ML030290757

IR 05000282-02-009 & 05000306-02-009, on October 29 - December 28, 2002, Prairie Island, Units 1 & 2. Flood Protection Measures, Inservice Inspection Activities & Event Followup

ML030290757
Person / Time
Site:	Prairie Island
Issue date:	01/29/2003
From:	Kenneth Riemer NRC/RGN-III/DRP/RPB5
To:	Nazar M Nuclear Management Co
References
IR-02-009
Download: ML030290757 (81)

See also: IR 05000282/2002009

Text

January 29, 2003

Mr. M. Nazar

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 50-282/02-09; 50-306/02-09

Dear Mr. Nazar:

On December 28, 2002, the U. S. Nuclear Regulatory Commission (NRC) completed an

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

enclosed report documents the inspection findings which were discussed on January 13, 2003,

with you and other members of your staff.

This inspection examined activities conducted under your license as they relate to safety and

compliance with the Commissions rules and regulations and with the conditions of your license.

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

personnel.

Based on the results of this inspection, the inspectors identified four issues of very low safety

significance (Green). These were determined to involve violations of NRC requirements.

However, because of the very low safety significance of the issues and because they were

entered into your corrective action program, the NRC is treating the issues 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, DC 20555-

0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission -

Region III, 801 Warrenville Road, Lisle, IL 60532-4351; 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.

Since the terrorist attacks on September 11, 2001, the NRC has issued two Orders

(dated February 25, 2002, and January 7, 2003) and several threat advisories to licensees

of commercial power reactors to strengthen licensee capabilities, improve readiness, and

enhance access authorization. The NRC also issued Temporary Instruction 2515/148 on

August 28, 2002, that provided guidance to inspectors to audit and inspect licensee

implementation of the interim compensatory measures (ICMs) required by the February 25th

M. Nazar

-2-

Order. Phase 1 of TI 2515/148 was completed at all commercial nuclear power plants during

2002, and the remaining inspections are scheduled for completion in 2003. Additionally, table-

top security drills were conducted at several licensees to evaluate the impact of expanded

adversary characteristics and ICMs on licensee protection and mitigative strategies.

Information gained and discrepancies identified during the audits and drills were reviewed and

dispositioned by the Office of Nuclear Safety and Incident Response. For 2003, the NRC will

continue to monitor overall safeguards and security controls, conduct inspections, and perform

force-on-force exercises at selected power plants. Should threat conditions change, the NRC

may issue additional Orders, advisories, and temporary instructions to ensure adequate safety

is being maintained at all commercial power reactors.

In accordance with 10 CFR 2.790 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/

Kenneth Riemer, Chief

Branch 5

Division of Reactor Projects

Docket Nos. 50-282; 50-306

License Nos. DPR-42; DPR-60

Enclosure:

Inspection Report 50-282/02-09; 50-306/02-09

w/Attachment: Memorandum Regarding TI 2515/149

cc w/encl:

Plant Manager, Prairie Island

R. Anderson, Executive Vice President

and Chief Nuclear Officer

Site Licensing Manager

Nuclear Asset Manager

Commissioner, Minnesota

Department of Health

State Liaison Officer, State of Wisconsin

Tribal Council, Prairie Island Indian Community

J. Silberg, Esquire

Shawn, Pittman, Potts, and Trowbridge

P. Marker, Office of the Attorney General

Administrator, Goodhue County Courthouse

Commissioner, Minnesota Department

of Commerce

DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML030290757.wpd

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

OFFICE

RIII

RIII

NAME

MKunowski:dtp

KRiemer

DATE

01/29/03

01/29/03

OFFICIAL RECORD COPY

M. Nazar

-3-

ADAMS Distribution:

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C. Ariano (hard copy)

DRPIII

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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket Nos:

50-282; 50-306

License Nos:

DPR-42; DPR-60

Report No:

50-282/02-09; 50-306/02-09

Licensee:

Nuclear Management Company, LLC

Facility:

Prairie Island Nuclear Generating Plant, Units 1 and 2

Location:

1717 Wakonade Drive East

Welch, MN 55089

Dates:

October 1 through December 28, 2002

Inspectors:

J. Adams, Senior Resident Inspector

S. Ray, Senior Resident Inspector, Braidwood

S. Burgess, Senior Reactor Analyst

D. Karjala, Resident Inspector

D. Kimble, Resident Inspector, Monticello

M. Mitchell, Radiation Specialist

M. Holmberg, Reactor Inspector

K. Poertner, Mechanical Engineer, NRR

S. Sanders, Reactor Operations Engineer, NRR

R. Jickling, Emergency Preparedness Analyst

Approved by:

Kenneth Riemer, Chief

Branch 5

Division of Reactor Projects

2

TABLE OF CONTENTS

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1.

REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1R01

Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1R04

Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1R05

Fire Protection Area Walkdowns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R06

Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R07

Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

1R08

Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

1R11

Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1R12

Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1R13

Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . 20

1R14

Personnel Performance Related to Non-Routine Plant Evolutions and Events

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

1R15

Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

1R16

Operator Workarounds (OWAs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

1R17

Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

1R19

Post-Maintenance Testing

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

1R20

Refueling and Other Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

1R22

Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

1R23

Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

1EP6

Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

2.

RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2OS1 Access Control to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 27

2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls . . . . . 28

3.

SAFEGUARDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

3PP3

Response to Contingency Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

4.

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

4OA6 Meeting(s) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

4OA7 Licensee-Identified Violations

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

LIST OF DOCUMENTS REVIEWED

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

3

SUMMARY OF FINDINGS

IR 05000282/2002-009, 05000306/2002-009; Nuclear Management Company, LLC; on

10/1 -12/28/02, Prairie Island Nuclear Generating Plant, Units 1 & 2. Flood Protection

Measures, Inservice Inspection Activities, and Event Followup. In addition, generic safety

issue inspections in accordance with Temporary Instruction (TI) 2515/149, Mitigating Systems

Performance Index Pilot Verification, were conducted.

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

the resident inspectors, inspectors from the Region III office, and inspectors from the Office of

Nuclear Reactor Regulation. Four 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.

Inspection Findings

Cornerstone: Initiating Events

Green. A finding of very low safety significance was identified for the existence of

prohibited loose materials in the safety-related cooling water pump rooms on three

separate occasions. The materials were specifically prohibited due to the potential for

the loose materials to obstruct required critical drainage paths from these areas

adversely affecting measures for internal flood protection.

This finding is more than minor because it was associated with two of the cornerstone

attributes, affected the initiating events cornerstone objective, and was repetitive.

However, it was of very low safety significance because it did not contribute to the

likelihood of a primary or secondary system loss of coolant accident, did not contribute

to both the likelihood of a reactor trip and the likelihood that mitigation equipment or

functions would not be available, and did not increase the likelihood of a fire or

internal/external flood. The finding was determined to be a Non-Cited Violation (NCV) of

10 CFR 50, Appendix B, Criterion V. (Section 1R06)

Cornerstone: Barrier Integrity

Green. The inspectors identified a finding of very low safety significance regarding

inadequate instructions in three procedures used to conduct ultrasonic examination of

plant components. Specifically, the licensee had not included the mode of ultrasonic

wave propagation for the material under examination in these procedures.

The finding was more than minor because, if left uncorrected, it could have adversely

affected the licensees ability to perform an adequate inspection of safety-related

components, including the reactor vessel. However, it was of very low safety

significance because the licensee confirmed that appropriate ultrasonic examinations

had been conducted during past examinations. This finding was determined to be an

NCV of 10 CFR 50.55a(g)(4). (Section 1R08)

4

Green. The inspectors identified a finding of very low safety significance regarding

failure to conduct a periodic technical review of an ultrasonic examination procedure

used to detect cracks in steam generator and main steam nozzle inner radii.

The finding was more than minor because, if left uncorrected, it could have resulted in

failure to incorporate the appropriate technical requirements into the procedure and

consequently led to an ineffective examination of plant components. The finding was of

very low safety significance because the appropriate technical review was completed

and only one technical error was identified which impacted the technical adequacy of the

procedure. This finding was determined to be an NCV of 10 CFR Part 50, Appendix B,

Criterion V. (Section 1R08)

Cornerstone: Emergency Preparedness

Green. On November 3, 2002, the licensee failed to classify and declare an Unusual

Event in accordance with emergency plan implementing procedures following receipt of

a seismic event annunciator in the control room and after confirmation with an offsite

agency of the occurrence of an earthquake in Alaska.

The failure to declare an Unusual Event is associated with a risk significant

planning standard and determined to be of very low safety significance using Manual

Chapter 0609, Appendix B, Emergency Preparedness Significance Determination

Process, Sheet 2. The finding was determined to be an NCV of 10 CFR 50.54(q),

50.47(b)(4), and Sections IV.B and IV.D.3 of Appendix E of 10 CFR Part 50.

