IR 05000282/2004003

IR 05000282-04-003 & IR 05000306-04-003, on 01/01/2004 Through 03/31/2004, for Prairie Island Nuclear Generating Plant, Units 1 & 2; Operator Performance During Non-Routine Evolutions & Events

ML041200487
Person / Time
Site:	Prairie Island
Issue date:	04/28/2004
From:	Gruss K NRC/RGN-III/DRP/RPB5
To:	Solymossy J Nuclear Management Co
References
IR-04-003
Download: ML041200487 (46)

Text

April 28, 2004

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000282/2004003; 05000306/2004003

Dear Mr. Solymossy:

On March 31, 2004, the U. S. Nuclear Regulatory Commission (NRC) completed a baseline inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on April 8, 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, one self-revealing finding of very low safety significance that involved a violation of NRC requirements was identified. However, because the violation was of very low safety significance and the issue was entered into your corrective action process, the NRC is treating the finding as a Non-Cited Violation in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest the subject or severity of a 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/

Kimberly A. Gruss, Chief Branch 5 Division of Reactor Projects Docket Nos. 50-282; 50-306 License Nos. DPR-42; DPR-60

Enclosure:

Inspection Report 05000282/2004003; 05000306/2004003 w/Attachment: Supplemental Information

REGION III==

Docket Nos:

50-282; 50-306 License Nos:

DPR-42; DPR-60 Report No:

05000282/2004003; 05000306/2004003 Licensee:

Nuclear Management Company, LLC Facility:

Prairie Island Nuclear Generating Plant, Units 1 and 2 Location:

1717 Wakonade Drive East Welch, MN 55089 Dates:

January 1 through March 31, 2004 Inspectors:

J. Adams, Senior Resident Inspector S. Burton, Senior Resident Inspector, Monticello D. Karjala, Resident Inspector B. Winter, Reactor Engineer Approved by:

Kimberly A. Gruss, Chief Branch 5 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000282/2004003, 05000306/2004003; 01/01/2004 - 03/31/2004; Prairie Island Nuclear

Generating Plant, Units 1 & 2; Operator Performance During Non-Routine Evolutions and Events.

This report covers a 3-month period of baseline resident inspection and an announced baseline inspection for the Periodic Evaluation of Maintenance Rule Implementation. The inspections were conducted by resident inspectors and inspectors from the Region III office. One green finding was identified. The significance of most findings is indicated by their color (Green,

White, Yellow, Red) using Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the significance determination process 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: Barrier Integrity

Green.

A finding of very low safety significance associated with exceeding Technical Specification (TS) and Pressure Temperature Limits Report (PTLR) limits was self-revealed. Technical Specification 3.4.3 requires that reactor coolant system (RCS)temperature be maintained within the limits of the PTLR. Section 3.0 of the PTLR requires that RCS temperature remain above 86 degrees Fahrenheit when the RCS is not vented. On December 1, 2002, with Unit 1 in Mode 5, and the RCS not vented, the reactor coolant pumps were started causing RCS temperature to drop below 86 degrees Fahrenheit. Action statement C.2 of TS 3.4.3 requires that the RCS be evaluated for acceptability for continued operation prior to entering Mode 4. Operators placed Unit 1 in Mode 4 without completing the required evaluation. Upon identification of the failure to meet the criteria contained in action statement C.2 of TS 3.4.3, the licensee performed the required evaluation to demonstrate the acceptability of continued operation. This finding also affected the cross-cutting areas of human performance and problem identification and resolution. Operators and engineers failed to recognize the violation of TS 3.4.3 and PTLR limits associated with RCS temperatures, and failed to recognize and implement the TS-required actions prior to a change in Mode.

Additionally, supervisors and plant managers failed to recognize the significance of the event and assign an appropriate priority during the corrective action screening process.

This issue was more than minor since the finding could be reasonably viewed as a precursor to a significant event such as the degradation or failure of the reactor pressure vessel. The finding was determined to be not suitable for significance determination process evaluation. NRC management reviewed the finding for significance and determined it to be of very low safety significance based on engineering evaluation conclusions that the limiting vessel baseline material stresses remained within allowable limits. Therefore, the deficiency was confirmed not to result in loss of function per Generic Letter 91-18. This finding resulted in a Non-Cited Violation of TS 3.4.3 which required the RCS be evaluated for acceptability for continued operation prior to entering Mode 4 when temperature limits contained in the PTLR are exceeded. (Section 1R14)

Licensee-Identified Violations

One 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 operated at or near full power until February 20, 2004, when power was reduced to approximately 45 percent of full power to allow condenser water box cleaning, amertap repair, turbine control valve maintenance and testing, and to search for condenser tube leaks. Unit 1 returned to full power on February 23, 2004, where it remained through the remainder of the period.

