

.1 Observation of Licensed Operator Requalification Training

a. Inspection Scope

On August 3, 2004, the inspectors performed a quarterly review during licensed operator requalification training in the simulator, completing one licensed operator requalification inspection sample. The inspectors observed a crew while in training during an as-found requalification examination in the plants simulator facility. The inspectors compared crew performance to licensee management expectations. The inspectors verified that the crew completed all of the critical tasks for the scenario. For any weaknesses identified, the inspectors observed that the licensee evaluators noted the weaknesses and discussed them in the critique at the end of the session.

The inspectors assessed the licensees effectiveness in evaluating the requalification program, ensuring that licensed individuals would operate the facility safely and within the conditions of their licenses, and evaluated licensed operator mastery of high-risk operator actions. The inspection activities included, but were not limited to, a review of high risk activities, emergency plan performance, incorporation of lessons learned, clarity and formality of communications, task prioritization, timeliness of actions, alarm response actions, control board operations, procedural adequacy and implementation, supervisory oversight, group dynamics, interpretations of TS, simulator fidelity, and licensee critique of performance.

b. Findings

No findings of significance were identified.

.2 Conformance With Operator License Conditions (Medical)

a. Inspection Scope

The inspectors evaluated one licensed operators license renewal application for conformance with the requirements of 10 CFR 55.57, Renewal of Licenses. The medical information included with a request for license renewal was compared with the medical information maintained in the operators docket in the Region III office. The inspectors interviewed management personnel via telephone and reviewed the associated CAP report and condition evaluation (CE).

b. Findings

Introduction:

The inspectors identified one finding of very low safety significance (Green) associated with a Non-Cited Violation of 10 CFR 50.74(c) for the failure to notify the NRC of a change in medical status of a licensed operator which required a condition to the operators Reactor Operator license within 30 days of identification.

Description:

The inspectors compared the medical information accompanying a request for license renewal with the medical information currently maintained in the Region III operators docket. The medical information in the operators docket did not indicate a corrective lenses condition was required for the operators license. The renewal request specified a corrective lenses condition for the license. It was determined by telephone interview that a change in the operators medical status occurred following a biennial medical examination conducted in July 2002. The medical examination identified that the operator required a corrective lenses condition for the operator license in accordance with the medical requirements of 10 CFR 55.21, 55.23, and 55.25. When questioned, the licensee confirmed that the operator required glasses as a result of the medical examination in July 2002. The licensee was unable to find documentation that the request for a conditioned license was sent to the Region III offices in July/August 2002, and the licensee failed to perform any follow-up measures to ensure the operators license was properly conditioned between July 2002 and August 2004. This issue was considered to be NRC-identified because it was identified by NRC inspectors on August 16, 2004, during a review of the operators request for license renewal.

The facility licensee issued CAP 037957 to track this finding. Corrective actions which will address this issue had been initiated before this issue was discovered. Control of communication with the NRC and tracking of operator license requirements had been transferred to the Prairie Island Regulatory Affairs department earlier to more effectively track regulatory requirements such as this license conditioning. This license condition was overlooked because the request for license condition was missed before these functions were transferred to Regulatory Affairs. The inspectors determined that the corrective actions appeared to be adequate and should be effective in preventing this type of issue in the future.

Analysis:

The inspectors reviewed the issue concerning the licensees failure to make a timely notification to the NRC because of a change in status of licensed operators medical condition against the guidance contained in Appendix B, Issue Dispositioning Screening, of IMC 0612, Power Reactor Inspection Reports. This finding affected the mitigating system cornerstone objective because inadequate evaluation or identification of medical restrictions on operator licenses could result in licensed operators who may not be medically qualified performing licensed duties in the control room, potentially endangering the health and safety of the public. Consequently, the safety significance of this issue was determined to be more than minor.

The inspector reviewed this issue in accordance with Manual Chapter 0609, Significance Determination Process, Appendix I, Operator Requalification Human Performance Significance Determination Process (SDP). The SDP concerning medical issues focused on general record deficiencies exceeding a specified threshold of 20 percent of the records reviewed. Based on this SDP, the inspector determined that this finding was of very low safety significance (Green) because the failure to properly identify and inform the NRC of medical restrictions on operator licenses exceeded the 20 percent threshold (one out of one records reviewed) for record deficiencies. No actual consequences were noted due to the adverse medical condition, and no adverse operational events were observed to have occurred due to inadequate medical conditioning of the operators license

Enforcement:

Section 50.74(c) of 10 CFR required, in part, that each facility licensee shall notify the NRC within 30 days of a permanent disability or illness to a licensed operator or senior operator as described in 10 CFR 55.25. Section 55.25 required, in part, that if a licensed operator develops a permanent physical or mental condition that causes the operator to fail to meet the requirements of Section 55.21, the facility licensee shall notify the NRC, within 30 days of learning of the diagnosis, in accordance with Section 50.74. For conditions for which a conditional license was required, the facility licensee must provide medical certification on Form NRC-396 as required by Section 55.23. Contrary to the above, in July 2002, during the required biennial medical examinations, the facility licensee was informed by the stations medical officer of the need for a medical restriction for corrective lenses for a licensed operator. The facility licensee acknowledged the medical evaluation, but failed to appropriately inform the NRC within 30 days of the change in medical condition and request a license medical restriction. On August 16, 2004, NRC inspectors identified the lack of the required medical restriction on the operators license. This issue is in the licensees corrective action program as CAP 037957. Because this violation was of very low safety significance and was captured in the licensees corrective action program, this violation was being treated as a NCV consistent with Section VI.A of NRC Enforcement Policy (05000282/2004007-01; 05000306/2004007-01). The licensee implemented corrective action and satisfactorily verified that the operator was performing licensed duties with corrective lenses.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed repetitive maintenance activities to assess maintenance effectiveness, including maintenance rule (10 CFR 50.65) activities, work practices, and common cause issues. The inspectors performed two issue/problem-oriented maintenance effectiveness samples and two structure, system, or component (SSC)/train function oriented maintenance effectiveness samples completing a total of four samples. The inspectors assessed the licensees maintenance effectiveness associated with repetitive problems on the following SSCs:

• plant circuit breakers during the week of August 2, 2004;

• reactor vessel level indicating system (RVLIS) during the week of September 19, 2004;

• D5 diesel generator during the week of September 19, 2004; and

• 1N31 source range detector during the week of September 27, 2004.