(Section 4OA3)

B.

Licensee-Identified Violations

Two violations of very low safety significance, which were identified by the licensee,

have been reviewed by the inspectors. Corrective actions taken or planned by the

licensee have been entered into the licensees corrective action program. The violations

and corrective action tracking numbers are listed in Section 4OA7.

5

REPORT DETAILS

Summary of Plant Status

Unit 1 was operated at or near full power until the unit was shut down for a refueling outage on

November 15, 2002. Unit 1 was made critical for physics testing on December 5, and the unit

was placed online on December 6. Unit 1 reached full power on December 9, and operated at

or near full power for the remainder of the inspection period.

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

1.

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01

Adverse Weather Protection (71111.01)

a.

Inspection Scope

During the week of November 3, 2002, the inspectors conducted plant walkdowns and

document reviews to verify that the risk significant systems were adequately protected

against impending cold weather. The inspectors concentrated on the safety-related

cooling water (CL) pumps, safeguards traveling screens, nonsafety-related CL pumps,

and external circulating water deicing equipment. The inspectors used the licensee

checklists and procedures listed at the end of this inspection report to verify that the

systems were lined up as required. In addition, the inspectors reviewed the Corrective

Action Program (CAP) Action Requests (ARs) and work orders (WOs) listed at the end

of this report to verify that the licensee had entered problems identified with cold

weather operations into the corrective action system and was taking the appropriate

compensatory actions.

b.

Findings

No findings of significance were identified.

1R04

Equipment Alignment (71111.04)

.1

Partial System Walkdowns

a.

Inspection Scope

The inspectors performed partial walkdowns of accessible portions of the following

trains of risk-significant mitigating systems while the trains were of increased importance

due to the redundant trains or other related equipment being unavailable:

12 safety-related diesel-driven cooling water (DDCL) pump during the

unavailability of the 22 safety-related DDCL pump on October 22, 2002; and

6

21 component cooling water (CC) heat exchanger while the 22 CC heat

exchanger was out-of-service for temperature control valve calibration on

December 12.

The inspectors utilized the valve and electric breaker checklists listed at the end of this

report to verify that the components were properly positioned and that support systems

were lined up as needed. The inspectors also examined the material condition of the

components and observed operating parameters of equipment to verify that there were

no obvious deficiencies. The inspectors reviewed outstanding WOs and CAP ARs

associated with the trains to verify that those documents did not reveal issues that could

affect train function. The inspectors referred to the Technical Specifications (TSs) and

Updated Safety Analysis Report (USAR) to determine the functional requirements of the

systems. In addition, the inspectors reviewed the CAP ARs listed at the end of this

report to verify that the licensee was identifying issues at an appropriate threshold and

entering them into their corrective action program.

b.

Findings

No findings of significance were identified.

.2

Complete System Walkdowns

a.

Inspection Scope

On November 1, 2002, the inspectors reviewed the alignment of the Unit 1 safety

injection (SI) system outside of containment. On November 25, the inspectors reviewed

the portion of the system inside containment. This system was selected because it was

considered both safety-significant and risk-significant in the licensees probabilistic risk

assessment. The inspection consisted of the following activities:

a review of plant procedures (including selected abnormal and emergency

procedures), drawings, and the USAR to identify proper system alignment;

a review of outstanding or completed temporary and permanent modifications to

the system;

a review of control room operator log entries from February 1 through

November 1, to identify potential system issues; and

an electrical and mechanical walkdown of the system to verify proper alignment,

component accessibility, availability, and current condition.

The inspectors also reviewed selected issues documented in CAP ARs, to determine if

they had been properly addressed. Documents reviewed during this inspection are

listed at the end of this report.

b.

Findings

No findings of significance were identified.

7

1R05

Fire Protection Area Walkdowns (71111.05)

a.

Inspection Scope

The inspectors conducted fire protection walkdown of fire area 86, intake screenhouse

on October 9, 2002. During the walkdown, the inspectors focused on the availability and

accessibility of fire protection equipment, the condition of fire fighting equipment, the

control of transient combustibles, and the condition and operating status of installed fire

barriers as described in fire hazards analysis and pre-fire plans. 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).

Additionally, the inspectors assessed the inspected area for the potential to impact

equipment which could initiate a plant transient or that could impact the plants ability to

respond to a security event.