Unit 2 operated at or near full power for the entire period.

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, Barrier Integrity, and

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

.1 Post-Maintenance Testing

a. Inspection Scope

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

• D6 emergency diesel generator following corrective maintenance to the overspeed stopping jack on January 5, 2004;

• 12 diesel-driven cooling water pump following maintenance on January 27, 2004;

• 12 DDCLP bearing water supply three-way valve on January 29, 2004;

• D2 emergency diesel generator following completion of the 18-month preventive maintenance on the engine and generator on March 11, 2004; and

• 11 shield building special ventilation system following the calibration of the exhaust filter temperature switch on March 16, 2004.

During the performance of these inspections, the inspectors conducted in-plant observation 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 (CAP).

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 five inspection samples, comprised of the following surveillance testing activities:

• SP 1093, D1 Diesel Generator Monthly Slow Start Test, on January 26, 2004;

• SP 1102, 11 Turbine-Driven Auxiliary Feedwater (AFW) Pump Monthly Test, on January 30, 2004;

• SP 2155B, Component Cooling (CC) System Quarterly Test, on February 5, 2004;

• SP 2335, D6 Diesel Generator 24-Hour Load Test, on March 1, 2004; and

• SP 1306, D2 Diesel Generator 18-Month Relay Functional Test, performed on March 10, 2004.

Observation of surveillance testing activities associated with licensee SP 1102 completed the quarterly baseline inspection requirement to observe an inservice testing activity for a risk significant pump or valve.

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 (TSs),

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 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 (CA) 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 Alignment Inspections

a. Inspection Scope

During this inspection period, the inspectors completed three inspection samples, comprised of partial in-plant walkdowns of accessible portions of trains of risk-significant mitigating systems during times when the trains were of increased importance due to the unavailability of the alternate train. The inspectors verified the alignment of the following plant equipment:

• D6 emergency diesel generator during the unavailability of the D5 emergency diesel generator for planned maintenance on January 21, 2004;

• D2 emergency diesel generator during the unavailability of the D1 emergency diesel generator for planned maintenance on February 17, 2004; and

• 22 CC water pump during the unavailability of the 21 CC water pump for planned maintenance on March 16, 2004.

The inspectors utilized the licensees applicable valve and electric breaker alignment checklists to verify that the components and required support systems were properly positioned to support the proper operation of the inspected systems. 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 (WO) and AR 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 documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Complete System Alignment Inspection

a. Inspection Scope

During the week of January 18, 2004, the inspectors performed a detailed in-plant walkdown of the alignment and condition of the Unit 2 Auxiliary Feedwater system, a risk significant system that provides decay heat removal during normal, 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 Auxiliary Feedwater 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 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 AR CAP items 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 AR CAP items to verify that the licensee was identifying issues at an appropriate threshold and entering them into their CA program in accordance with station CA 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 in the document action for 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 eight fire areas were inspected by in-plant walkdowns supporting the completion of eight fire protection zone walkdown samples:

• Fire Area 25, Unit 1, D1 emergency diesel generator room on January 16, 2004;

• Fire Area 31, Unit 1 auxiliary feedwater pump and instrument air compressor room on January 16, 2004;

• Fire Area 32, Unit 2 auxiliary feedwater pump and instrument air compressor room on January 16, 2004;

• Fire Area 41A, diesel-driven cooling water pump area of the screenhouse on January 20, 2004;

• Fire Area 81, Unit 1 bus 15, 4160 volt switchgear room on January 16, 2004;

• Fire Area 113, Unit D5 emergency diesel generator fuel oil day tank room on January 20, 2004;

• Fire Area 115, Unit D5 emergency diesel generator lubricating oil storage tank room on January 20, 2004; and

• Fire Area 117, Unit 2 bus 25, 4160 volt switchgear room on January 20, 2004.