The inspectors reviewed the licensees maintenance rule evaluations of equipment failures for maintenance preventable functional failures and equipment unavailability time calculations, comparing the licensees evaluation conclusions to applicable Maintenance Rule (a)1 performance criteria. Additionally, the inspectors reviewed scoping, goal-setting (where applicable), performance monitoring, short-term and long-term corrective actions, functional failure definitions, and current equipment performance status.

The inspectors reviewed CAPs for significant equipment failures associated with circuit breakers for risk significant mitigating equipment, an emergency alternating current power supply (diesel generator) for risk significant and safety-related mitigating equipment, and important reactor coolant system level and nuclear instrumentation relied upon in emergency operating procedures to ensure that those failures were properly identified, classified, and corrected. The inspectors reviewed other CAPs to assess the licensees problem identification threshold for degraded conditions, the appropriateness of specified corrective actions, and that the timeliness of the actions were commensurate with the significance of the identified issues. The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed risk assessments for the following six maintenance activities, completing six risk assessment and emergent work control inspection samples:

• the simultaneous unavailability of the 22 component cooling water heat exchanger and the 125 station air compressor for planned maintenance on July 19, 2004;

• the emergent failure of breaker 26-2 with the declaration of inoperability of the 26 load sequencer, D6 diesel generator, concurrent with the out-of-service of the 125 service air compressor, and 122 instrument air dryer on July 20, 2004;

• the simultaneous unavailability of the 22 charging pump and the 21 auxiliary feedwater pump for planned maintenance on August 3, 2004;

• the simultaneous unavailability of D5 diesel generator, bus 15 load sequencer, and bus 25 load sequencer for planned maintenance on September 15, 2004;

• the simultaneous unavailability of bus 15, bus 111, 17 inverter, and D2 diesel generator for planned maintenance on September 22, 2004; and

• the simultaneous unavailability of bus 15, 121 air compressor, 17 inverter, and 11 cooling water pump for planned maintenance on September 28, 2004.

During these reviews, the inspectors compared the licensees risk management actions to those actions specified in the licensees procedures for the assessment and management of risk. The inspectors verified that evaluation, planning, control, and performance of the work were done in a manner to reduce the risk and minimize the duration where practical, and that contingency plans were in place where appropriate.

The inspectors used the licensees daily configuration risk assessment records, observations of shift turnover meetings, observations of daily plant status meetings, and observations of shiftily outage meetings to verify that the equipment configurations had been properly listed, that protected equipment had been identified and was being controlled where appropriate, and that significant aspects of plant risk were communicated to the necessary personnel. The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R14 Personnel Performance Related to Non-Routine Plant Evolutions and Events

.1 Closure of Moisture Separator Reheater Steam Supply Valves on a Loss of Power

Supply

a. Inspection Scope

On September 9, 2004, the inspectors discussed with operators the actions taken to address an emergent failure of the power supply for the moisture separator reheater steam supply valves. The loss of the power supply resulted in a loss of turbine efficiency and a power mismatch between the reactor and turbine power. The inspectors also performed an in-office review of operator actions and compared their actions to the actions specified in annunciator response and abnormal operating procedures. The inspectors compared the plants response to the expected response of a failure of the power supply to instrument panel 313.

The inspectors reviewed the CAPs listed in the Attachment to verify that the licensee was identifying equipment and human performance issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. This inspection effort completed one inspection sample for personnel performance related to non-routine plant evolutions and events.

b. Findings

No findings of significance were identified.

.2 Taking Unit 1 Pressurizer Solid and Control of the Reactor Coolant System in a Water

Solid Configuration

a. Inspection Scope

On September 11, 2004, the inspectors discussed with and observed control room operators collapse the bubble in the Unit 1 pressurizer, place the reactor coolant system in a water solid configuration, and control reactor coolant system pressure and temperatures. The inspectors compared operator actions to the actions specified in plant operating procedures. The inspectors reviewed descriptions of expected plant response provided in plant operating procedures and compared actual control room instrument response to the expected instrument response.

The inspectors reviewed the CAPs listed in the Attachment to verify that the licensee was identifying equipment and human performance issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. This inspection effort completed one personnel performance related to non-routine plant evolutions and events inspection sample.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the technical adequacy of four operability evaluations completing four operability evaluation inspection samples. The inspectors conducted these inspections by in-office review of associated documents and in-plant observations of affected areas and plant equipment. The inspectors compared degraded or nonconforming conditions of risk significant SSCs associated with mitigating systems against the functional requirements described in TS, USAR, and other design basis documents; determined whether compensatory measures, if needed, were implemented; and determined whether the evaluation was consistent with the requirements of Administrative Work Instruction (AWI) 5AWI 3.15.5, Operability Determinations. The following operability evaluations were reviewed:

• CE 005637 that documented the operability of the 12 DDCLP with unusual surveillance data on July 21, 2004;

• Operability Recommendation (OPR) 000507 that documented the operability of transformer CT12, which supplies electrical power from offsite to safety related 4kV buses, with the presence of a bulge in the cold shrink cable termination on July 23, 2004;

• OPR 000511 that documented the operability of the 11 and 12 RHR pumps with current transducers, which provide an isolation function between safety-related and non safety related circuits, that were purchased without all required qualifications on August 24, 2004; and

• OPR 000514 that documented the operability of the 12 DDCLP with the suction bell bearing water flow switch stuck at 0 gallons per minute (gpm) on September 9, 2004.

b. Findings

No findings of significance were identified.

1R16 Operator Workarounds

a. Inspection Scope

On August 11, 2004, the inspectors evaluated a licensee identified operator workaround associated with the 21 steam generator power operated relief valve hand controller completing one operator workaround inspection sample. The inspectors reviewed associated procedures and conducted discussions with operators to determine if the 21 steam generator power operated relief valve mitigating function or the operators ability to implement abnormal or emergency operating procedures were affected.