The inspectors reviewed the as-found condition of fire doors, dampers, penetration

seals, fire detectors, sprinklers, fire hoses and extinguishers, comparing the as-found

conditions to the configuration described in fire hazards analysis and pre-fire plans.

During this review, the inspectors verified equipment was in its appropriate location, was

available for immediate use, and was not obstructed. The inspectors also verified that

the as-found transient combustible loading was within the analyzed limits. The

inspectors reviewed applicable CAP ARs listed at the end of this report to verify that the

licensee was identifying fire protection issues at an appropriate threshold and entering

them into their corrective action program.

b.

Findings

No findings of significance were identified.

1R06

Flood Protection Measures (71111.06)

a.

Inspection Scope

On October 16, 2002, the inspectors reviewed and assessed protection measures for

internal flooding events. The inspectors evaluated whether the licensee took

appropriate precautions to mitigate the risk from internal flooding events. Specifically,

the inspectors performed the following:

reviewed the USAR and other selected design basis documents to identify those

areas susceptible to internal flooding;

reviewed the licensee's probabilistic risk analysis and associated flood protection

reports to identify risk significant flood areas and protective features;

reviewed abnormal and alarm response procedures associated with the

diagnosis and mitigation of flooding events;

performed a walkdown of the Units 1 and 2 safety-related DDCL pump rooms,

the common safety-related motor-driven cooling water (MDCL) pump room, and

the safeguards traveling screens room to evaluate whether appropriate flood

protection controls were being maintained; and

8

interviewed selected operating, engineering, and maintenance staff regarding

internal flood protection controls.

In addition, the inspectors reviewed the corrective action program to verify that identified

problems were being entered with the appropriate characterization and significance.

The inspectors also reviewed the corrective actions for flood protection related issues

documented in selected action requests.

b.

Findings

Introduction

On three separate occasions during the inspection period, inspectors identified the

existence of loose materials in the safety-related CL pump rooms. These materials

were specifically prohibited due to their potential adverse affect on required critical

drainage paths. The existence of these conditions resulted in a finding of very low

safety significance (Green) and a Non-Cited Violation (NCV) of NRC requirements.

Discussion

No deficiencies with the required flood protection measures were identified on

October 16. Subsequently, however, during routine plant walkdowns, the inspectors

identified the existence of loose materials in the safety-related cooling water pump

rooms that were specifically prohibited due to their potential adverse effect on required

critical drainage paths: on October 28, the inspectors identified two oil absorbent pads

in the 22 DDCL pump room; on November 6, the inspectors identified a temporary

power cable routed through a critical drainage path in the 12 DDCL pump room; and on

November 13, the inspectors identified a significant quantity of foreign material in the

121 MDCL pump room while the pump was aligned as a safety-related pump.

In each case listed above, the licensee failed to remove, properly control, or prevent

the introduction of materials that could block critical drainage paths associated with

operable safety-related CL pumps. Administrative Work Instruction 5AWI 8.9.0,

Section 6.2.2, states materials that could plug drainage paths be prevented from doing

so by tethering or anchoring the material when required equipment within the area is

operable. The materials identified by inspectors on October 28 and on November 13

were not tethered or anchored and in both cases the associated safety-related CL

pumps were considered operable.

In the November 6th case, Section 6.2.5 of 5AWI 8.9.0 states ensure temporary or

permanent changes that could impact drainage flow within any critical drainage area are

in accordance with the plants internal flooding analysis. The installation of the

temporary power cable identified by the inspectors had not been evaluated with respect

to the internal flooding analysis prior to its routing through the critical drainage area.

Analysis

The inspectors determined that this finding was more than minor. Inspection Manual

Chapter (IMC) 0612, Appendix E, Section 4, provides a number of examples of minor

9

procedural errors. Example a is similar to this case and indicates that a problem of

this type is more than minor if repetitive. The inspectors identified this issue on three

separate occasions within a 3-week period. The internal flood protection measures

required in these areas were not new requirements; the problems were in areas

routinely visited by operators; and the licensee missed opportunities to identify and

correct the issues in each of the cases prior to identification by inspectors. Additionally,

this finding was associated with two of the cornerstone attributes listed in IMC 0612,

Appendix BProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0612,</br></br>Appendix B" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., Section C and affected the initiating events cornerstone objective. For

example, the initiating events cornerstone objective to limit the likelihood of those events

that upset plant stability and challenge critical safety functions during shutdown as well

as power operations was affected by the materials that were introduced into the safety-

related CL pump rooms. Specifically, the design control and human performance

attributes were affected because the introduced materials changed the physical

conditions assumed in the internal flooding analysis. Therefore, for the time that these

conditions existed it could not be shown that the safety-related CL pumps would have

remained available during an internal flood. The loss of a safety-related cooling water

pump or pumps during an internal flood could upset plant stability.