The inspectors also reviewed the AR CAP items listed in the Attachment to verify that the licensee was identifying fire protection issues at an appropriate threshold and entering them into their CA program in accordance with station CA procedures.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors performed an in-office review of the most recently completed SP for the inspection of plant flooding barriers and the abnormal procedure for flooding. The contents of these documents were compared to the plant flood protection design sections in the USAR and the assumption contained in the IPEEE associated with external flooding event. This inspection effort completed the annual external flood protection inspection sample.

The inspectors performed a physical inspection of flood protection barriers in the Auxiliary Building, Turbine Building, D5/D6 Building, and the Old Screenhouse during the period of March 3 through 11, 2004, comparing the as-found conditions of the flood protection panels against the acceptance criteria in the SP. The inspectors also verified that the actions specified in the abnormal procedure for flooding could be performed in a timely manner (3 days) if required, and the necessary hardware and consumable materials were available and still within their shelf life.

The inspectors reviewed several AR CAP items to verify that minor deficiencies identified during this inspection were entered into the licensees CA program, that problems associated with plant equipment relied upon to prevent or minimize flooding were identified at an appropriate threshold, and that CAs commensurate with the significance of the issue were identified and implemented. As part of this inspection, the inspectors reviewed the documents listed in the Attachment.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

On March 1, 2004, the inspectors performed a quarterly review of Crew 6 during licensed operator requalification training in the simulator, completing one licensed operator requalification inspection sample. The inspectors observed a training crew 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 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 operated 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 TSs, simulator fidelity, and licensee critique of performance. The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Biennial Maintenance Effectiveness Periodic Evaluation

a. Inspection Scope

The inspectors examined the periodic evaluation reports completed for calendar years 2002 and 2003. To evaluate the effectiveness of (a)(1) and (a)(2) activities, the inspectors examined a number of Prairie Island (a)(1) Action Plans, Functional Failures, and CAP reports. The inspectors reviewed these same documents to verify that the threshold for identification of problems was at an appropriate level and the associated CAs were appropriate. Also, the maintenance rule program documents were reviewed.

The inspectors reviewed the following systems, completing four inspection procedure samples:

• AFW Auxiliary Feedwater;

• DG Emergency Diesel Generator;

• EA 4160 Vac; and

• CC CC Water.

The inspectors verified that the periodic evaluation was completed within the time restraints defined in 10 CFR 50.65 (once per refueling cycle, not to exceed 2 years).

The inspectors also determined that the licensee reviewed its goals, monitored Structures, Systems, and Components (SSCs) performance, reviewed industry operating experience, and made appropriate adjustments to the maintenance rule program as a result of the above activities.

The inspectors verified that the licensee balanced reliability and unavailability of SSCs including safety significant systems during the previous refueling cycle.

The inspectors verified that (a)(1) goals were established and CAs were appropriate to address the causes for SSCs being in (a)(1) category, including the use of industry operating experience, and that (a)(1) activities and related goals were adjusted as needed.

The inspector verified that the licensee has established (a)(2) performance criteria, examined any SSCs that failed to meet their performance criteria, and reviewed any SSCs that have suffered repeated maintenance preventable functional failures including a verification that failed SSCs were considered for (a)(1).

In addition, the inspectors reviewed maintenance rule self-assessments that addressed the maintenance rule program implementation. The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Quarterly Maintenance Effectiveness Assessments

a. Inspection Scope

The inspectors performed one issue/problem-oriented maintenance effectiveness inspection of repetitive pump seal failures on safety-related pumps and two structures, systems, or components function-oriented maintenance effectiveness inspections associated with the annunciator and CC water systems. The inspectors selected these structures, systems, or components for review because of their designation as high risk significant systems in the Maintenance Rule. Additionally, the annunciator system and several safety-related pumps had recently experienced repetitive problems. This inspection effort constituted three maintenance effectiveness inspection samples.

The inspectors reviewed maintenance activities to assess maintenance effectiveness, including maintenance rule activities, work practices, and the evaluation of issues for common cause. Inspection activities included, but were not limited to, the licensees categorization of specific issues including evaluation of performance criteria, appropriate work practices, identification of common cause errors, extent of condition, and trending of key parameters. Additionally, the inspectors reviewed implementation of the Maintenance Rule (10 CFR 50.65) requirements, including a review of scoping, goal-setting, performance monitoring, short-term and long-term CAs, functional failure determinations associated with reviewed condition reports, and current equipment performance status.