The inspectors also reviewed the CAPs to verify that the licensee was identifying operator workaround issues at an appropriate threshold, entering them into their corrective action program, and resolving them in accordance with station corrective action procedures. The documents reviewed by the inspectors are listed in the

.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed modification package 03FH02 and WO 0405444, which changed the OPDT reactor trip setpoint calculation, completing one permanent plant modification inspection procedure sample. Specifically, this modification removed the delta flux input to the reactor trip setpoint calculation circuitry on Unit 2. The modification was also performed on Unit 1. The modification was performed under Facility Operating License DPR-60 Amendment 153 which was requested because the licensee transferred core reload safety analysis responsibility from Nuclear Management Companys (NMC) Nuclear Analysis Department to Westinghouse. The inspectors performed an in-office review of the design change package. A detailed list of the documents reviewed is included in the Attachment.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors observed the licensees performance during the twenty-third Unit 1 refueling outage 1R23 conducted between September 10 and September 30, 2004.

These inspection activities represent one refueling outage inspection sample.

This inspection consisted of an in-office review of the licensees outage schedule, safe shutdown plan and procedures governing the outage. Specifically, the inspectors assessed whether the licensee planned to effectively manage elements of shutdown risk pertaining to reactivity control, decay heat removal, inventory control, electrical power availability, and containment integrity.

The inspectors conducted in-plant observations of the following outage activities daily:

• attended outage management turnover meetings to verify that the current shutdown risk status was accurate, well understood, and adequately communicated;

• performed walkdowns of the main control room to observe the alignment of systems important to shutdown risk;

• observed the operability of RCS instrumentation and compared channels and trains against one another;

• performed in-plant walkdowns to observe ongoing work activities and foreign material exclusion control; and

• conducted in-office reviews of selected issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance Additionally, the inspectors performed in-plant observations of the following specific activities:

• Unit 1 shutdown and initial cooldown;

• alignment of the RHR system for shutdown cooling and control of reactor coolant system cooldown;

• reactor vessel head leakage examination per Inspection Procedure 71111.08, paragraph 02.03.b and SP 1407;

• reactor coolant system boric acid corrosion control inspection per Inspection Procedure 71111.08, paragraph 02.03.a and SP 1405;

• control room staff draining reactor level to the reactor vessel to the flange;

• assessment of shutdown risk;

• control of containment integrity;

• reactor pressure vessel head lift;

• core unloading activities in the reactor containment, spent fuel pool, and control room; and

• reactor lower internals removal.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors conducted an in-plant observation of the physical changes to the equipment and an in-office review of documentation associated with four temporary modifications completing four temporary modification inspection samples. As part of this inspection, the documents in the Attachment were utilized to evaluate the potential for an inspection finding.

The inspectors reviewed the following temporary modifications:

• installation of jumpers on Unit 1 to prevent automatic safety injection actuation for refueling outage activities on September 20, 2004;

• operation of the Unit 1 containment purge system on September 21, 2004;

• installation of temporary air lines to facilitate repair to a leak in the Unit 1 instrument air system in the auxiliary building on September 22, 2004; and

• removal of containment purge exhaust filters on September 30, 2004.

The inspection activities included, but were not limited to, a review of design documents, safety screening documents, and USAR to determine that the temporary modification was consistent with modification documents, drawings and procedures. The inspectors also reviewed the post-installation test results to confirm that tests were satisfactory and the actual impact of the temporary modification on the permanent system and interfacing systems were adequately verified. The inspectors also reviewed the CAPs listed in the Attachment to this report to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed a licensed shift operating crew perform an as-found exercise on the simulator on August 10, 2004, completing one emergency planning simulator exercise sample. The inspectors observed activities in the control room simulator and attended the post-exercise critique. The inspectors evaluated the drill performance and verified that licensee evaluators observations were consistent with those of inspectors and that deficiencies were entered into the corrective action program.

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 or not the conditions surrounding the PIs had been evaluated, and identified problems had been entered into the corrective action program for resolution. This review represented one sample.

b. Findings

No findings of significance were identified.

.2 Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

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

1) Containment Steam Generator Vaults; 2) Rad Waste Building; and 3) Containment Seal Table Area.

This review represented one sample.

The inspectors reviewed the radiation work permit (RWP) and work packages used to access these three 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 review represented one sample.

The inspectors walked down and surveyed (using an NRC survey meter) these three 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 review represented one sample.

The inspectors reviewed RWPs for the following airborne radioactivity area 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:

Containment Seal Table. 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 review represented one sample.

The adequacy of the licensees internal dose assessment process for internal exposures

> 50 millirem committed effective dose equivalent was assessed. There were no internal exposures greater than 50 millirem. This review represented one sample.

The inspectors also reviewed the licensees physical and programmatic controls for highly activated and/or contaminated materials (non-fuel) stored within spent fuel or other storage pools. This review represented one sample.

b. Findings

No findings of significance were identified.

.3 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed 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 review represented one sample.

The inspectors reviewed 15 corrective action reports related to access controls and three high radiation area radiological incidents when available (non-PIs identified by the licensee in high radiation areas <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 review represented one sample.

The inspectors evaluated the licensees process for problem identification, characterization, prioritization, and verified that problems 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 review represented one sample.

The inspectors reviewed licensee documentation packages for all PI events occurring since the last inspection to determine if any of these PI events involved dose rates

>25 R/hr at 30 centimeters or >500 R/hr at 1 meter. Barriers were evaluated for failure and to determine if there were any barriers left to prevent personnel access.

Unintended exposures >100 millirem total effective dose equivalent (or >5 rem shallow dose equivalent or >1.5 rem lens dose equivalent), were evaluated to determine if there were any regulatory overexposures or if there was a substantial potential for an overexposure. No examples of these type of PI events occurred. This review represented one sample.

b. Findings

No findings of significance were identified.

