ML051240352

IR 05000282-05-003, 05000306-05-003; on 01/01/2005 - 03/31/2005; Prairie Island Nuclear Generating Plant, Units 1 and 2; Maintenance Effectiveness and Operability Evaluations

ML051240352
Person / Time
Site:	Prairie Island
Issue date:	04/28/2005
From:	Passehl D NRC/RGN-III/DRP/RPB3
To:	Solymossy J Nuclear Management Co
References
IR-05-003
Download: ML051240352 (39)

See also: IR 05000282/2005003

Text

April 28, 2005

Mr. Joseph Solymossy

Site Vice-President

Prairie Island Nuclear Generating Plant

Nuclear Management Company, LLC

1717 Wakonade Drive East

Welch, MN 55089

SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2

NRC INTEGRATED INSPECTION REPORT 05000282/2005003;

05000306/2005003

Dear Mr. Solymossy:

On March 31, 2005, the U. S. Nuclear Regulatory Commission (NRC) completed an integrated

inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report

documents the inspection findings which were discussed on April 12, 2005, 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). Both findings also resulted in a violation of NRC requirements.

Because these violations were of very low safety significance and were entered into your

corrective action program, the NRC is treating the findings as Non-Cited Violations 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, D.C.

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, D.C. 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

J. Solymossy -2-

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/

David Passehl, Acting Chief

Branch 3

Division of Reactor Projects

Docket Nos. 50-282; 50-306

License Nos. DPR-42; DPR-60

Enclosure: Inspection Report 05000282/2005003; 05000306/2005003

w/Attachment: Supplemental Information

cc w/encl: C. Anderson, Senior Vice President, Group Operations

J. Cowan, Executive Vice President and Chief Nuclear Officer

Regulatory Affairs Manager

J. Rogoff, Vice President, Counsel & Secretary

Nuclear Asset Manager

Tribal Council, Prairie Island Indian Community

Administrator, Goodhue County Courthouse

Commissioner, Minnesota Department

of Commerce

Manager, Environmental Protection Division

Office of the Attorney General of Minnesota

DOCUMENT NAME: G:\prai\pra2005003.wpd

To receive a copy of this document, indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy

OFFICE RIII N RIII N

NAME DPassehl/sls KOBrien (Section

1R15)

DATE 4/28/05 4/28/05

OFFICIAL RECORD COPY

J. Solymossy -3-

ADAMS Distribution:

MLC

RidsNrrDipmIipb

GEG

KGO

JTA

CAA1

C. Pederson, DRS (hard copy - IRs only)

DRPIII

DRSIII

PLB1

JRK1

ROPreports@nrc.gov (inspection reports, final SDP letters, any letter with an IR number)

U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket Nos: 50-282; 50-306

License Nos: DPR-42; DPR-60

Report No: 05000282/2005003; 05000306/2005003

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, 2005

Inspectors: J. Adams, Senior Resident Inspector

D. Karjala, Resident Inspector

B. Winter, Reactor Engineer

Approved by: D. Passehl, Acting Chief

Branch 3

Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000282/2005003, 05000306/2005003; 01/01/05 - 03/31/05; Prairie Island Nuclear

Generating Plant, Units 1 and 2; Maintenance Effectiveness and Operability Evaluations.

This report covers a 3-month period of baseline resident inspection. The inspection was

conducted by the resident inspectors, and an inspector from the Region III office. Two Green

findings were identified. 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: Barrier Integrity

• Green. The inspectors identified a finding of very low safety significance for inadequate

corrective actions associated with the repetitive failure of Unit 1 and 2 containment fan

coil units (CFCUs). Specifically, the licensee failed to identify and correct the root cause

of the accelerated erosion of the CFCUs and to implement effective corrective actions in

a timely manner to preclude repeat failures of these significant conditions adverse to

quality. The finding constituted a Non-Cited Violation of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Actions. The primary cause of this finding was related to the

cross-cutting area of Problem Identification and Resolution (corrective actions) because

the ineffective implementation of the licensees corrective action program allowed the

root cause of a Unit 1 fan coil unit failure in November 2001, to go unidentified and was

not corrected. The licensees inadequate corrective action has resulted in multiple

performance failures of the safety-related containment cooling system and multiple

unplanned Technical Specifications (TS) Limiting Condition for Operation (LCO) entries.

The licensee has conducted a root cause evaluation, identified long-term corrective

actions to prevent future failures, and has implemented short-term corrective actions to

reduce the erosion rate until long-term corrective actions are fully implemented.

The inspectors concluded that the licensees failure to identify the root cause of the fan

coil unit accelerated erosion and implement effective corrective action to preclude

recurrence was a performance deficiency that warranted significance evaluation. The

inspectors determined the finding to be more than minor because the finding affected

the barrier integrity cornerstone objective to provide reasonable assurance that the

physical design barriers (the reactor containment) protect the public from radionuclide

release from accidents or events. The significance evaluation resulted in a finding of

very low safety significance (Green) since the unavailability of the CFCUs did not

adversely affect core damage frequency nor did it adversely affect the large early

release frequency. (Section 1R12)

• Green. The inspectors identified a finding of very low safety significance for a failure to

comply with the required actions of Technical Specifications (TS) Limiting Condition for

Operation (LCO) 3.0.3. Specifically, the licensee failed to place Unit 2 in Mode 3 within

7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and Mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> of entry into TS LCO 3.0.3 after 2 CFCUs, each

1 Enclosure

from opposite trains, were declared inoperable on February 11, 2005. This finding

constituted a Non-Cited Violation of TS LCO 3.0.3. The inspectors determined that the

finding impacted the cross-cutting area of Human Performance (organization) because

the licensee's management organization failed to carefully assess the situation

regarding TS compliance. The licensees decision to not place Unit 2 in Mode 3 within

7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and Mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> was based on a conclusion reached in an

operability evaluation. That evaluation concluded that the 21 CFCU, one of two CFCUs

in Train A, by itself, was sufficient to remove the post-accident containment heat load.

The licensee concluded that the 21 CFCU constituted an operable train of containment

cooling, declared containment cooling Train A operable, and exited TS LCO 3.0.3. The

licensee completed repairs and returned the two CFCUs to operable status on

February 12, 2005.

The inspectors concluded that the licensees failure to place Unit 2 in Mode 3 and

Mode 4 as required by TS LCO 3.0.3 was a performance deficiency that warranted

significance evaluation. The inspectors determined the finding to be more than minor

because the failure to comply with a TS-required shutdown could reasonably be viewed

as a precursor to a significant event. The significance evaluation resulted in a finding of

very low safety significance (Green) since the unavailability of the CFCUs did not

adversely affect core damage frequency nor did it adversely affect the large early

release frequency. (Section 1R15)

B. Licensee-Identified Violations

No findings of significance were identified.

2 Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at 98 percent power until the unit was shut down for repairs to the generator

seal oil system on February 19, 2005. The reactor was restarted on February 26, 2005, and the

generator was placed online on March 4, 2005. The unit operated at or near full power for the

remainder of the inspection period.

Unit 2 operated at or near full power with the following exceptions. On February 10, 2005,

power was reduced to approximately 6.5 percent for nine hours for maintenance on a heater

drain tank pump. On March 30, 2005, the unit was shut down for repairs to the 21, 22, and 23

containment fan coil units (CFCU). The unit remained shut down for the remainder of the

inspection period.

1. REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather (71111.01)

a. Inspection Scope

On March 30, 2005, the inspectors evaluated the licensees implementation of their

adverse weather abnormal operating procedure for tornados and high winds following

inclusion of the plant site and surrounding area in a tornado watch by the National

Weather Service. The inspectors observed the actions taken by plant operators and

compared them to the actions specified in Abnormal Operating Procedure AB-2,

Tornado/Severe Thunderstorm/High Winds, Revision 26.

This inspection comprised one inspection sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

.1 Partial Walkdowns

a. Inspection Scope

The inspectors performed three inspection samples comprising 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. In addition, the

inspectors reviewed corrective action program action requests (CAPs) associated with

3 Enclosure

equipment alignment issues 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.

The inspectors utilized the valve and electric breaker checklists 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

performance 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 Updated Safety Analysis Report (USAR) to determine the functional

requirements of the systems.

The inspectors verified the alignment of the following trains:

• 22 turbine-driven auxiliary feedwater pump during the unavailability of the 21

auxiliary feedwater pump on January 19, 2005;

• diesel generator D2 during the unavailability of diesel generator D1 on

January 25, 2005; and

• diesel generator D5 during the unavailability of the 122 control room chiller

February 28, 2005.

The key documents reviewed by the inspectors associated with this inspection are listed

in the Attachment to this inspection report.

b. Findings

No findings of significance were identified.

.2 Complete Walkdowns

a. Inspection Scope

During the week of January 16, 2005, the inspectors performed a detailed in-plant

walkdown of the alignment and condition of the Unit 1 component cooling water system,

a risk significant system that provides cooling to safety-related and risk significant

components during normal, off-normal, and accident modes of operation. This

inspection effort constituted one complete system alignment inspection sample. In

addition, the inspectors reviewed CAPs associated with equipment alignment issues 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.

The inspectors conducted in-plant walkdowns using the applicable alignment checklists

and plant drawings to verify that system components were properly positioned to

support the completion of system safety functions and to verify that the as-found system

configuration matched the configuration specified in the system alignment checklist and

plant drawings. The inspectors examined the material condition of the components,

4 Enclosure

such as pumps, motors, valves, instrumentation, controls, and electrical panels. The

inspectors observed operating parameters of equipment to verify that there were no

obvious performance 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 where

applicable. 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

Technical Specifications (TS), USAR, and other design basis documents to determine

the functional requirements of the systems and verified those functions could be

performed if needed.

The key documents reviewed by the inspectors associated with this inspection are listed

in the Attachment to this inspection report.

b. Findings

No findings of significance were identified.

1R05 Fire Protection Area Walkdowns (71111.05)

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 (IPEEE); 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 ten fire areas were inspected

by in-plant walkdowns supporting the completion of ten fire protection zone walkdown

samples:

• Fire Area 25, D1 diesel generator room, on January 18, 2005;

• Fire Area 31, auxiliary feedwater pump room, on January 18, 2005;

• Fire Area 32, auxiliary feedwater pump room, on January 18, 2005;

• Fire Area 41A, diesel-driven cooling water pump area, on January 19, 2005;

• Fire Area 41B, screenhouse below grade, on January 19, 2005;

• Fire Area 81, bus 15 room, January 18, 2005;

• Fire Area 89, guard house, on January 20, 2005;

• Fire Area 113, D5 day tank room, January 18, 2005;

• Fire Area 115, D5 lubricating oil make-up tank room, January 18, 2005; and

• Fire Area 117, bus 25 room, January 18, 2005.

The key documents reviewed by the inspectors associated with this inspection are listed

in the Attachment to this inspection report.

5 Enclosure

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope

The inspectors performed an in-office review of the most recently completed

surveillance procedure (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 an external flooding event. This inspection effort completed

the annual external flood protection inspection sample.

The inspectors performed an in-plant inspection of flood protection barriers in the

Auxiliary Building, Turbine Building, D5/D6 Building, and the Old Screenhouse during

the period of March 10 through 16, 2005, 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 (three days) if required, and the necessary hardware and consumable

materials were available and still within their shelf life.

The inspectors reviewed several CAP items to verify that minor deficiencies identified

during this inspection were entered into the licensees corrective action program, that

problems associated with plant equipment relied upon to prevent or minimize flooding

were identified at an appropriate threshold, and that corrective actions 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.

1R07 Heat Sink Performance (71111.07A)

a. Inspection Scope

On February 22, 2005, the inspectors performed an in-office review of the results of

SP 1424, Unit 1 Five Year Containment Fan Coil Unit Performance Test. This

procedure fulfills a commitment to Generic Letter 89-13, Service Water System

Problems Affecting Safety-Related Equipment, which requires a test program to verify

the heat transfer capability of safety-related heat exchangers cooled by service water.

The CFCUs remove heat from the containment building during normal operations and

during post-accident conditions to ensure that containment pressure does not exceed its

6 Enclosure

design value. The inspectors verified the following items were addressed in the test

results:

• Test acceptance criteria and results appropriately considered differences

between testing conditions and design conditions;

• Test results were appropriately categorized against preestablished acceptance

criteria;

• Frequency of testing is sufficient to detect degradation prior to loss of heat

removal capability below design basis values; and

• Test results considered test instrument inaccuracies and differences.

This inspection constituted one inspection sample. The key documents reviewed by the

inspectors associated with this inspection are listed in the Attachment to this inspection

report.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

a. Inspection Scope

On February 28, 2005, 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 annual 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.

The key documents reviewed by the inspectors associated with this inspection are listed

in the Attachment to this inspection report.

b. Findings

No findings of significance were identified.

7 Enclosure

1R12 Maintenance Effectiveness (71111.12)

.1 Repetitive CFCU Failures

a. Inspection Scope

The inspectors reviewed a repetitive maintenance activity to assess maintenance

effectiveness, including maintenance rule (10 CFR 50.65) activities, work practices, and

common cause issues. The inspectors performed one system/train function oriented

maintenance effectiveness sample. The inspectors assessed the licensees

maintenance effectiveness associated with repetitive failures of CFCU H-bends and

U-bends.

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, 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 the

CFCUs to ensure that those failures were properly identified, classified, corrected, 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

Introduction

The inspectors investigated the details associated with the repetitive failures of the

CFCUs and identified a finding of very low significance that was also determined to be a

Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions.

Specifically, the licensee failed to identify and implement effective corrective actions in a

timely manner to eliminate the failure mechanism common to all CFCUs on both Units 1

and 2. The licensees ineffective corrective actions resulted in multiple performance

failures of the safety-related containment cooling system and several unplanned

TS LCO entries for containment integrity (TS 3.6.1), containment cooling (TS 3.6.5), and

two entries into TS LCO 3.0.3 with one resulting in a TS-required shutdown of Unit 2.

(See Section 1R15 of this Report.)

Description

Unit 1 and Unit 2 CFCUs have demonstrated a long-standing history of failures due to

accelerated erosion. For example, during the period from 1985 to 2001 there were

approximately 24 through-wall leaks identified. Since the beginning of 2001, seven

additional CFCU failures were identified. Historically, the licensee accepted running the

CFCUs to failure. Until recently, the licensee reacted to the failures of the CFCUs by

8 Enclosure

conducting repairs but never taking the appropriate actions to determine the root cause

of the accelerated erosion and eliminating it.