For each system reviewed, the inspectors reviewed significant WOs and AR CAP items to verify that failures were properly identified, classified, and corrected, and that unavailable time had been properly calculated. The inspectors reviewed CA documents to verify that the licensee was identifying maintenance effectiveness and maintenance rule issues at an appropriate threshold and entering them into their CA program in accordance with station CA procedures. 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:

• unavailability of the 22 turbine-driven auxiliary feedwater pump and the 22 containment spray pump for planned maintenance on January 8, 2004;

• unavailability of emergency diesel generator D5 and the 21 cooling water pump for planned maintenance on January 20, 2004;

• unavailability of the Unit 2 Reactor Protective System blue channel Overtemperature Delta Temperature and Overpower Delta Temperature trips for emergent maintenance while the 121 safeguards traveling screen, the 121 and 122 intake bypass gates, and the 124 air compressor were unavailable for planned maintenance on February 4, 2004;

• unavailability of the 22 CC pump and heat exchanger, the 121 safeguards traveling screen, the 121 and 122 intake bypass gates, and the 124 air compressor for planned maintenance on February 5, 2004;

• unavailability of the 12 residual heat removal (RHR) pump, the 121 safeguard traveling screen, and the 122 air compressor for planned maintenance on February 11, 2004; and

• unavailability of the D2 emergency diesel generator, 22 diesel-driven cooling water pump, and the 22 cooling water strainer for planned maintenance on March 9, 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 associated with maintenance activities. 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

a. Inspection Scope

On March 3, 2004, the inspectors reviewed licensee personnel performance during a December 1, 2002, transient that resulted in Unit 1 reactor coolant system (RCS)temperature reduction below the limits of the PTLR as reported in Licensee Event Report 2002-03-00. The review constituted one inspection procedure sample. The inspectors conducted an in-office review of documents associated with the event and discussed the event with engineering and operations personnel. The inspectors compared the actions of plant personnel to the action required by TS and plant procedures. The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

Introduction During an RCS fill and vent evolution with the reactor in Mode 5, the start of a reactor coolant pump (RCP) caused the RCS temperature to drop below the PTLR limit of 86 degrees Fahrenheit. Subsequently, operators took the reactor to Mode 4 without performing the TS-required evaluation of RCS acceptability for continued operation, resulting in a self-revealing finding of very low safety significance and a Non-Cited Violation of TS requirements.

Description On December 1, 2002, with the reactor in Mode 5 during an RCS fill and vent evolution, the start of an RCP caused the RCS temperature to drop below 80 degrees Fahrenheit.

Technical Specification 3.4.3 required that RCS temperature be maintained within the limits of the PTLR. Section 3.0 of the PTLR requires that RCS temperature remain above 86 degrees Fahrenheit when the RCS is not vented. This condition existed for about 56 hours6.481481e-4 days <br />0.0156 hours <br />9.259259e-5 weeks <br />2.1308e-5 months <br />. The drop in RCS temperature below the PTLR limits required that the licensee evaluate the RCS for acceptability for continued operation before entering Mode 4. Unit 1 entered Mode 4 on December 3, 2002. The TS condition was not recognized by plant operators and the required action was not completed prior to entering Mode 4.

A Unit 2 reactor operator, who observed the RCP start, questioned the decrease of Unit 1 RHR inlet temperature below 86 degrees Fahrenheit and pointed it out to the Unit 1 operators. This prompted a discussion among the Unit 1 operating crew. The operators erroneously determined that temperature drop was not a concern since this was a transient condition and not representative of bulk coolant temperature. As such, senior licensed operators failed to recognize that TS limits had been exceeded.

The Unit 2 reactor operator accepted the transient temperature justification with reservations and on December 6, 2002, submitted AR CAP 027064 questioning whether the plant was operating in a conservative manner by starting RCPs at a temperature low enough to cause the resulting transient temperature to go below the 86 degrees Fahrenheit PTLR limit. The licensees root cause report indicated that the reactor operators intent in writing this AR CAP was not to report a potential TS violation.