The inspectors determined that the finding could be evaluated in accordance with

IMC 0609, Significance Determination Process [SDP], because the finding was

associated with an increase in the likelihood of an initiating event. Using the Phase 1

screening, the inspectors determined that the finding did not contribute to the likelihood

of a primary or secondary system loss of coolant accident, did not contribute to both the

likelihood of a reactor trip and the likelihood that mitigation equipment or functions would

not be available, and did not increase the likelihood of a fire or internal/external flood.

The inspectors determined the finding to be of very low safety significance (Green).

Enforcement

In part, 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,

states that activities affecting quality shall be accomplished in accordance with

instructions, procedures, or drawings. Contrary to the above, the licensee failed to

implement the requirements specified in procedure 5AWI 8.9.0, Section 6. Since the

licensee entered the conditions identified by the inspectors into their corrective action

program with AR CAP 026010, AR CAP 026158, and AR CAP 026291, this violation is

being treated as an NCV in accordance with VI.A.1 of the NRCs Enforcement Policy

(NCV 50-282/306/02-09-01).

1R07

Heat Sink Performance

a.

Inspection Scope

On November 15, 2002, the inspectors conducted a walkdown of the data acquisition

test equipment installed on the Unit 1 CC heat exchangers and observed the real-time

data obtained during pre-test equipment functional tests.

The inspectors reviewed the Unit 1 CC heat exchanger test data obtained from the

performance tests conducted on November 16. The inspectors compared the test

results to the heat exchangers required performance specified in the CC design basis

10

documents listed at the end of this report. The inspectors evaluated test data for

indications of heat exchanger deficiencies that could mask degraded performance and

other heat exchanger problems that would be indicative of potential common cause heat

sink problems that potentially could increase plant risk.

The inspectors reviewed the licensees performance with respect to the identification

and resolution of problems associated with heat sink performance problems. The

inspectors focused their evaluation on problems that could result in an initiating event or

affect multiple heat exchangers in mitigating systems, thereby increasing risk. A list of

corrective action documents reviewed by the inspectors has been included at the end of

this report.

b.

Findings

No findings of significance were identified.

1R08

Inservice Inspection Activities (71111.08)

a.

Inspection Scope

The inspectors evaluated the implementation of the licensees inservice inspection

program for monitoring degradation of the reactor coolant system (RCS) boundary and

risk significant piping system boundaries, based on review of records and in-process

observation of nondestructive examinations.

From November 18 through November 26, 2002, the inspectors observed:

ultrasonic (UT) examination of an elbow-to-pipe weld W-3 and safe-end-to-elbow

weld W-2 on the pressurizer safety relief line inside the Unit 1 containment;

UT examination of a reducer-to-safe-end weld W-13 on the pressurizer spray

line inside the Unit 1 containment;

dye penetrant (PT) examination of pipe-to-elbow weld W-25 on the residual heat

removal (RHR) pump loop B line inside the Unit 1 containment;

PT examination of the pipe-to-elbow weld W-6 on RCS loop A inside the Unit 1

containment;

PT examination of the nozzle-to-pipe weld W-12 on RCS crossover loop A inside

the Unit 1 containment;

acquisition and evaluation of eddy current (ET) data on the Unit 1 steam

generators (SGs), which occurred in a service building outside the protected

area;

video taped visual examination of the secondary side inspection of SG 11 at the

top of the tubesheet to locate potential loose parts, which occurred in a service

building within the protected area; and

in situ pressurization of two SG tubes inside the Unit 1 containment. The tubes

tested were located in SG 11 at row 14, column 31, and row 11, column 37, and

each contained a single axial ET indication located just above the top of the

tubesheet.

From November 18 through November 26, 2002, the inspectors reviewed:

11

repair and replacement records required by the American Society of Mechanical

Engineers (ASME) Code for the performance of a preventative weld buildup on

the control rod drive intermediate canopy seal weld and the replacement of the

B loop pressurizer spray valve CV 31225; and

nondestructive examination reports with Code recordable indications identified

during previous UT and PT examinations.