.4 Job-In-Progress Reviews

a. Inspection Scope

The inspectors observed that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers. This review was conducted in conjunction with Inspection Procedure 71121.02, and is documented in Section 2OS2.4 of this report. This review represented five samples.

b. Findings

No findings of significance were identified.

.5 High Risk Significant, High Dose Rate, High Radiation Areas (HRA) and VHRA 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 verify that any procedure modifications did not substantially reduce the effectiveness and level of worker protection. This review represented one sample.

The inspectors discussed with RP 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 RP group, so as to allow corresponding timely actions to properly post and control the radiation hazards. This review represented one sample.

The inspectors conducted plant walkdowns to verify the posting and locking of entrances to high dose rate HRAs, and very high radiation. This review represented one sample.

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 review represented one sample.

The inspectors reviewed six radiological problem reports which found that 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.

These problems, along with planned and taken corrective actions were discussed with the Radiation Protection Manager. This review represented one sample.

b. Findings

No findings of significance were identified.

.7 Radiation Protection Technician Proficiency

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation protection technician (RPT) performance with respect to radiation protection work requirements and evaluated whether they 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 review represented one sample.

The inspectors reviewed seven radiological problem reports which found that the cause of the event was radiation protection technician 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 review represented one sample.

b. Findings

No findings of significance were identified.

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

.1 Inspection Planning

a. Inspection Scope

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

• Outage Containment Scaffold;

• Outage Containment Structural Modifications;

• Outage Primary and Secondary Side Water Level Control;

• Outage Insulation; and

• Outage Reactor Coolant System Cutting and Welding Activities.

This review represented one sample.

b. Findings

No findings of significance were identified.

.2 Radiological Work Planning.

a. Inspection Scope

The inspectors evaluated the licensees list of work activities ranked by estimated exposure that were in progress and reviewed the following five work activities of highest exposure significance:

• Outage Containment Scaffold;

• Outage Containment Structural Modifications;

• Outage Primary and Secondary Side Water Level Control;

• Outage Insulation Removal; and

• Outage Reactor Coolant System Cutting and Welding Activities.

This review represented one sample.

The inspectors compared the results achieved including dose rate reductions and person-rem used with the intended dose established in the licensees ALARA planning for these five work activities. Reasons for inconsistencies between intended and actual work activity doses were reviewed. This review represented one sample.

b. Findings

No findings of significance were identified.

.3 Verification of Dose Estimates and Exposure Tracking Systems

a. Inspection Scope

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

The licensees process for adjusting exposure estimates or re-planning work, when unexpected changes in scope, emergent work or higher than anticipated radiation levels were encountered, was evaluated. This included determining that adjustments to estimated exposure (intended dose) were based on sound radiation protection and ALARA principles and not adjusted to account for failures to control the work. The frequency of these adjustments was reviewed to evaluate the adequacy of the original ALARA planning process. This review represented one sample.

The licensees exposure tracking system was evaluated to determine whether the level of exposure tracking detail, exposure report timeliness, and exposure report distribution was sufficient to support control of collective exposures. RWPs were reviewed to determine if they covered too many work activities to allow work activity specific exposure trends to be detected and controlled. During the conduct of exposure significant work, the inspectors evaluated if licensee management was aware of the exposure status of the work and would intervene if exposure trends increased beyond exposure estimates. This review represented one sample.

b. Findings

No findings of significance were identified.

.4 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 high radiation areas for observation of work activities that presented the greatest radiological risk to workers:

• Outage Containment Scaffold and Shielding;

• Outage Containment Structural Modifications;

• Outage Steam Generator Upper Assembly Removal;

• Outage ISI Robotic Activities; and

• Outage RCS Cutting and Welding Preparation and Staging.

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, 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.

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 review represented one sample.

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, ensuring that workers were properly trained, and that proper tools and equipment were available when the job started. This review represented one sample.

b. Findings

No findings of significance were identified.

.5 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 high radiation areas 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 that work activity controls were being complied with. Also, radiation worker training and skill levels were reviewed to determine if they were sufficient relative to the radiological hazards and the work involved. This review represented one sample.

b. Findings

No findings of significance were identified.

.6 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 review represented one sample.

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 review represented one sample.

b. Findings

No findings of significance were identified.

2OS3 Access Control to Radiologically Significant Areas (71121.03)

Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed the Radiation Work Permits (RWPs) and work packages used to access four areas including high radiation work areas, for the upcoming Steam Generator Replacement Outage, to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm setpoints for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. This review represented one sample.

b. Findings

No findings of significance were identified.

Cornerstone: Public Radiation Safety

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

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed the most current Radiological Effluent Release Report to verify that the program was implemented as described in Radiological TSs/Offsite Dose Calculation Manual (RETS/ODCM) and to determine if ODCM changes were made in accordance with Regulatory Guide 1.109 and NUREG-0133.

The inspectors reviewed RETS/ODCM to identify the effluent radiation monitoring systems and its flow measurement devices, effluent radiological occurrence performance indicator incidents in preparation for onsite follow-up, and the USAR description of all radioactive waste systems. This review represented one sample.

b. Findings

No findings of significance were identified.

.2 Onsite Inspection

a. Inspection Scope

The inspectors walked down the major components of the gaseous and liquid release systems (e.g., radiation and flow monitors, demineralizers and filters, tanks, and vessels) to observe current system configuration with respect to the description in the USAR, ongoing activities, and equipment material condition. This review represented one sample.

The inspectors observed the routine processing (including sample collection and analysis) to verify that appropriate treatment equipment was used and that radioactive liquid waste was processed and released in accordance with procedure requirements and observed the sampling and compositing of liquid effluent samples. There was no scheduled release of radioactive liquid waste during the inspection. The inspectors observed the routine processing (including sample collection and analysis) of radioactive gaseous effluent to verify that appropriate treatment equipment was used and that the radioactive gaseous effluent was processed and released in accordance with RETS/ODCM requirements. There was no scheduled release of radioactive gaseous effluent during the inspection. This review represented one sample.