On November 11, 2001, the 11 CFCU experienced a through-wall leak. The licensees

corrective action program evaluation of the event determined the cause of the failure to

be erosion and identified a corrective action to perform research to determine if a more

erosion resistant copper alloy should be used. The research was to be performed as

part of a fan coil face replacement modification. However, the fan coil face replacement

modification was never funded and the corrective action to research a more erosion

resistant material was administratively closed without identification of the root cause of

the erosion and without the implementation of any corrective action to prevent

recurrence. Researching the material acceptability for the application would likely have

led to the discovery of the root cause of the accelerated erosion experienced by the

CFCUs.

On November 17, 2004, through-wall leakage was identified on H-bends of the 22 and

23 CFCUs. The licensee entered TS LCO 3.6.1 for an inoperable containment. The

licensee restored the containment to an operable status within the required completion

time by closing the cooling water containment isolation valves to each affected CFCU.

This action made both the 22 and 23 CFCUs inoperable with respect to their

containment cooling function. Since the 22 CFCU was part of Train B of the

containment cooling system and the 23 CFCU was part of Train A of the containment

cooling system, both trains were inoperable and the licensee entered into TS LCO 3.0.3.

The repair of the CFCUs could not be completed in the allowed completion time for a

unit shutdown and Unit 2 was placed in Mode 3 while repairs were completed. The

licensee performed American Society of Mechanical Engineers (ASME) Code repairs of

the leaking tubing to restore both containment integrity and the containment cooling

functions. Upon the completion of repairs the TS LCOs were exited and Unit 2 was

restarted.

The licensee sent the failed H-bends offsite for failure analysis. The failure analysis

concluded that the through-wall leaks were due to erosion. The erosion occurred

around braze materials that had overflowed from the brazed joints onto the internal

surface of the H-bend. The buildup of braze material caused flow disruptions in the

H-bends, resulting in grooving and eventually leak formation in the copper base metal.

On January 11, 2005, the 21 CFCU was declared inoperable due to through-wall

leakage. The licensee conducted what they believed to be an ASME Code repair of the

leak, exited the applicable TS LCO, and assembled a root cause evaluation (RCE) team

to identify the cause of the CFCU leaks. On March 30, 2005, the licensee identified that

the repairs made to the CFCU were not in compliance with the ASME Code and Unit 2

was shut down for additional repair.

RCE 000193 identified a number of factors that cause erosion, including flow rate,

suspended materials in the cooling water, coil design (materials), fabrication

irregularities to the inner surface of the tubing that cause localized eddy currents under

high flow conditions, and high turbulence areas (H-bends and U-bends) where cooling

fluids make sharp directional changes. The RCE team evaluated each condition that

could cause accelerated erosion as it applied to the CFCU.

9 Enclosure

The evaluation of cooling water flow rate through the CFCU identified that they were

routinely operated at a flow rate of greater than 900 gallons per minute (gpm). A review

of design specification associated with the current CFCUs indicated that they had been

designed for a normal flow rate of 450 gpm. The effect of operating the CFCU at the

higher flow rate was evaluated by the RCE team and offsite personnel with expertise in

heat exchanger design and performance. The CFCUs currently installed in the Unit 1

and 2 containments were constructed of 99.9 percent (pure) copper. Pure copper

tubing is typically utilized in systems with a fluid velocity of five to seven feet per second

and should typically last about 10 to 15 years. The normal operation of CFCUs at

900 gpm results in a fluid velocity of nine feet per second. The increased fluid velocity

reduces the predicted life in half (five to seven years). If the licensee had researched

the acceptability of fan coil unit materials instead of administratively closing the

corrective action in November 2001, they likely would have identified reduced life

expectancy associated with operation of the pure copper coils at flow rates in excess of

900 gpm. This clearly was a missed opportunity to identify and correct the root cause of

the CFCU accelerated erosion.

On February 11, 2005, through-wall leaks were once again identified on the 22 and 23

CFCUs. However, during this event the licensee determined through engineering

analysis that the 21 CFCU could remove the required post accident heat load with

contingency actions in place. This formed the basis for Operability Recommendation

(OPR) 000533 which the licensee used to justify that the 21 CFCU comprised an

operable train of containment cooling and exited TS LCO 3.0.3 (see Section 1R15.1).

On March 24, 2005, through-wall leaks were once again identified on the 23 CFCU.

During this failure the licensee entered TS LCO 3.6.1 for the loss of containment

integrity but exited this LCO once containment isolation valves were closed. In contrast

to the January 11, 2005, event the licensee did not enter TS 3.6.5 for the loss of one

train of containment cooling citing the conclusion reached in OPR 000533 that the

21 CFCU, with other compensatory measure that existed at the time, comprised an

operable train of containment cooling.

On March 30, 2005, with Unit 2 in Mode 3 for repair of previous CFCU repairs

determined not in compliance with the ASME Code on the 21, 22, and 23 CFCUs, a new

active leak on a U-bend of the 21 CFCU was identified. At the time of identification, the

21 CFCU was already declared inoperable and was out-of-service.

Analysis

The inspectors determined that the performance deficiency existed since the licensee

failed to meet corrective actions requirements specified in 10 CFR 50, Appendix B,

Criterion XVI. Specifically, the licensee failed to identify and correct the root cause of

the CFCU accelerated erosion and to implement effective corrective actions in a timely

manner to preclude repeat failures.

The inspectors determined the finding to be more than minor in accordance with

Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports,

Appendix B, Issue Disposition Screening, issued on June 20, 2003. The finding

affected the barrier integrity cornerstone objective to provide reasonable assurance that

10 Enclosure

the physical design barriers (the reactor containment) protect the public from

radionuclide release from an accident or events. The cornerstone objective attribute of

Structure, System, or Component (SSC) and Barrier Performance was not maintained.

Specifically, degraded barrier performance resulted when through-wall leaks occurred in

CFCUs H-bends and U-bends and degraded SSC performance resulted when CFCUs

were isolated from their cooling water source preventing the removal of heat from

containment. The inspectors determined that the finding impacted the cross-cutting

area of Problem Identification and Resolution (corrective actions) because an

opportunity to identify the root cause of the accelerated erosion and implement effective

corrective actions to preclude recurrence was missed following a November 2001 CFCU

failure.

The inspectors completed the significance determination of this finding using IMC 0609,

Significance Determination Process, dated March 12, 2003, Appendix A, Determining

the Significance of Reactor Inspection Findings for At-Power Situations, dated

December 1, 2004. The Phase 1 Significance Determination worksheet identified that

the finding represented an actual reduction in defense-in-depth for the atmospheric

pressure control function of the reactor containment. Therefore, further evaluation in

accordance with IMC 609, Appendix H, Containment Integrity Significance

Determination Process, dated May 6, 2004, was required. The Appendix H evaluation

resulted in a finding of very low safety significance (Green) since the unavailability of the

CFCUs did not adversely affect core damage frequency nor did it adversely affect the

large early release frequency.

Enforcement

It is stated, in part, in 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, that

measures shall be established to assure that conditions adverse to quality are promptly

identified and corrected. In the case of a significant condition adverse to quality, the

measures shall assure that the cause of the condition is determined and corrective

actions taken to preclude repetition.

Contrary to the above, on November 11, 2001, the licensee failed to determine the

cause of the accelerated erosion that had resulted in through-wall leakage on the Unit 1

and 2 CFCUs, and failed to implement corrective actions to preclude recurrence.