The records reviewed and activities observed were evaluated for conformance with

requirements in Section III, V, IX, and XI of the ASME Code.

The inspectors also reviewed a sample of inservice inspection related problems

documented in the licensees corrective action program, to assess conformance with

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements.

b.

Findings

(1)

Missed SG 12 and SG 21 Tubesheet-to-Head Weld UT Examinations

Introduction

On November 25, 2002, the inspectors identified an unresolved item (URI) associated

with the licensees failure to perform a volumetric examination of the Unit 1 SG 12 and

Unit 2 SG 21 tubesheet-to-head W-A welds during the 1999 and 2002 refueling

outages, respectively. At the conclusion of this inspection, the inspectors could not

determine the risk of this finding because the licensee had not yet completed re-

examination of these welds to determine the size and significance of weld flaws left in

service.

Description

For Unit 1, the licensee identified a flaw during the 1999 UT examination of the SG 11

tubesheet-to-head weld W-A that exceeded Code acceptance standards of Table

IWB-3410-1. The licensee accepted the flaw based on an analysis derived in

Westinghouse document WCAP 14166, Handbook on Flaw Evaluation for Prairie

Island Units 1 and 2 Steam Generators and Pressurizer. However, the licensee did not

examine the SG 12 W-A weld during this outage as required by paragraph IWB-2430 of

Section XI of the 1989 Edition, no Addenda, of the ASME Code. For the SG 12 W-A

weld, the licensee had not completed a UT examination since 1998. The licensee

entered the failure to perform the SG 12 W-A weld examination into the corrective action

system (CAP 026715) and no immediate operability evaluation was required because

Unit 1 was in cold shutdown. The licensee subsequently initiated actions to perform

examinations of the Unit 1 SG 11 and SG 12 W-A welds during the current refueling

outage.

During the extent of condition review, the licensee identified that a similar condition also

existed for the Unit 2 SG W-A welds. When the licensee examined the SG 22 weld W-A

in February of 2002, 14 flaws were identified which exceeded Code acceptance

standards of Table IWB-3410-1. The licensee applied a weld flaw analysis derived in

12

WCAP 14166 to accept these flaws for continued service. However, the licensee did

not expand the scope of the inspection to include UT examination of the SG 21 weld

W-A. The licensee last performed a UT examination of one-third of the SG 21 weld

W-A in May of 2000. The licensee entered the failure to perform the SG 12 W-A weld

examination into the corrective action system (CAP 026755), considered that the SG 21

weld W-A was operable, and was evaluating the need to seek NRC approval for Code

relief to allow deferral of this weld examination until the next refueling outage in the fall

of 2003. In operability recommendation (OPR) 000360, the licensee concluded that the

SG 21 W-A weld was operable because only Code acceptable indications were

identified during the previous two UT examinations conducted in 1997 and 2000, which

provided assurance that no structurally significant flaws could exist. The inspectors

noted that the licensee had last performed a full inspection of this weld in 1993 and had

not established a basis for their conclusion that no structurally significant flaws were

present. The licensee subsequently revised OPR 000360 and included a technical

evaluation of the potential inservice flaw sizes based on a methodology established in

WCAP 14166. The licensees revised OPR considered embedded flaw growth using a

series of loading transients with the maximum applied stress intensity factor for the

maximum size flaw detected. Based on this methodology, the licensee concluded that

the indications identified during the 2000 refueling outage were acceptable for 10 years

of service without further inspection and SG 21 was operable. The inspectors noted that

the application of WCAP 14166 to inservice flaws in SG W-A welds had been accepted

by the NRC for previous flaw evaluations, however, not as a basis to allow deferring the

required Code examinations.

The licensee was in the third Code interval and was committed to the requirements of

Section XI, 1989 Edition, no Addenda, of the ASME Code for these inservice

examinations. Specifically, the SG head-to-tubesheet W-A welds were required to be

volumetrically examined once per Code interval (10 years) in accordance with the Table

IWB-2500 Category B.2.40. Section XI, IWB-2430 required Examinations performed in

accordance with Table IWB-2500-1 that reveal indications exceeding the acceptance

standards of Table IWB-3410-1 shall be extended to include additional examinations at

this outage. The additional examinations shall include the remaining welds, areas, or

parts included in the inspection item listing... This statement required the licensee to

take prompt (at this outage) actions to determine the extent of potential degradation

when inservice weld flaws were identified which exceed Code limits. Therefore, the

inspectors were concerned that the licensees decision to not examine SG 12 and

SG 21 W-A welds during the 1999 and 2002 refueling outages could have potentially

allowed weld flaws of unacceptable size to remain in service.