Following the Submittals of AR CAP 027064, multiple opportunities were missed by plant operations and engineering personnel to recognize the TS violation. For example:

• on December 6, 2002, the Shift Manager performed an operability screening of AR CAP 027064 and failed to recognize the TS violation;

• on December 12, 2002, the participants of the operations focus meeting (all senior licensed personnel) failed to recognize the TS violation;

• on December 12, 2002, the event screening committee, a technically diverse group of senior personnel, failed to recognize the TS violation; and

• on December 10, 2002, through October 22, 2003, engineering personnel involved in the event evaluation and assessment specified in condition evaluation (CE) 001649, and the identification and implementation of CAs specified in CA 003778, failed to recognize the TS violation.

The AR CAP 027064 was closed on November 17, 2003. On November 29, 2003, the operator that initiated AR CAP 027064 reviewed the CA taken and initiated an AR CAP 034273 questioning the correctness of a formula that was provided by engineering for the calculation of the RCS bulk average coolant temperature and the resolution of all concerns from his original AR CAP.

On December 31, 2003, an engineer involved in the development of the original PTLR reviewed the CE 004228 resulting from AR CAP 034273. This engineer recognized that the RCS bulk average coolant temperature was not a valid parameter for the representation of the reactor vessel balkline material temperature. The System Engineering Manager then concluded that there had been a violation of TS 3.4.3. The licensee wrote AR CAP 034715 entering the condition into the CA program and performed an engineering evaluation to assess the acceptability of the reactor vessel integrity for continued operation. Resident and Regional inspectors reviewed the licensees evaluation using inspection procedure 71111.15. (Section 1R15)

Analysis The inspectors determined that the failure of operators and engineers to recognize the exceeding of TS 3.4.3 and PTLR limits without implementing the specified actions affected the barrier integrity cornerstone, thus warranting evaluation for significance.

The inspectors determined that the finding was more than minor in accordance with Inspection Manual Chapter 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on June 20, 2003. Specifically, the finding could be reasonably viewed as a precursor to a significant event, such as the degradation or failure of the reactor pressure vessel. In this specific case, RCS temperature went below the temperature for which the Overpressure protection system was analyzed in the PTLR. At the time that the temperature transient occurred, the reactor vessel was not vented and was nearly water-solid. Any high pressure injection of water into the RCS could have rapidly resulted in a Overpressure condition exceeding the maximum allowable stresses of the reactor vessel balkline material.

This finding affected the cross-cutting areas of human performance. The licensees root cause evaluation identified, as a primary cause, human performance deficiencies.

Specifically, the operators lacked sufficient knowledge to prevent a temperature transient during RCP start which resulted in RCS temperature below the limit required by the PTLR. Additionally, operators did not recognize or evaluate the impact of the low temperature condition as required by TS 3.4.3.

This finding also affected the cross-cutting areas of problem identification and resolution. Specifically, the condition occurred on December 1 but was not entered into the CA program until December 6, 2002; the AR CAP was screened as a significance level C (condition adverse to quality) and should have been a significance level B (significant condition adverse to quality); the CE was not completed until November 11, 2003; the initial evaluation did not adequately address the issues, resulting in the originator of the initial AR CAP to initiate another AR CAP on November 29, 2003; and the second AR CAP was also inappropriately screened as a significance level C.

The inspectors attempted to evaluate the finding using the Inspection Manual Chapter 0609, Significance Determination Process (SDP), Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations, issued on March 18, 2002. Since the finding was associated with a challenge to RCS barrier, the Phase 1 SDP worksheets specified that a Phase 2 SDP be performed.

However, the Phase 2 SDP does not model degradation or failure of the RCS and could not be used to evaluate the significance of this issue.

The inspectors reviewed the licensees evaluation that justified the acceptability of the reactor vessel for continued operation. The licensee concluded that the limiting vessel baseline material stresses remained within allowable limits since excessive RCS pressure did not exist concurrently with the low RCS temperatures. Therefore, the deficiency was confirmed not to result in loss of function per Generic Letter 91-18. In the case of a mitigating system this would result in a finding of very low safety significance using the Phase 1 SDP worksheet. Applying this logic to the barrier integrity cornerstone, one can reasonably conclude that this finding was also of very low safety significance. Since the finding was not suitable for SDP evaluation, NRC management reviewed the finding for significance and determined it to be of very low safety significance (Green).