Corrective actions identified by the licensee that would have identified the root cause of

the accelerated erosion were administratively closed with no action taken. The failure to

implement effective corrective actions to identify and correct the root cause of the

accelerated erosion resulted in the subsequent simultaneous failure of the 22 and 23

CFCUs on November 17, 2004; the failure of the 21 CFCU on January 11, 2005; the

simultaneous failures of the 22 and 23 CFCUs on February 11, 2005; the failure of the

23 CFCU on March 24, 2005; and the failure of the 21 CFCU on March 30, 2005.

Because this finding is of very low safety significance, and has been entered into the

licensees corrective action program with CAPs 039881, 039923, 040615, 040885,

041520, and 041589, this finding is being treated as an NCV, consistent with

Section VI.A of the NRC Enforcement Policy (NCV 05000282/2005003-01;

05000306/2005003-01).

11 Enclosure

The licensee has identified a number of immediate and interim corrective actions. The

licensee immediately performed an ASME Code repair of the leaking tubing to restore

both containment integrity and the containment cooling functions. In the interim, the

licensee has increased the frequency of containment inspections from quarterly to

monthly to visually inspect the CFCUs for leakage (CAPs 040379 and 040535); increase

the monitoring of containment sump A pump run times (Prairie Island Nuclear

Generating Plant Form 1180 auxiliary building operator logs); imposed restrictions on

placing the CFCUs on its chilled water source (Operating Instruction 05-12 and CAP

040906); establish a plan of inspection and/or testing to effectively clarify the condition

of all CFCUs (Engineering Work Request 10057); and implement any practical action to

reduce cooling water flow through the CFCUs to minimize the erosion rate.

The licensees RCE 000193 identified three corrective actions to prevent recurrence.

Corrective Action (CA) 010285 contains an action to verify and restore the material

condition of the Unit 1 and 2 CFCUs. This action is scheduled to be completed no later

than the next refueling outage for each unit. New CFCU faces have been ordered for

Unit 2 and are scheduled to be installed during refueling outage 2R23. CA 010286

contains an action to limit further erosion on the CFCUs. As stated previously, the

licensee has reduced the cooling water flow rate through the CFCUs to the greatest

extent practical to minimize the erosion rate. The material specifications for the new coil

faces specified a more erosion resistant copper alloy to be used in their construction.

CA 010287 contains an action to establish a condition monitoring program to assess the

condition of CFCUs relative to the effects of erosion and other potential thinning

mechanisms and establish an appropriate frequency of assessment.

.2 Quarterly 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 completing a total of two samples. The inspectors

assessed the licensees maintenance effectiveness associated with repetitive problems

on the following SSCs:

• 21 residual heat removal pump breaker problems on March 7, 2005; and

• Unit 2 charging pump failures March 23, 2005.

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

electrical equipment problems for risk significant and safety-related mitigating

12 Enclosure

equipment 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 (71111.13)

a. Inspection Scope

The inspectors reviewed risk assessments for six maintenance activities associated the

following combinations of equipment unavailability completing six risk assessment and

emergent work control inspection samples:

• the simultaneous unavailability of the 22 residual heat removal pump, the 22

component cooling water pump, the 23 charging pump, and the 122 instrument

air dryer for planned maintenance on January 6, 2005;

• the simultaneous unavailability of the 21 auxiliary feedwater pump and the 21

containment spray pump on January 21, 2005;

• the simultaneous unavailability of bus CT-11, the 21 residual heat removal pump,

the 21 component coolant water pump, and the 123 instrument air compressor

on February 17, 2005;

• the simultaneous unavailability of volume control tank level loop 1L-112 and the

123 instrument air compressor on February 18, 2005;

• the simultaneous unavailability of D1 diesel generator and the 12 diesel-driven

cooling water pump on March 21, 2005; and

• the simultaneous unavailability of 12 diesel-driven cooling water pump, 121

intake bypass gate, 121 control room chiller, and Unit 2, train A of the reactor

vessel level indicating system on March 24, 2005.

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 shiftly 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.

13 Enclosure

b. Findings

No findings of significance were identified.

1R14 Personnel Performance Related to Non-Routine Plant Evolutions and Events (71111.14)

a. Inspection Scope

On March 30, 2005, the inspectors reviewed licensee personnel performance during a

shutdown of Unit 2 required by TS due to CFCUs declared inoperable. The review

constituted one inspection procedure sample. The inspectors observed the

performance of operations personnel in the control room during the unplanned and non-

routine evolution. 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

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors reviewed the technical adequacy of eight operability evaluations

completing eight 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 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 5AWI 3.15.5, Operability Determinations. The

following operability evaluations were reviewed:

C OPR 000526, that documented the operability of the 21 motor-driven auxiliary

feedwater pump with lubricating oil pressure anomalies;

• OPR 000528, that documented the operability of the Unit 2 containment and the

containment cooling system with through-wall leaks on the 22 and 23 CFCUs

(November 2004 CFCU failures);

• OPR 000529, that documented the operability of diesel generator D2 with 5 time

delay relays beyond their qualified life of 10 years;

• CAP 040435 Past (historical) Operability Recommendation for pressurizer power

operated relief valve low temperature overpressure protection function;

• OPR 000533, that documented the operability of the Unit 2 containment and the

containment cooling system with through-wall leaks on the 22 and 23 CFCUs

(February 2005 CFCU failures);

14 Enclosure

• OPR 000534, that documented the operability of the Unit 2 component cooling

water system and the containment with a leak on the 21 reactor coolant pump

lower oil cooler outlet flow transmitter;

• OPR 000537, that documented an operability assessment of the Unit 1 turbine

stop valve SV-2 failure to close; and

• OPR 000542, that documented the operability of the Unit 2 containment cooling

system train B with the 21, 22, and 23 CFCUs determined inoperable due to non-

Code repairs.

The key documents reviewed by the inspectors associated with this inspection are listed

in the Attachment to this inspection report.

b. Findings

Introduction

The inspectors reviewed the actions taken by the licensee to comply with the TS when

two CFCUs were declared inoperable on February 11, 2005. The inspectors identified a

finding of very low safety significance and a Non-Cited Violation for a failure to comply

with the required actions of TS LCO 3.0.3. Specifically, the licensee failed to place

Unit 2 in Mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and in Mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> of entry into TS LCO 3.0.3. Unit 2 remained at full power throughout this event.

Description

On February 11, 2005, plant operators identified multiple through-wall leaks on two of

the four Unit 2 CFCUs. Specifically, the licensee identified leaks on the 22 (train B) and

23 (train A) CFCUs. The remaining operable CFCUs were the 21 (train A) and the 24

(train B) CFCUs. The licensee appropriately declared the containment inoperable and

closed the associated containment isolation valves for the CFCUs in accordance with

TS LCO 3.6.1. Closing the containment isolation valves also rendered the 22 and 23

CFCUs inoperable. TS LCO 3.6.5.c states, in part, that with one containment cooling

train inoperable, restore the train to operable status within seven days. Since there are

no specified actions for both trains of CFCUs being declared inoperable, the licensee

entered TS LCO 3.0.3 at 9:17 a.m. on February 11. The associated action was to place

the unit in Mode 3 (Hot Standby) within seven hours; i.e., by 4:17 p.m.

Concurrent with preparations to shut down Unit 2, engineering personnel performed a

technical evaluation with the support of a heat exchanger performance vendor, and

documented the evaluation in OPR 000533. This evaluation concluded that the

21 CFCU, by itself, was sufficient to remove the post-accident containment heat load

under certain environmental and other conditions that existed at the time of this event.