The licensee staff discussed their decision to not apply the Section XI, IWB-2430

requirements to expand the scope of weld examinations for these SG W-A welds. The

licensee staff had applied a successive examination schedule discussed in Section XI,

IWB-2420 to the SG 11 and SG 22 W-A welds because flaws were identified that

required an analysis to leave in service. The licensee staff then excluded application of

IWB-2430 requirements to expand the extent of weld examinations to SG 12 and SG 21

W-A welds, because SG 11 and SG 22 W-A welds were in a successive examination

schedule. The licensee staff had interpreted the Section XI, IWB-2430 statement

examinations performed in accordance with Table IWB-2500-1, to allow excluding

expansion of weld examinations for new weld flaws identified during successive

13

examinations performed under IWB-2420. Section XI, IWB-2420(b) required If flaw

indications or relevant conditions are evaluated in accordance with IWB-3132.4 or

IWB-3142.4, respectively, and the component qualifies as acceptable for continued

service, the areas containing such flaw indications or relevant conditions shall be

reexamined during the next three inspection periods listed in the schedules of inspection

programs of IWB 2410. For SG 11 and SG 22 the licensee was performing these

successive examinations beginning in 1994 for SG 11 and 1989 for SG 22 after

identification of subsurface flaws which exceeded acceptable sizes as identified in

Table IWB-3410-1. The licensee staff believed that these subsurface flaw indications

which exceeded Code acceptance criteria, were likely fabrication-related weld defects

(e.g., slag, inclusions or weld porosity), vice service-induced. However, the licensees

manual UT examination methods were not sufficient to confirm the flaw locations or to

determine changes in flaw size (e.g., flaws indications sometimes got smaller in

subsequent examinations). Therefore, the licensee staff had considered each flaw

identified in the SG W-A welds that exceeded Code acceptance criteria during these

examinations to be a new flaw.

The inspectors requested the licensee provide a technical basis to support their

application of Code requirements to not expand the scope of the SG W-A weld

examinations. At the conclusion of the inspection, the licensee staff did not have a

documented technical basis, nor an NRC-endorsed Code Case, which supported their

potentially nonconservative application of Code requirements.

Analysis

The licensee performance deficiency associated with this finding was a failure to follow

the ASME Code examination expansion requirements to volumetrically examine weld

W-A on SG 12 and SG 21 during the 1999 and 2002 refueling outages respectively.

The inspectors reviewed this issue against the guidance contained in Appendix B, Issue

Dispositioning Screening, of IMC 0612, Power Reactor Inspection Reports. In

particular, the inspectors compared this finding to the findings identified in Appendix E,

Examples of Minor Issues, of IMC 0612 to determine whether the finding was minor.

Following that review, the inspectors concluded that the guidance in Appendix E was not

applicable for the specific finding since no examples were provided which involved

failure to perform inservice examinations. As a result, the inspectors compared this

performance deficiency to the minor questions contained in Section C, Minor

Questions, to Appendix B of IMC 0612. The inspectors concluded that the issue was

more than minor because the finding, if left uncorrected, could become a more

significant safety concern. Specifically, the licensees failure to volumetrically examine

weld W-A in SG 12 and SG 21 could have resulted in plant operation with unacceptable

weld flaws that challenged the reactor coolant pressure boundary integrity.

As a result, the inspectors reviewed this issue in accordance with IMC 0609,

Significance Determination Process. The inspectors conducted this review utilizing the

SDP Phase 1 Screening Worksheet for IE [Initiating Events], MS [Mitigating Systems]

and B [Barrier Integrity] Cornerstones. The inspectors determined that this issue

potentially affected the NRCs Barrier Integrity Cornerstone. However, the inspectors

could not evaluate the significance of this issue until the licensee completed UT

14

examination of SG 12 weld W-A and SG 21 weld W-A to determined the size and

significance of weld flaws left in service.