The inspectors reviewed the records of abnormal releases or releases made with inoperable effluent radiation monitors and reviewed the licensees actions for these releases to ensure an adequate defense-in-depth was maintained against an unmonitored, unanticipated release of radioactive material to the environment. This review represented one sample.

The inspectors reviewed the licensees technical justification for changes made by the licensee to the ODCM as well as to the liquid or gaseous radioactive waste system design, procedures, or operation since the last inspection to determine whether the changes affect the licensees ability to maintain effluents As-Low-As-Reasonably-Achievable (ALARA) and whether changes made to monitoring instrumentation resulted in a non-representative monitoring of effluents.

This review represented one sample.

The inspectors reviewed a selection of monthly, quarterly, and annual dose calculations to ensure that the licensee properly calculated the offsite dose from radiological effluent releases and to determine if any annual RETS/ODCM (i.e., Appendix I to 10 CFR Part 50 values) were exceeded. This review represented one sample.

The inspectors reviewed air cleaning system surveillance test results to ensure that the system was operating within the licensees acceptance criteria. The inspectors reviewed surveillance test results the licensee uses to determine the stack and vent flow rates. The inspectors verified that the flow rates were consistent with RETS/ODCM or USAR values. This review represented one sample.

The inspectors reviewed records of instrument calibrations performed since the last inspection for each point of discharge effluent radiation monitor and flow measurement device and reviewed any completed system modifications and the current effluent radiation monitor alarm setpoint value for agreement with RETS/ODCM requirements. The inspectors also reviewed calibration records of radiation measurement (i.e., counting room) instrumentation associated with effluent monitoring and release activities and the quality control records for the radiation measurement instruments. This review represented one sample.

The inspectors reviewed the results of the interlaboratory comparison program to verify the quality of radioactive effluent sample analyses performed by the licensee. The inspectors reviewed the licensees quality control evaluation of the interlaboratory comparison test and associated corrective actions for any deficiencies identified. The inspectors reviewed the licensees assessment of any identified bias in the sample analysis results and the overall effect on calculated projected doses to members of the public. In addition, the inspectors reviewed the results from the licensees Quality Assurance (QA) audits to determine whether the licensee met the requirements of the RETS/ODCM. This review represented one sample.

.3 Identification and Resolution of Problems

a. Inspection Scope

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

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

• initial problem identification, characterization, and tracking;

• disposition of operability/reportability issues;

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

• identification of repetitive problems;

• identification of contributing causes;

• identification and implementation of effective corrective actions;

• resolution of non-cited violations (NCVs) tracked in the corrective action system; and

• implementation/consideration of risk significant operational experience feedback.

This review represented one sample.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

.1 Reactor Safety Strategic Area

a. Inspection Scope

The inspectors reviewed the licensee submittals for four performance indicators for Prairie Island Units 1 and 2, completing eight performance indicator verification inspection procedure samples. The inspectors reviewed the documents listed in the

.

The inspectors observed a chemistry technician obtain and analyze a Unit 2 RCS sample used for the RCS Specific Activity performance indicator.

The inspectors used performance indicator guidance and definitions contained in Nuclear Energy Institute (NEI) Document 99-02, Revision 2, Regulatory Assessment Performance Indicator Guideline, to verify the accuracy of the performance indicator data. The inspectors review included, but was not limited to, conditions and data from logs, LERs, condition reports, and calculations for each performance indicator specified.

The inspectors also reviewed the CAPs listed in the Attachment to this report to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with corrective action procedures.

The licensees reporting of the following performance indicators were verified:

Unit 1

• Safety System Functional Failures for the 3rd quarter 2003 through the 2nd quarter 2004;

• Reactor Scrams for the 2nd quarter 2003 through the 2nd quarter 2004;

• Unplanned Power Changes for the 3rd quarter 2003 through the 2nd quarter 2004; and

• Reactor Coolant System Activity for the 3rd quarter 2003 through the 2nd quarter 2004.

Unit 2

• Safety System Functional Failures for the 3rd quarter 2003 through the 2nd quarter 2004;

• Reactor Scrams for the 2nd quarter 2003 through the 2nd quarter 2004;

• Unplanned Power Changes for the 3rd quarter 2003 through the 2nd quarter 2004; and

• Reactor Coolant System Activity for the 3rd quarter 2003 through the 2nd quarter 2004.

b. Findings

No findings of significance were identified.

.2 Radiation Safety Strategic Area

a. Inspection Scope

The inspectors reviewed the licensees assessment of its performance indicator for public radiation safety by reviewing the dose records related to both liquid and gaseous effluent releases from the station from January 2003 to June 2004, to determine if this data was adequately assessed and reported. Since no reportable events were identified by the licensee for all quarters of calendar year 2003 and for the 1st and 2nd quarters of calendar year 2004, the inspectors compared the licensees data with the corrective action database for these time periods to verify that there were no unaccounted for occurrences in the Public Radiation Safety performance indicator as defined by the applicable revision of NEI 99-02.

The inspectors also reviewed the licensees determination of Performance Indicator (PI)for the occupational radiation safety cornerstone (Occupational Exposure Control Effectiveness) to verify that the licensee accurately determined these performance indicators and had identified all occurrences required by these indicators. Specifically, the inspector reviewed the licensees CAPs for 3rd and 4th quarter 2003 and the first three quarters of 2004 Occupational Exposure performance indicator data to ensure that there were no PI occurrences that were not identified by the licensee. Additionally, as part of plant walkdowns (Section 2OS1.1), the inspector selectively examined the adequacy of posting and controls for locked HRAs, to verify the current Occupational Exposure Control Effectiveness performance indicator. The inspector interviewed members of the licensees staff who were responsible for performance indicator data acquisition, verification and reporting, to verify that their review and assessment of the data was adequate.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

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 ensure timely corrective actions, and that adverse trends were identified and addressed. Minor issues entered into the licensees corrective action program as a result of inspector observations are covered by the list of documents included in the Attachment.

b. Findings

No findings of significance were identified.