The licensee ultimately concluded that the 21 CFCU constituted an operable train of

containment cooling, declared train A operable, and exited TS LCO 3.0.3 at 1:38 p.m.

on February 11. Late on February 12, the licensee repaired the leaks on both the 22

and 23 CFCUs and exited TS LCO 3.6.5.c.

The inspectors challenged the appropriateness of the licensees conclusion that the

21 CFCU constituted the operable train A of containment cooling based on review of the

15 Enclosure

TS. Specifically, TS Surveillance Requirement (SR) 3.0.1 states that "SRs shall be met

during the MODES or other specified conditions in the Applicability for individual LCOs,

unless otherwise stated in the SR. Failure to meet a Surveillance, whether such failure

is experienced during performance of the surveillance or between performances of the

Surveillance, shall be failure to meet the LCO."

SR 3.6.5.3 requires the licensee to, "Verify each containment cooling train cooling water

flow rate to each fan coil unit [emphasis added] is greater than or equal to 900 gpm."

Furthermore, SR 3.6.5.2 requires the licensee to, "Operate each containment cooling

train fan coil unit [emphasis added] on low motor speed for greater than or equal to 15

minutes." Because the licensee had closed the containment isolation valves to 22 and

23 CFCUs to comply with TS LCO 3.6.1 for an inoperable containment after the leaks

were initially identified, SR 3.5.6.3, (900 gpm to each fan coil unit) could not be met.

Furthermore, the licensee had tagged out the motors for the CFCUs when the

containment isolation valves were closed per Abnormal Operating Procedure C35

AOP4, Step 2.4.3.O. Therefore, SR 3.6.5.2 (operate for greater than or equal to 15

minutes) could not be met.

The licensee completed repairs to the 23 CFCU, the first of the two leaking CFCUs, and

declared the CFCU operable at 3:09 a.m. on February 12. This was 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> 52

minutes after Unit 2 was required to be in Mode 3. The 22 CFCU was repaired and

declared operable at 10:40 p.m. on February 12.

Analysis

The inspectors determined that the licensees failure to maintain a sufficient number of

CFCUs capable of meeting TS SRs in order to meet the limiting conditions of operation

for the containment cooling function was a performance deficiency warranting

significance determination. The inspectors evaluated the finding and determined it to be

more than minor in accordance with IMC 0612, Power Reactor Inspection Reports,

Appendix B, Issue Disposition Screening, issued on June 20, 2003. Specifically, the

finding was more than minor because the failure to comply with a TS-required shutdown

could reasonably be viewed as a precursor to a significant event. This conclusion is

further supported by 10 CFR Part 50.36(c)(2) that states Limiting conditions for

operation are the lowest functional capability or performance level of equipment required

for safe operation of the facility. The inspectors also determined that the finding

impacted the cross-cutting area of Human Performance (organization) because the

licensee's management organization failed to carefully assess the situation regarding

TS compliance.

The inspectors completed the significance determination of this finding using IMC 0609,

Significance Determination Process, dated March 21, 2003, Appendix A, Determining

the Significance of Reactor Inspection Findings for At-Power Situations, dated

December 1, 2004. The Phase 1 Significance Determination worksheet identified that

the finding represented an actual reduction in defense-in-depth for the atmospheric

pressure control function of the reactor containment. Therefore, further evaluation in

accordance with IMC 609, Appendix H, Containment Integrity Significance

Determination Process, dated May 6, 2004, was required. The Appendix H evaluation

resulted in a finding of very low safety significance (Green) since the unavailability of the

16 Enclosure

CFCUs did not affect core damage frequency nor did it affect the large early release

frequency.

Enforcement

TS 3.6.1 requires that the containment be operable in Modes 1-4. TS 3.6.1 Action A

requires that with an inoperable containment, restore the containment to operable within

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

TS 3.6.5 requires, in part, that two containment cooling trains be operable. TS 3.6.5

Action C requires that with one containment cooling train inoperable, restore the

containment cooling train to operable status within seven days. TS 3.6.5 does not

address inoperability of two containment cooling trains.

SR 3.0.1 states that SRs shall be met during the MODES or other specified conditions in

the Applicability for individual LCOs, unless otherwise stated in the SR. Failure to meet

a Surveillance, whether such failure is experienced during performance of the

surveillance or between performances of the Surveillance, shall be failure to meet the

LCO.

SR 3.6.5.3 requires the licensee to verify each containment cooling train cooling water

flow rate to each fan coil unit is greater than or equal to 900 gpm.

SR 3.6.5.2 requires the licensee to operate each containment cooling train fan coil unit

on low motor speed for greater than or equal to 15 minutes.

Because the licensee had closed the containment isolation valves to 22 and 23 CFCUs

to comply with TS LCO 3.6.1 for an inoperable containment within one hour after leaks

were identified, SR 3.5.6.3 could not be met. Furthermore, because the licensee had

tagged out the motors for the CFCUs when the containment isolation valves were

closed, SR 3.6.5.2 could not be met. Because the SRs could not be met, TS LCO 3.6.5

could not be met.

TS LCO 3.0.3 states, in part, that when an LCO is not met and the associated actions

are not met or an associated action is not provided, then action shall be initiated within

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit, as applicable, in Mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, Mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />,

and Mode 5 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />.

Contrary to the above, at 4:17 p.m. on February 11, 2005, the licensee failed to

implement the required action of TS LCO 3.0.3. Specifically, at 9:17 a.m. on

February 11, 2005, the licensee identified leakage from both the 22 and 23 CFCUs.

The licensee entered TS LCO 3.6.1 for both CFCUs and closed the respective

containment isolation valves. The licensee also entered TS LCO 3.6.5 and TS

LCO 3.0.3. At 1:38 p.m. on February 11, the licensee exited from TS LCO 3.0.3 without

restoring the 22 and 23 CFCUs to operable status and without placing Unit 2 in Mode 3

within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and Mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> of entry into TS LCO 3.0.3. Unit 2 continued

to operate in Mode 1 at full power.

17 Enclosure

Because this finding is of very low safety significance, and has been entered into the

licensees corrective action program with CAP 041681, this finding is being treated as a

NCV, consistent with Section VI.A of the NRC Enforcement Policy

(NCV 05000306/2005003-02).

The through-wall leakage from the 23 CFCU was repaired fully restoring the functional

capability of containment cooling system Train A at 3:09 a.m. on February 12, 2005.

The 22 CFCU was repaired at 10:40 p.m. on February 12, restoring operability of

containment cooling system Train B.

1R16 Operator Workarounds (OWAs) (71111.16)

.1 Operator Workarounds

a. Inspection Scope

The inspectors reviewed selected OWAs to determine if the mitigating system function

was affected. Specifically, the inspectors evaluated if the operators ability to implement

abnormal and emergency operating procedures was affected by the workaround. The

inspectors considered operator workarounds that have not been evaluated by the

licensee and that have been formalized as long-term corrective action for a degraded or

non-conforming condition. The inspectors also reviewed OWAs that increased potential

for personnel error including OWAs that:

• required operations contrary to past training or require more detailed knowledge

of the system than routinely provided;

• required a change from longstanding operational practices;

• required operation of system or component in a manner that is different from

similar systems or components;

• created the potential for the compensatory action to be performed on equipment

or under conditions for which it is not appropriate;

• impaired access to required indications, increase dependence on oral

communications, or require actions under adverse environmental conditions; or

• required the use of equipment and interfaces that had not been designed with

consideration of the task being performed.