Enforcement Prairie Island TS 3.4.3 requires that RCS temperature be maintained within the limits of the PTLR. Section 3.0 of the PTLR requires that RCS temperature remain above 86 degrees Fahrenheit when the RCS is not vented. On December 1, 2002, with Unit 1 in Mode 5, and with the RCS not vented, the RCPs were started causing RCS temperature to drop below 86 degrees Fahrenheit. The action specified in action statement C.2 of TS 3.4.3 requires that the RCS be evaluated for acceptability for continued operation prior to entering Mode 4. Contrary to the above, Unit 1 entered Mode 4 on December 3, 2002, without completing the required evaluation. Upon identification of the failure to meet the criteria contained in action statement C.2 of TS 3.4.3 on December 31, 2003, the licensee performed the required evaluation to justify the acceptability of continued operation. This evaluation was documented in operability recommendation (OPR)000468 and was completed on December 31, 2003. Because this violation was of very low safety significance, and the licensee entered the condition into their CA program with AR CAP 034715, this violation is being treated as an NCV in accordance with VI.A.1 of the NRCs Enforcement Policy (NCV 05000282/2004003-01).

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the technical adequacy of eight operability evaluations completing eight operability evaluation inspection procedure 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 structures, systems, or components 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:

• Operability Recommendation 468, which was performed in response to Unit 1 RCS temperature exceeding the PTLR RCS Temperature Limit during refueling outage 1R22 on January 6, 2004;

• prompt operability evaluation documented in AR CAP 033846, which determined that the D5 emergency diesel generator remained operable with the D5 ventilation system recirculation damper inoperable on January 22, 2004;

• Operability Recommendation 441 documenting the operational acceptability of the voltage applied to relays in the turbine-driven auxiliary feedwater pump control circuit during the design basis events on February 3, 2004;

• independent assessment of the operability of the 22 DDCLP with the 21 scavenging and combustion air damper failed in open position for WO 0305054 on February 12, 2004;

• OPR 473 documenting the operational acceptability of the floor load capacity of the 755 foot elevation of the Unit 2 auxiliary building on March 16, 2004;

• OPR 478 documenting the acceptability of the current auxiliary feedwater pump suction pressure switch setpoint assuming the failure of the condensate storage tanks following a seismic event or tornado on March 17, 2004;

• the historical assessment of operability for mitigating equipment down stream of high energy line break dampers CD-34197 and CD-34198 including the 12, 21, and 22 safety-related batteries and the 12 and 22 auxiliary feedwater pumps on March 24, 2004; and

• evaluation of technical support center (TSs) operability and Reportability after the TSS was unable to meet the acceptance criteria during the performance of ventilation testing on March 29, 2004.

The inspectors also reviewed several AR CAP items documenting degraded conditions to verify that the licensee was identifying issues at an appropriate threshold and entering them into their CA program in accordance with station CA procedures. The documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R16 Operator Workarounds (OWAs)

.1 Review of Selected Workarounds

a. Inspection Scope

On January 26, 2004, inspectors conducted an in-office review of an OWA associated with emergency diesel generators D1 and D2, completing one inspection procedure sample. On January 26, 2004, the inspectors observed a monthly surveillance of D1, and noted that for the first 30 minutes of the diesel operation, there was considerable smoke in the room from the leaks in the engine exhaust manifold. Inspectors were told that this occasionally results in fire alarms in the control room. The inspectors reviewed the situation to determine whether the condition should be considered an OWA. A detailed list of the documents reviewed during this inspection is included at the end of this report.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed design change 02EM01, which replaced the control room steam generator level chart recorders with paperless recorders, completing one permanent plant modification inspection procedure sample. The recorders replaced were four wide range and two narrow range steam generator level recorders for each unit. The recorders were qualified as Regulatory Guide 1.97 control room instrumentation. The replacement recorders display steam generator levels on an illuminated color screen and the data is stored in an internal memory. The inspectors performed an in-office review of the design change package and an in-plant review of the control room installation. A detailed list of the documents reviewed is included in the

.

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 one temporary modification. This inspection effort completes one temporary modification inspection procedure sample. The documents reviewed by the inspectors are listed in the

.

The inspectors reviewed the temporary modification 98T059 that failed open the three-way cooling water valve to the RHR motor coolers. 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 AR CAP items to verify that the licensee was identifying issues at an appropriate threshold and entering them into their CA program in accordance with station CA.

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 March 1, 2004, completing one emergency planning simulator exercise sample. The inspectors observed activities in the control room simulator, attended the post-exercise critique, and reviewed the final exercise critique report. 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 CA program.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

Cornerstone: Mitigating Systems

a. Inspection Scope

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

.