.2 Problem Identification and Resolution Annual Sample Review - Containment Fan Coil

Unit Performance Testing

a. Inspection Scope

The inspectors selected a corrective action program issue for detailed review which constituted one annual problem identification and resolution inspection procedure sample. The inspectors selected testing of CFCUs in response to GL 89-13, Service Water System Problems Affecting Safety-Related Equipment. Five CAPs were initiated in 2003 and 2004, identifying the failure to comply with the commitment to perform the testing on Unit 1 every 5 years. The effectiveness of the licensees corrective action program was assessed by reviewing the documented history of equipment performance, CAP evaluations, corrective actions, and other corrective action program documents. A complete list of the documents reviewed is included in the Attachment.

b. Findings

Introduction:

The inspectors identified a finding associated with the licensees untimely corrective actions to fulfill a commitment to GL 89-13. The issue was considered to be a finding of very low safety significance (Green). No violation of NRC requirements was identified.

Description:

Generic Letter 89-13 recommended that safety-related heat exchangers cooled by service water be tested at a minimum frequency of once every 5 years to verify heat transfer capability. The Prairie Island response to GL 89-13 stated that a periodic test program will be implemented as recommended by the Generic Letter and the licensee implemented procedure H21, Generic Letter 89-13 Implementing Program. The safety-related cooling supply for the CFCUs was cooling water and the CFCUs are included in the scope of procedure H21. The most recent performance test on the Unit 1 CFCUs was conducted in December 1995. Licensee staff members initiated three CAPs in 2003 and two CAPs in 2004 identifying that the periodic testing was postponed. The testing has not been performed as of the end of this inspection period despite the repeated CAPs. The testing is currently scheduled for December 2004, 9 years since the previous test and 4 years past the recommended 5 year frequency. The inspectors concluded that the corrective action program was ineffective in addressing the deficiency in a timely manner.

The CAPs indicate that the testing was postponed due to unavailability of a chilled water supply. The GL 89-13 stated that alternative actions were acceptable in lieu of testing.

An example of an acceptable alternative action was regular inspection and cleaning.

The CAP documentation does not identify that any alternative actions were considered or evaluated.

The licensee had performed periodic flow tests which demonstrated adequate flow; therefore, this concern deals with the licensees ability to resolve the CAPs; not in the functionality of the CFCUs.

Analysis:

The inspectors determined that the failure to implement actions to meet the commitment was a deficiency warranting a significance determination accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, issued on June 20, 2003. The inspectors determined that the finding was more than minor because if left uncorrected the finding would become a more significant safety concern, it involved the barrier integrity cornerstone, and it affected the cornerstone objective of providing reasonable assurance that the containment will protect the public from radio nuclide releases caused by accidents or events.

The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process. The finding was associated with the heat removal and pressure control function for the reactor containment barrier. Since the finding does not represent an actual reduction of the reactor containment pressure control function, the inspectors answered no to all of the SDP Phase 1 screening questions for the barrier integrity cornerstone. Therefore, this finding was considered to be of very low safety significance (Green).

Enforcement:

The finding is a failure to fulfill a regulatory commitment to GL 89-13.

Since the testing is not required by 10 CFR 50, no violation of regulatory requirements occurred. The issue was considered a finding of very low safety significance (FIN 05000282/2004007-02). The licensee entered the issue into the corrective action program as CAP 036991, The Unit 1 FCU Performance Test Work Orders Were Postponed.

.3 Problem Identification and Resolution Annual Sample Review - Flow Accelerated

Corrosion Program Effectiveness

a. Inspection Scope

During the week ending September 11, 2004, the inspectors selected a corrective action program issue for detailed review completing one problem identification and resolution annual inspection sample. The inspectors selected an issue associated with the flow accelerated corrosion (FAC) program originally identified by the Prairie Island Nuclear Oversight organization and entered into the corrective action program with CAP 032418 on September 12, 2003.

The inspectors conducted a review of the previously referenced CAP and other related corrective action program documents, and interviewed FAC Program Engineer, Supervisor of Inspection and Material Engineering, the Engineering Programs Manager, and the Site Engineering Director in order to assess the effectiveness of the licensees efforts to correct the identified problem. Of the documents reviewed by inspectors, particular attention was placed on the review of the licensees corrective actions taken to address the noted deficiencies and the effectiveness of those actions. The inspectors also ensured that the licensee had identified the full extent of the issue, conducted an appropriate evaluation, and that licensee-identified corrective actions were appropriately prioritized. The inspectors compared the licensees actions taken to address the issue against the requirements of the licensees corrective action program as specified in Administrative Work Instruction 5AWI 16.0.0, Action Request Process; Performance Assessment Fleet Procedure FP-PA-ARP-01, Action Request Process; Administrative Work Instruction 5AWI 15.0.2, Work Order Codes; and 10 CFR Part 50, Appendix B.

A complete list of the documents reviewed is included in the Attachment.

b. Findings and Observations

No findings of significance were identified.

4OA3 Event Followup

(Closed) LER 05000282/2004-001-00: Condition Prohibited by TSs Caused by Miscalibration.

On April 19, 2004, an evaluation determined that the setpoints for Control Room Air Supply Radiation Monitors (RM-23 and RM-24) had been miscalibrated and they were declared inoperable. On April 20, 2004, both RM-23 and RM-24 were recalibrated to their proper setpoints. RM-23 had been set to the wrong setpoint on February 24, 2004, and RM-24 had been set to the wrong setpoint on March 1, 2004.

The inspectors reviewed the licensees root cause investigation report, immediate corrective actions, and corrective actions to prevent recurrence to verify that the proposed and completed corrective actions addressed the causes of the event and fully restored the function of the radiation monitors. The inspectors also assessed the significance of the finding using the significance determination process. Because the inoperable radiation monitors did not cause a loss of safety function, the finding was determined to be of very low safety significance (Green). The enforcement aspect of this issue is discussed in Section 4OA7. This LER is closed.