The inspectors reviewed two OWAs from the licensees list of OWAs both associated

with pressurizer heater control. The Unit 1 and Unit 2 OWA resulted from a different

cause but impacted the control room operators in essentially the same way; therefore,

the inspectors considered the review as one inspection sample. The Unit 1 OWA

resulted from a need for one additional set of back-up heaters to maintain reactor coolant

system pressure in the normal operating band due to problems with group C pressurizer

heaters. The Unit 2 pressurizer heater control issue was associated with the back-up

heaters operating point shift due to misadjustment of the pressurizer spray bypass valve.

The key documents reviewed by the inspectors associated with this inspection are listed

in the Attachment to this inspection report.

18 Enclosure

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope

The inspectors performed five assessments of post-maintenance testing completing five

post-maintenance test inspection samples. The inspectors selected post-maintenance

tests associated with important mitigating and barrier integrity systems to ensure that the

testing was performed adequately, demonstrated that the maintenance was successful,

and that operability of associated equipment and/or systems was restored. The

inspectors conducted this inspection by in-office review of documents and in-plant

walkdowns of associated plant equipment. The inspectors observed and assessed the

post-maintenance testing activities for the following maintenance activities:

• 21 auxiliary feedwater pump following maintenance on the lubricating oil pump on

January 19, 2005;

• diesel generator D1 following preventative maintenance on January 28, 2005;

• Unit 1 main turbine stop valve SV-2 following repairs on March 4, 2005;

• diesel generator D5 following preventative maintenance on March 18, 2005; and

• 12 diesel-driven cooling water pump following preventative maintenance on

March 24, 2005.

The inspectors reviewed the appropriate sections of the TS, USAR, and maintenance

documents to determine the systems safety functions and the scope of the maintenance.

The inspectors also reviewed the CAPs listed in the Attachment 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. The documents

reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified

1R20 Refueling and Other Outage Activities (71111.20)

a. Inspection Scope

Unit 1 Maintenance Outage

a. Inspection Scope

The inspectors observed the licensees performance during the Unit 1 maintenance

outage 1F51 conducted between February 18 and March 4, 2005. These inspection

activities represent one outage inspection sample.

19 Enclosure

This inspection consisted of an in-office and in-plant review of outage activities

performed by the licensee. The inspectors conducted in-office reviews of outage related

documentation and in-plant observations of the following daily outage activities:

• 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 reactor coolant system instrumentation and compared

channels and trains against one another;

• observe ongoing work activities and foreign material exclusion control; and

• reviewed 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:

• observed the reactor shutdown from full power to hot shutdown;

• conducted an independent post outage containment close-out inspection;

• observed the reactor start up from the control room; and

• observed generator synchronization to the grid and power ascension.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

During this inspection period, the inspectors completed five inspection samples.

SP 1106B completed the quarterly Inservice Testing inspection requirement of a risk-

significant pump or valve. SP 2001AA completed the annual requirement to select a

reactor coolant system leakage detection surveillance test sample. The inspectors

selected the following surveillance testing activities:

• SP 2307, D6 Diesel Generator 6-Month Fast Start Test, on January 3, 2005;

• SP 1219, Monthly 4 Kilovolt Bus 16 Undervoltage Relay Test, on March 8, 2005;

• SP 1106B, 22 Diesel-Driven Cooling Water Pump Monthly, on March 15, 2005;

• SP 1334, D1 Diesel Generator 18-Month 24-Hour Load Test, on March 21, 2005;

and

• SP 2001AA, Unit 2 Daily Reactor Coolant System Leakage Test, on

March 29, 2005.

20 Enclosure

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 were clearly stated, demonstrated operational readiness, and

were consistent with the system design basis;

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

calibration frequency was in accordance with TS, 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, 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.

1R23 Temporary Plant Modifications (71111.23)

a. Inspection Scope

The inspectors conducted in-plant observations of the physical changes to the equipment

and an in-office review of documentation associated with two temporary modifications

completing two temporary modification inspection samples. As part of this inspection,

the documents in the Attachment were utilized to evaluate the potential for an inspection

finding.

21 Enclosure

The inspectors reviewed the following temporary modifications:

• temporary modification 05T187 associated with a temporary installation of

jumpers in breaker cubicles 15-7 and 16-8 to mitigate a potential single failure

vulnerability with metering circuits for safety-related buses 15 and 16 on

February 7, 2005; and

• temporary modification 05T185 associated with a temporary repair of a steam

leak on Unit 1 main steam non-return check valve RS-19-2 on March 10, 2005.

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 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 (71114.06)

a. Inspection Scope

The inspectors observed the licensee perform an emergency preparedness drill on

February 9, 2005. This inspection effort completed one emergency planning drill

evaluation sample.

The inspectors observed activities in the control room simulator, Technical Support

Center, and Emergency Operations Facility and attended the post-drill critique on

February 9, 2005. The focus of the inspectors activities was to note any weaknesses

and deficiencies in the drill performance and ensure that the licensee evaluators noted

the same weaknesses and deficiencies and entered them into the corrective action

program. The inspectors placed emphasis on observations regarding event

classification, notifications, protective action recommendations, and site evacuation and

accountability activities. The documents reviewed by the inspectors are listed in the

Attachment.

b. Findings

No findings of significance were identified.

22 Enclosure

4. OTHER ACTIVITIES

4OA2 Identification and Resolution of Problems (71152)

.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 - Inadvertent Dilution of the

Reactor Coolant System

a. Inspection Scope

During the week ending March 11, 2005, 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

inadvertent dilution of the reactor coolant system that was identified and entered into the

corrective action program with CAP 039236.

The inspectors conducted a review of the previously referenced CAPs and other related

corrective action program documents in order to assess the effectiveness of the

licensees efforts to correct the identified problem. The inspectors placed particular

attention 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 key documents reviewed by the inspectors associated with this inspection are listed

in the Attachment to this inspection report.

b. Findings and Observations

No findings of significance were identified.

23 Enclosure

.3 Ineffective CFCU Corrective Actions

a. Inspection Scope

The inspectors assessed the licensees maintenance effectiveness associated with

repetitive problems on Unit 1 and Unit 2 CFCUs. During that inspection, the inspectors

identified a performance deficiency associated with the cross-cutting area of Problem

Identification and Resolution.

The key documents reviewed by the inspectors associated with this inspection are listed

in the Attachment to this inspection report.

b. Findings

The inspectors investigated the details associated with the repetitive failures of the

CFCUs and identified a finding of very low significance that was also determined to be a

NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions. Specifically, the

licensee failed to identify and implement effective corrective actions in a timely manner to

eliminate the failure mechanism common to all CFCUs on both Units 1 and 2. The

licensees ineffective corrective actions resulted in multiple performance failures of the

safety-related containment cooling system and several unplanned TS LCO entries for

containment integrity, containment cooling, and two entries into TS LCO 3.0.3 with one

resulting in a TS required shutdown of Unit 2. A detailed evaluation of this finding of very

low safety significance can be found in Section 1R12.1 of this report.