The inspectors used performance indicator guidance and definitions contained in Nuclear Energy Institute 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 AR CAP items listed in the Attachment to this report to verify that the licensee was identifying issues at an appropriate threshold and entering them into their CA program in accordance with station CA.

The licensees reports of the following performance indicators were verified:

Unit 1

• Safety System Unavailability - Auxiliary Feedwater System for the 1st quarter 2003 through the 4th quarter 2003; and

• Safety System Unavailability - High Pressure Safety Injection for the 1st quarter 2003 through the 4th quarter 2003.

Unit 2

• Safety System Unavailability - Auxiliary Feedwater System for the 1st quarter 2003 through the 4th quarter 2003; and

• Safety System Unavailability - High Pressure Safety Injection for the 1st quarter 2003 through the 4th quarter 2003.

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

The inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that the licensee entered issues into its CA system at an appropriate threshold, that adequate attention was given to timely CAs, and that adverse trends were identified and addressed. The inspectors also performed a screening review of items entered into the CA program and observed daily CA program meetings to identify conditions that warranted additional follow-up.

b. Findings

No findings of significance were identified.

.2 Annual Sample Review

a. Inspection Scope

During the week ending January 31, 2004, the inspectors selected a CA program issue for detailed review which constituted one annual problem identification and resolution inspection procedure sample. The inspectors selected continuing configuration control problems for review. Two AR CAP items issued in 2003, identifying adverse trends in the DISPOSITIONING of plant equipment, historical CA program documents, and other CA program documents linked to those documents, were reviewed to assess the effectiveness of the licensees efforts to correct the problem. Of the documents reviewed by inspectors, particular attention was placed on the review of the licensees CAs taken to address the noted deficiencies and the licensees effectiveness reviews.

The inspectors also ensured that the licensee had identified the full extent of the issue, conducted an appropriate evaluation, and that licensee-identified CAs were appropriately prioritized. The inspectors compared the licensees actions taken to address the issue against the requirements of the licensees CA program as specified in Administrative Work Instruction 5AWI 16.0.0, Action Request Process; Performance Assessment Fleet Procedure FP-PA-ARS-01, Action Request Process; Administrative Work Instruction 5AWI 15.0.2, WO Codes; and 10 CFR Part 50, Appendix B. A complete list of the documents reviewed is included in the Attachment.

b. Findings and Observations

The inspectors did not identify any findings associated with the review of this sample.

However, the inspectors noted that the licensees CAs have not been fully effective in the elimination of DISPOSITIONING events. The inspectors observed that the number of events had declined during 2002 but trended upward in 2003. The licensee identified and documented the upward trend with two AR CAPs, analyzed and compared the circumstances associated with recent individual DISPOSITIONING events, and identified and implemented new and unique CAs. The licensee continues to actively monitor the effectiveness of the CAs implemented in 2003.

4OA3 Event Followup

.1 (Closed) LER 2002-03-00:

Unit 1 - Failure to Meet TS Limiting Condition for RCS Pressure and Temperature Limits On December 1, 2002, with Unit 1 in Mode 5, RCS temperature dropped below 80 degrees Fahrenheit in response to starting the RCPs. Technical Specification 3.4.3 requires that the RCS temperature be maintained within the limits of the PTLR at all times. Section 3.0 of the PTLR requires that the RCS temperature remain above 86 degrees Fahrenheit when not vented. Action Statement C.2 for TS 3.4.3 specified evaluating the RCS acceptability for continued operation before entering Mode 4. The TS condition was not recognized and the required action was not completed prior to entering Mode 4.

The failure to perform the evaluation constituted a finding of more than minor significance. The LER was reviewed by the inspectors and a finding of very low safety significance was identified resulting in a Non-Cited Violation of NRC requirements.