4OA5 Other Activities

.1 Reactor Containment Sump Blockage (NRC Bulletin 2003-01, Prairie Island Units 1

and 2) (Temporary Instruction 2515/153)

a. Inspection Scope

The inspectors performed a preliminary review of licensee activities in response to NRC Bulletin 2003-01, "Potential Impact of Debris Blockage on Emergency Sump Recirculation at Pressurized Water Reactors (PWRs)," in accordance with NRC Temporary Instruction 2515/153, "Reactor Containment Sump Blockage (NRC Bulletin 2003-01)," dated October 3, 2003. The inspectors reviewed the licensees completed and proposed compensatory measures submitted in accordance with Bulletin 2003-01, Option 2, to verify they have been implemented or were planned and scheduled for implementation consistent with the licensees response.

The inspectors interviewed operations and engineering personnel and reviewed training records, procedures for foreign material control and containment inspection, and the results of containment coating and debris generation inspections. The documents reviewed by the inspectors are listed in the Attachment.

On October 7, 2003, the inspectors performed visual inspections of the as-left condition of the Unit 2 containment sumps and sump screens, and the as-left configuration of reactor cavity drain. The inspectors also walked down the Unit 2 containment to verify that the condition of the containment coatings, piping insulation, post Loss-of-Coolant-Accident (LOCA) drainage paths, and emergency core cooling system (ECCS) recirculation sumps were consistent with condition reported in the licensees containment closeout inspection. The inspectors assessed the licensees foreign material exclusion controls during subsequent containment entries following completion of the final containment closeout inspection.

On September 11, 2004, the inspectors conducted a walkdown shortly after a Unit 1 reactor shutdown was completed to assess the as-found conditions in the containment including the material condition and/or cleanliness of the recirculation sump, the sump screens, containment coatings, equipment insulation and general containment cleanliness. The inspectors conducted this inspection with a specific focus for the existence of loose debris upstream and in the direct vicinity of the recircualtion sump that could have blocked the sump screens or become ingested in emergency core cooling systems in the event of a LOCA.

b. Findings

Temporary Instruction Reporting Requirements No findings of significance were identified relative to the potential impact of debris blockage on emergency sump recirculation. The following information is provided as specified by the Reporting Requirements section of Temporary Instruction 2515/153.

During the September 2003 Prairie Island Unit 2 refueling outage (2R22), plant staff from the Design Engineering department performed a containment walkdown using the guidance provided in NEI 02-01, Condition Assessment Guidelines: Debris Sources Inside PWR Containments, Revision 1, to identify and quantify potential debris sources; and to obtain additional detailed data and photographs to support future debris transport analyses. Additionally, engineers also checked the material condition of the containment sump and sump screens, and verified that no major obstructions upstream of the sump that could prevent the return of reactor coolant to the recirculation sump.

The engineers did not identify any excessive gaps in the installation of the recirculation sump screens.

During this inspection period Prairie Island Unit 1 commenced a refueling and steam generator replacement outage (1R23). Design engineers conducted a Unit 1 containment walkdown equivalent to the walkdown conducted during the previous Unit 2 walkdown. This walkdown had been performed during the November 2002, Unit 1 refueling outage, but was performed without the guidance contained in NEI 02-01. The design engineers re-performed their walkdown to quantify debris sources using NEI 02-01 guidance during the current refueling outage. The engineers did not identify any excessive gaps in the installation of the recirculation sump screens.

The inspectors assessed conditions in the respective containments during each of the refueling outages mentioned previously. The inspectors conducted this assessment following the completion of the final closeout inspections. The inspectors observed that the as-left conditions in the containment were consistent with the conditions documented in the licensees final containment closeout inspection and the plants design basis. The inspectors closeout assessment included as-left condition of the containment sumps, sump screens, configuration of reactor cavity drain, containment coatings, piping insulation, and post-LOCA drainage paths.

Based on inspector observations of the sump screen design, the inspectors determined two design attributes of the sump screens to be worthy of mention. First, the inspectors noted the relatively small surface area of the sump screens. The designed gross surface area of the sump screen was calculated to be 54.8 square feet. This results in an actual flow area of 38 square feet when the area of the screen blocked by level instruments and by the screen bars were subtracted.

Second, the recirculation sump screen was designed with only one screen with a mesh size (opening size) that measures 3/4 (0.750) of an inch by 3-11/16 (3.6875) inches.

Based on the inspectors experience this appeared to be a very large mesh size for this application. Comparing the recirculation sump screen mesh size to the smaller opening sizes associated with ECCS equipment and fuel element upper and lower nozzles reveals the potential for flow blockage. For example, the residual heat removal heat exchanger tube inside diameter measures 0.652 inches, safety injection orifices and throttle valves opening measures 0.54 inches, fuel assembly top nozzle opening measures 0.472 inches, and fuel assembly bottom nozzle opening measures 0.188 inches. Based on the large screen opening size, the potential for excessive screen plugging with debris is minimized at the expense of an increase in potential for debris ingestion into emergency core cooling and the reactor coolant systems.

Based on discussion with the licensee, review of the licensee response to Bulletin 2003-01, and review of interim compensatory actions implemented, the licensee has recognized the potential for debris ingestion and potential flow blockage of ECCS equipment and fuel elements. The compensatory measures specified in the licensees 60-day response letter to Bulletin 2003-01 were verified as completed by the inspectors during this inspection.

In the licensees response to Bulletin 2003-01 the licensee committed to perform an evaluation to analyze the emergency core cooling system recirculation functions with respect to the potentially adverse post-accident debris blockage effects on the containment sump. The licensee plans to work with NEI and implement the methodology developed by NEI to resolve Generic Safety Issue 191, if appropriate for Prairie Island.

.2 (Closed) Unresolved Item (URI)05000282/2003005-01; 05000306/2003005-01:

Resolution of Questions Associated with the Tornado Design of the Auxiliary and Turbine Buildings.

The licensee referenced Calculation 02Q0357-C-001, Assessment of Old Service Building for Seismic and Tornado Loads in two operability evaluations concerning the turbine and auxiliary building structures. At the time of the inspection, questions regarding the adequacy of the calculation were raised by the inspectors and the issue was identified as a unresolved item. During this current inspection period, the inspectors reviewed additional building specific calculations for the Unit 1 and 2 turbine and auxiliary buildings which the licensee had completed to determine structural integrity of the turbine and auxiliary buildings. Additional documents reviewed by the inspectors are listed in the Attachment. Based on this additional review, the inspectors had no further questions or concerns. This unresolved item is considered closed.