4OA3 Event Followup (71153)

a. Inspection Scope

(Closed) Licensee Event Reports (LERs) 05000306/2004-001-00 and

05000306/2004-001-01: Unit 2 Shutdown Required by Technical Specifications Due to

Two Trains of Containment Cooling Inoperable

On November 17, 2004, two leaks were identified on the 23 CFCU and one leak was

identified on the 22 CFCU. The leaking CFCUs were isolated. Since the leaks affected

one of two CFCUs in each of the two trains of containment cooling, both trains of

containment cooling were declared inoperable and TS LCO 3.0.3 was entered. The

leaks could not be repaired before a plant shutdown was required. The plant was shut

down and repair of the leaks was completed on November 18, 2004. Unit 2 returned to

power operations on November 19, 2004.

The inspectors reviewed the root cause investigation report, the appropriateness of

corrective actions, and compliance with requirements. This LER is closed.

b. Findings

No findings of significance were identified.

24 Enclosure

4OA4 Cross-Cutting Findings

.1 A finding described in Section 1R12.1 of this report had, as its primary cause, a Problem

Identification and Resolution deficiency (corrective action) because the ineffective

troubleshooting resulted in a failure to promptly identify the root cause, correct significant

conditions adverse to quality, and preclude recurrence of Unit 1 and 2 CFCU failures.

.2 A finding described in Section 1R15 of this report had, as its primary cause, a Human

Performance deficiency (organization) because the licensee's management organization

failed to carefully assess the situation regarding TS compliance.

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 April 12, 2005. The

inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. No proprietary information was identified.

ATTACHMENT: SUPPLEMENTAL INFORMATION

25 Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

L. Clewett, Plant Manager

R. Graham, Director of Site Operations

P. Huffman, Operations Manager

J. Lash, Training Manager

K. Ludwig, Maintenance Manager

J. Maki, Outage and Scheduling Manager

S. McCall, Manager of Engineering Programs

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

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000282/2005003-01 NCV Failure to Implement Prompt and Effective Corrective

05000306/2005003-01 Actions for Repetitive Failures of Containment Fan Coil

Units05000306/2005003-02 NCV Failure to Meet Technical Specification 3.0.3

Requirements

05000306/2004-001-00 LER Unit 2 Shutdown Required by Technical Specifications

05000306/2004-001-01 Due to Two Trains of Containment Cooling Inoperable

Closed

05000282/2005003-01 NCV Failure to Implement Prompt and Effective Corrective

05000306/2005003-01 Actions for Repetitive Failures of Containment Fan Coil

Units05000306/2005003-02 NCV Failure to Meet Technical Specification 3.0.3

Requirements

05000306/2004-001-00 LER Unit 2 Shutdown Required by Technical Specifications

05000306/2004-001-01 Due to Two Trains of Containment Cooling Inoperable

Discussed

None.

1 Attachment

LIST OF DOCUMENTS REVIEWED

The following is a list of documents reviewed during the inspection. Inclusion on this list does

not imply that the NRC inspectors reviewed the documents in their entirety but rather that

selected sections of portions of the documents were evaluated as part of the overall inspection

effort. Inclusion of a document on this list does not imply NRC acceptance of the document or

any part of it, unless this is stated in the body of the inspection report.

1R04 Equipment Alignment

22 Turbine-Driven AFW Pump

CAP 037878; VC-33-01 Found in the Local Position

Diesel Generator D5

CAP 036915; 2-EG-41-6 Check Valve in D5 1B Starting Air System Found Installed

Backwards

Unit 1 Component Cooling Water Complete Equipment Alignment

CAP 039294; Cooling Water System Cross-Tied to Fire Protection System

1R05 Fire Protection

Plant Safety Procedure F5, Appendix A, Revision 15; Fire Strategies for Fire

Areas 25, 31, 32, 41A, 41B, 81, 89, 113, 115, and 117

Plant Safety Procedure F5, Appendix F, Revision 19; Fire Hazard Analysis for Fire

Areas 25, 31, 32, 41A, 41B, 81, 89, 113, 115, and 117

IPEEE NSPLMI-96001, Appendix B; Internal Fires Analysis; Revision 2

1R06 Flood Protection Measures (external)

SP 1293; Inspection of Flood Control Measures; Revision 13

AB-4; Flood; Revision 26

1R07 Heat Sink Performance

SP 1424; Unit 1 Five Year Containment Fan Coil Unit Performance Test; Revision 0

1R11 Licensed Operator Requalification Program

Simulator Exercise Guide P9160S-001 ATT SQ-48; Revision 0

1R12 Maintenance Rule Implementation

CFCU Failures

RCE 000193; Fan Coil Unit Cooling Coil Leakage

2 Attachment

Maintenance Rule A(1) Action Plan for the Containment Ventilation System

General Condition Report 200186219; U-Bend on the 11 CFCU Was Found to be

Leaking

CAP 039881; Possible 23 CFCU Leakage

CAP 039923; Unplanned LCO - 22 CFCU

CAP 040560; 21 Containment Fan Coil Unit Leakage

CAP 040615; Potential Common Mode Failure of CFCUs During a Design Basis Event

CAP 040885; 23 CFCU Leakage

CAP 040942; 21 Containment Sump A Run Time - Repeat Issue

21 Residual Heat Removal Pump Breaker Problems

Maintenance Rule Evaluation 000169; Unplanned LCO Not Met Due to 21 RHR [Residual

Heat Removal] Out of Service

Maintenance Rule Evaluation 000189; Failure of Indicating Light Circuit for Breaker 25-7

21 RHR Pump

CAP 030769; Unplanned LCO Not Met Due to 21 RHR Out of Service

CAP 031333; Failure of Indicating Light Circuit for Breaker 25-7 21 RHR Pump

CAP 036800; Negative Trend Concerning Dirty Contacts on Switches

CAP 040380; Trend - Loose Electrical Connections Impacting Plant Conditions

Unit 2 Charging Pump Failures

CAP 028202; 21 Charging Pump Was Started and Flow Did Not Increase

CAP 037133; Failure of 22 Charging Pump Coupling

CAP 037356; 22 Charging Pump Tripped for Unknown Reasons

CAP 040339; 23 Charging Pump Had Large Seal Leak

1R13 Maintenance Risk Assessments and Emergent Work Control

22 RHR Pump, 22 Component Cooling Water Pump, 23 Charging Pump, and 122

Instrument Air Dryer

Unit 2 Configuration Risk Assessment for January 6, 2005

Operator Logs for January 6, 2005

3 Attachment

21 AFW Pump and 21 Containment Spray Pump

Unit 2 Configuration Risk Assessment for January 21, 2005

Operator Logs for January 21, 2005

Bus CT-11, 21 RHR Pump, 21 Component Cooling Water Pump, and 123 Instrument

Air Compressor

Unit 2 Configuration Risk Assessment for February 17, 2005

Operator Logs for February 17, 2005

Volume Control Tank Level Loop 1L-112 and 123 Instrument Air Compressor

Unit 1 Configuration Risk Assessment for February 18, 2005

Operator Logs for February 18, 2005

WO 0501454; Investigate and Repair Volume Control Tank Auto Make-up Control

Unavailability of EDG D1 and 12 Diesel-Driven Cooling Water Pump

Unit 1 Configuration Risk Assessment for March 21, 2005

Unavailability of 12 Diesel-Driven Cooling Water Pump, 121 Intake Bypass Gate,

121 Control Room Chiller

Unit 2 Configuration Risk Assessment for March 24, 2005

1R14 Non-Routine Evolutions

Operating Procedure 2C1.3; Unit 2 Shutdown; Revision 53

Operating Procedure 2C1.4; Unit 2 Power Operation; Revision 35

1R15 Operability Evaluations

1 Motor-Driven AFW Pump

OPR 000526; Low Oil Pressure on 21 Motor-Driven AFW Pump

Equipment/System Troubleshooting Investigation; Low Lube Oil Pressure on 21 Motor-