(Section 1R14)

.2 Auxiliary Feedwater Pump Suction Switch Miscalibration Event

a. Inspection Scope

On January 12, 2004, the licensee identified during a routine surveillance that the auxiliary feedwater pump suction switches had been miscalibrated. Early extent of CE by the licensee determined that the 11, 12, and 21 auxiliary feedwater pump suction switches had been incorrectly calibrated in the non-conservative direction during their previous calibration. The inspectors observed the licensees immediate CAs to establish at least one operable auxiliary feedwater pump for each unit. The inspectors verified that the licensee understood the potential significance of the miscalibration error and were taking prompt action to restore the auxiliary feedwater pump pressure switch setpoints to within tolerance. The inspectors reviewed the subsequent historical operability evaluation (Section 1R15 and 4AO7) that demonstrated that the as-found calibration of the miscalibrated suction switches did not result in loss of function of the affected auxiliary feed water pumps.

b. Findings

No findings of significance were identified.

4OA4 Cross-Cutting Aspects of Findings

.1 A self-revealing finding described in Section 1R14 of this report was attributed to, as a

primary cause, human performance deficiencies, in that the operators failed to recognize and prevent a temperature transient during an RCP start. This resulted in RCS temperature falling below the limit required by the PTLR. Additionally, operators did not recognize or evaluate the impact of the low temperature condition as required by TS 3.4.3.

The finding also included Problem Identification and Resolution deficiencies. The low temperature condition was identified by an operator on the other unit rather than the operators performing the evolution. The condition occurred on December 1, but was not entered into the CAP until December 6, 2002. The AR CAP was screened as a significance level C which is a condition adverse to quality. The licensees CAP procedure defines significance level B as a condition that is reportable to the NRC as a significant condition adverse to quality. The CE was not completed until November 11, 2003. The initial evaluation did not adequately address the issues, and the originator initiated another AR CAP on November 29, 2003. The second AR CAP was also inappropriately screened as a significance level C. During the review of the evaluation of the second AR CAP, the significance of the condition was finally recognized, resulting in an OPR, root cause evaluation, and LER.

40A5 Other Activities

.1 (Closed) Temporary Instruction (TI) 2515/154:

Spent Fuel Material Control and Accounting at Nuclear Power Plants. The inspectors completed Phase I of the subject TI and provided the appropriate documentation to NRC management as required by the TI.

4OA6 Meeting(s)

.1 Interim Exit Meeting

An interim exit meeting was conducted for the Maintenance Effectiveness Periodic Evaluation inspection with Mr. J. Solymossy, Site Vice President, on March 5, 2004.

.2 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 April 8, 2004. The licensee did not identify any materials examined during the inspection as proprietary in nature.

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 a Non-Cited Violation.

Cornerstone: Mitigating Systems

Auxiliary Feedwater Pump Suction Switch Miscalibration On January 4, 2004, the licensee identified that the 12 auxiliary feedwater pump suction pressure switch had been set incorrectly during its previous calibration. An extent of condition review of the 11, 21, and 22 auxiliary feedwater pump pressure switches revealed that the 11 and 21 auxiliary feedwater pump suction pressure switches had also been set incorrectly. The cause of the incorrect pressure switch setting was due to the selection of the improper engineering units on the pneumatic calibrator. Title 10, CFR Part 50, Appendix B, Criterion V, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures or drawings of a type appropriate to the circumstances. The calibration procedure failed to include a step to verify and, if necessary, set the calibrator to the proper engineering units. The licensee entered these conditions into their CA program with AR CAPs 034864, 034876, 034882, 035302, and 035359. The historical operability of the affected auxiliary feedwater pumps were addressed by CE 004509. Based on the result of the historical operability evaluations, the auxiliary feedwater pumps would have tripped on low suction pressure prior to damaging the auxiliary feedwater pumps by air ingestion. Because the incorrect setting of the auxiliary feedwater pump suction pressure switches did not result in a loss of safety function, this violation is of very low safety significance and is being treated as a Non-Cited Violation.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. Solymossy, Site Vice President

M. Werner, Plant Manager

T. Allen, Outage and Scheduling Manager

R. Best, Maintenance Rule Coordinator

R. Graham, Director of Operations

D. Herling, Assistant Operations Manager

P. Huffman, System Engineering Manager

J. Lash, Training Manager

S. Northard, Director of Engineering

A. Qualantone, Security Manager

G. Salamon, Regulatory Affairs Manager

T. Taylor, Performance Assessment Manager

D. Wilson, System Engineer

P. Zamarripa, System Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000282/2004003-01 NCV Failure to Meet TS Limiting Condition for RCS Pressure and Temperature Limits 50-282/02-003-00 LER Failure to Meet TS Limiting Condition for RCS Pressure and Temperature Limits

Discussed

None.