.3 (Closed) URI 05000282/2000013-05; 05000306/2000013-05: Unable to Determine the

Safety Significance of the Failure to Analyze Cooling Water Flow to Assure Adequate Cooling during the Recirculation Phase of a loss of coolant accident (LOCA).

A concern was identified regarding the licensees failure to analyze cooling water flow upon loss of air to certain temperature control valves to assure adequate cooling during the recirculation phase of a LOCA. The inspectors questioned how other safety related heat loads would be affected and how adequate cooling water flow could be assured for these loads during the recirculation phase. This matter was considered an unresolved item pending completion of an analysis to verify that recirculation phase heat loads would be adequately supported.

The licensee performed additional calculations which demonstrated adequate cooling water flow to safeguards loads during the recirculation phase of a LOCA. The inspectors reviewed the subsequent calculations and had no further concerns. The documents reviewed during this followup inspection are listed in the Attachment. This item is closed.

.4 (Discussed) URI 05000282/2000013-06; 05000306/2000013-06. Unable to Determine

the Validity of the Practice of, After a Seismic Event, Using Assumptions for Through Wall Leakage Rather Than Complete Pipe Severance A concern was identified regarding the inability to determine the validity of the practice of, after a seismic event, using assumptions for through wall leakage of non-seismically designed piping rather than complete pipe severance. The inspectors questioned the use of this design approach for non-seismically designed piping and were unable to determine the validity of the licensees assumption. Pending review and evaluation of this assumption by NRC headquarters personnel, this issue was considered unresolved.

On May 3, 2004, the licensee submitted a license amendment request pursuant to 10 CFR 50.90, to define a hydraulic analysis methodology for demonstrating functionality of the cooling water system following a design basis seismic event and to define acceptance criteria from the ASME Section III Code, Subsection ND, for stress analysis of the cooling water system non-Class I piping with design basis seismic loads.

This item remains open pending NRR review and evaluation of the licensees submital.

.5 Review of Strike Contingency Plans and Preparation for Potential Work Disruption

(92709)

a. Inspection Scope

The inspectors completed review of the licensees activities to prepare for a potential work disruption after it became evident that little progress was made towards reaching an initial labor contract agreeable to both NMC management and engineers represented by the International Brotherhood of Electrical Workers, Local 949. The inspectors reviewed the licensees contingency staffing plans for operations, maintenance, security, emergency preparedness, and other plant departments. The inspectors also reviewed projected work schedules and use of overtime; preparatory communications with offsite law enforcement agencies and other emergency services; and planned communications with public media.

b. Findings

No findings of significance were identified.

4OA6 Meeting(s)

.1 Exit Meeting

The inspectors presented the inspection results to Mr. J. Solymossy and other members of licensee management at the conclusion of the inspection on October 8, 2004. The inspectors 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:

• Occupational Radiation Safety Access Control and Public Radiation Safety Gaseous and Liquid Effluent Treatment and Monitoring Systems with Mr. J. Solymossy on July 30, 2004.

• Occupational Radiation Safety Access Control and Public Radiation Safety Gaseous and Liquid Effluent Treatment and Monitoring Systems with Mr. R. Graham on September 24, 2004.

• Licensed operator medical issue via telephone with Mr. G. Salamon on September 17, 2004.

4OA7 Licensee-Identified Violations

The following violation of very low significance was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Manual, NUREG-1600, for being dispositioned as an NCV.

Cornerstone: Barrier Integrity

Condition Prohibited by TSs Caused by Miscalibration Prairie Island TS 3.3.6 requires that two channels of control room special ventilation system actuation instrumentation shall be operable in Modes 1, 2, 3, 4, and during movement of irradiated fuel assemblies. Contrary to the above, between March 1, 2004, until April 20, 2004, the licensee identified that both channels of control room special ventilation system radiation monitoring instrumentation (RM-23 and RM-24) were inoperable because they were calibrated with the wrong setpoint and the required actions for Condition A and B were not completed within the required completion time.

The licensee recalibrated the radiation monitors, and entered the condition into their corrective action program. (This event was discussed in Section 4OA3 of this report.)

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Allen, Outage and Scheduling Manager

D. Anderson, Engineering Design Manager

J. Anderson, Radiation Protection Manager

T. Bacon, Operations Training Supervisor

S. Cook, Nuclear Oversight Manager

R. Graham, Director of Operations

D. Herling, Assistant Operations Manager

P. Huffman, Operations Manager

J. Lash, Training Manager

S. McCall, Engineering Programs Manager

C. Mundt, Engineering Plant and Systems Manager

S. Northard, Business Support Manager

A. Qualantone, Security Manager

G. Salamon, Regulatory Affairs Manager

T. Silverberg, Site Engineering Director

J. Solymossy, Site Vice President

T. Taylor, Performance Assessment Manager

M. Werner, Plant Manager

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000282/2004007-01; NCV Failure to Inform the NRC Within 30 Days of a Change

05000306/2004007-01 in Medical Status of a Licensed Operator in Accordance with 10 CFR 50.74(c)

05000282/2004007-02 FIN Containment fan coil units not tested in accordance with Generic Letter 89-13 commitments

Closed

05000282/2000013-05; URI Unable to Determine the Safety Significance of the

05000306/2000013-05 Failure to Analyze Cooling Water Flow to Assure Adequate Cooling During the Recirculation Phase of a LOCA

05000282/2003005-01; URI Resolution of Questions Associated with the Tornado

05000306/2003005-01 Design of the Auxiliary and Turbine Buildings

05000282/2004-001-00 LER Condition Prohibited By TSs Caused by Miscalibration Attachment

Discussed

05000282/2000013-06; URI Unable to Determine the Validity of the Practice of, After

05000306/2000013-06 a Seismic Event, Using Assumptions for Through Wall Leakage Rather Than Complete Pipe Severance Attachment