Driven AFW Pump

Unit 2 CFCUs and Containment

OPR 000528; Containment Fan Coil Unit Cooling Coils (H-Bends and U-Bends);

Revision 0, 1, and 2

RCE 000193; 21 Fan Coil Unit Unplanned LCO Due to Cooling Water Leak

Apparent Cause Evaluation 008886; Possible 23 CFCU Leakage

4 Attachment

Diesel Generator D2

OPR 000529; Five D1 Agastat Relays Appear to be Beyond Qualified Life of 10 Years;

Revision 0

Past (Historical) Operability Recommendation for Pressurizer Power Operated Relief

Valve Low Temperature Overpressure Protection Function

CAP 040435; Additional Action Related to CAP 039539

CAP 039539; Westinghouse Analysis Reveals Higher Required Number of Power

Operated Relief Valve Strokes for Low Temperature Overpressure Protection

Repetitive Failure of CFCUs

Abnormal Operating Procedure C35 AOP4; Cooling Water Leakage in Containment;

Revision 12

OPR 000533; 21 Containment Sump A Run Time - Repeat Issue

Unit 2 Component Cooling Water and Containment

OPR 000534; Component Cooling Water Leak; Revision 0 and 1

Turbine Stop Valve

OPR 000537; SV-2 Not Develop the Required 50 Pounds Per Square Inch Drop When

Closed Per SP 1054

CAP 041183; SV-2 Not Develop the Required 50 Pounds Per Square Inch Drop When

Closed Per SP 1054

Non-Code Repairs to CFCUs

OPR 000542; Train B Containment Cooling Operability with 22 CFCU Isolated

Letter dated March 7, 2005, from E. Mercier to S. Thomas; Containment Integrity

Analysis with Half CFCU Capacity

Letter dated February 11, 2005, from E. Mercier to S. Thomas; Preliminary Nuclear

Analysis Department Analysis Results for Main Steamline Break and Loss of Coolant

Accident with Reduced CFCU Heat Removal

1R16 OWAs

Prairie Island Operator Workarounds List; Updated March 1, 2005

CAP 036710; Received Annunciator 47512-0608 When Pressurizer Master Controller is

Placed in Automatic

CAP 040114; Inoperable Pressurizer Group C Heaters Not Repaired During 1R23

Causing an OWA

5 Attachment

1R19 Post-Maintenance Testing

21 AFW Pump

SP 2100; 21 Motor-Driven AFW Pump Monthly Test; Revision 64

CAP 040637; Part Found Not Installed on 21 AFW

Diesel Generator D1

D1 18-Month Preventative Maintenance Voluntary Limiting Condition for Operation Plan;

January 23 through 27, 2005

SP 1295; D1 Diesel Generator 6-Month Fast Start Test; Revision 35

SP 1334; D1 Diesel Generator 18-Month 24-Hour Load Test; Revision 7

CAP 040754; D1 Locked Out During Post-Maintenance Operability Test

CAP 040816; WO 046367 Installed a Different Size Orifice Without Proper

Documentation

Unit 1 Stop Valve SV-2

SP 1054; Turbine Stop, Governor, Reheat Stop and Reheat Intercept Valve Exercise;

Revision 31

Diesel Generator D5

SP 2295; D5 Diesel Generator 6-Month Fast Start Test; Revision 28

SP 2334; D5 Diesel Generator 18-Month 24-Hour Load Test; Revision 9

CAP 040754; D1 Locked Out During Post-Maintenance Operability Testing

12 Diesel-Driven Cooling Water Pump

SP 1106A; Cooling Water Pump Monthly Test; Revision 64

1R20 Refueling and Other Outage Activities

SP 1750; Post Outage Containment Close-Out Inspection, Part C; Revision 27

1R22 Surveillance Testing

SP 2307

SP 2307; D6 Diesel Generator 6-Month Fast Start Test; Revision 22

CAP 040401; D6 Diesel Room Vent System Trouble Alarm During D6 Engine Run

SP 1219

SP 1219; Monthly 4 Kilovolt Bus 16 Undervoltage Relay Test; Revision 29

6 Attachment

SP 1106B

SP1106B; 22 Diesel-Driven Cooling Water Pump Monthly; Revision 62

CAP 041334; Desired Cooling Water Flow Rate Not Achieved During 22 Diesel-Driven

Cooling Water Pump Monthly SP

SP 1334

SP 1334; D1 Diesel Generator 18-Month 24-Hour Load Test; Revision 7

CAP 041454; Documentation of D5 18-Month Boroscope Results of WO 0400818

SP 2001AA

SP 2001AA; Unit 2 Daily Reactor Coolant System Leakage Test: Revision 42

CAP 040369; Boric Acid Leaks Found During SP 1544

1R23 Temporary Modifications

Temporary Modification 05T187

Temporary Modification 05T187- Installation of Jumpers in Breaker Cubicles 15-7 and

16-8

CAP 040896; 5AWI 6.5.0 Has Several Traps to Make Human Performance Errors

Temporary Modification 05T185

Modification 05T185; Furmanite Repair RS-19-2; March 2, 2005

CAP 040403; RS-19-2 Has a Leak Under the Insulation

WO 0500826; Furmanite 12 Steam Generator Main Steam Outlet Stop Check Valve

WO 0500827; Repair 12 Steam Generator Main Steam Outlet Stop Check Valve

1EP6 Drill Evaluation

Prairie Island Nuclear Generating Plant Emergency Plan Drill; February 9, 2005;

Revision 2

4OA2 Identification and Resolution of Problems

Annual Sample

CAP 033250; Make Up Flow to the Volume Control Tank and Reactor Coolant System

CAP 039236; SP 1366/SP 2366 Will Cause an Inadvertent Dilution of the Reactor

Coolant System

CAP 039599; Inadvertent Dilution of Unit 1 Reactor Coolant System Boron

7 Attachment

Apparent Cause Evaluation 008854; Inadvertent Boration of Unit 2 Reactor Coolant

System

4OA3 Event Followup

LER 05000306/2004-001-00 and 05000306/2004-001-01; Unit 2 Shutdown Required by

Technical Specifications Due to Two Trains of Containment Cooling Inoperable

RCE 000193, Fan Coil Unit Cooling Leakage; February 15, 2005

8 Attachment

LIST OF ACRONYMS USED

ADAMS Agencywide Documents Access and Management System

ASME American Society of Mechanical Engineers

CA Corrective Action

CAP Corrective Action Program/Corrective Action Program Action Request

CFR Code of Federal Regulations

CFCU Containment Fan Coil Unit

DRP Division of Reactor Projects

gpm gallons per minute

IMC Inspection Manual Chapter

IPEEE Individual Plant Examination of External Events

IR Inspection Report

LCO Limiting Condition for Operation

LER Licensee Event Report

NCV Non-Cited Violation

NMC Nuclear Management Corporation, LLC

NRC U.S. Nuclear Regulatory Commission

OPR Operability Recommendation

OWA Operator Workaround

PARS Publicly Available Records

RCE Root Cause Evaluation

RHR Residual Heat Removal

SSC Structure, System, or Component

SDP Significance Determination Process

SP Surveillance Procedure

SR Surveillance Requirement

TS Technical Specifications

USAR Updated Safety Analysis Report

WO Work Order

9 Attachment