Enforcement

Requirements of 10 CFR 50.55a(g)(4) are, in part, that throughout the service life of a

pressurized water-cooled nuclear power facility, components must meet the

requirements set forth in the ASME Code,Section XI. Section XI, IWB-2430 required

Examinations performed in accordance with Table IWB-2500-1 that reveal indications

exceeding the acceptance standards of Table IWB-3410-1 shall be extended to include

additional examinations at this outage. The additional examinations shall include the

remaining welds, areas, or parts included in the inspection item listing...

Contrary to these requirements, on May 22, 1999, the licensee performed an

examination as described in Table IWB-2500-1 (Code item B.2.40) for Unit 1 SG 11

weld W-A that revealed an indication which exceeded the acceptance standards of

Table IWB-3410-1 and failed to include additional examinations of the remaining Code

item B.2.40 welds of Table IWB-2500-1 during the 1999 outage. Specifically, the

licensee failed to perform a volumetric examination of weld W-A on SG 12 during the

1999 outage and this weld had not received a volumetric inspection since 1998.

Contrary to these requirements, on February 15, 2002, the licensee performed an

examination as described in Table IWB-2500-1 (Code item B.2.40) for Unit 2 SG-22

weld W-A that revealed 14 indications which exceeded the acceptance standards of

Table IWB-3410-1 and failed to include additional examinations of the remaining Code

Item B.2.40 welds of Table IWB-2500-1 during the 2002 Unit 2 refueling outage.

Specifically, the licensee failed to perform a volumetric examination of weld W-A on

SG 21 during the February 2002 outage and this weld had not received a volumetric

inspection since May 2000.

Because the significance of this finding is not yet known, it is considered an Unresolved

Item (URI 50-282/306/02-09-02) pending completion of a UT examination of weld W-A

on SG 12 and weld W-A on SG 21.

(2)

Lack of ASME Code Requirement in Ultrasonic Examination Procedures

Introduction

The inspectors identified a finding of very low significance (Green) and an associated

NCV of 10 CFR 50.55a(g)(4) related to inadequate instructions in three procedures used

to conduct ultrasonic examination of plant components.

Description

On November 20, 2002, the inspectors identified three procedures used for

conducting UT examinations of ASME Code components, that lacked a Code

requirement to specify the mode of wave propagation in the material. Specifically,

procedures ISI-UT-3, Ultrasonic Examination of Ferritic Vessels, Revision 10,

ISI-UT-3A, Ultrasonic Examination of Reactor Vessel Welds, Revision 8, and

15

ISI-UT-5E, Ultrasonic Examination of Steam Generator Primary and Main Steam

Nozzle Inner Radii, Revision 1, lacked instructions which described the mode of wave

propagation in the material under examination. The inspectors were concerned that

failure to include this Code requirement could result in the licensee staff selecting an

incorrect UT transducer, which could result in an ineffective weld examination. For

example, an L-wave transducer produces both a refracted shear wave and longitudinal

wave within the material examined. These two sound waves enter the material at

different angles and propagate at different speeds which could cause the licensee staff

to misinterpret flaw signals or misinterpret the extent of weld examination coverage

achieved.

Analysis

The licensee performance deficiency associated with this finding was failure to

incorporate an ASME Code requirement to specify the mode of wave propagation into

procedures ISI-UT-3, ISI-UT-3A and ISI-UT-5E. The inspectors reviewed this issue

against the guidance contained in Appendix B, Issue Dispositioning Screening, of

IMC 0612, Power Reactor Inspection Reports. In particular, the inspectors compared

this finding to the findings identified in Appendix E, Examples of Minor Issues, of

IMC 0612 to determine whether the finding was minor. The inspectors concluded that

the guidance in Appendix E was not applicable for the specific finding since no

examples were provided which involved procedure errors which could lead to ineffective

weld examinations affecting the pressure boundary integrity. As a result, the inspectors

compared this performance deficiency to the minor questions contained in Section C,

Minor Questions, to Appendix B of IMC 0612. The inspectors concluded that the issue

was more than minor because the finding, if left uncorrected, could become a more

significant safety concern, in that it could have adversely affected the licensees ability to

detect flaws in safety-related components, including the reactor vessel. The failure to

specify the mode of wave propagation could have allowed the licensee inspection staff

to select an L-wave transducer when a shear wave transducer was appropriate or vice

versa. The use of an incorrect transducer could render the weld examination ineffective,

in that unacceptable weld flaws could potentially go undetected. Based on review of

past examination records, the licensee determined that improper transducers had not

been used for previous UT examinations. The licensee subsequently initiated changes

to the procedures to include the mode of wave propagation in the material under

examination.

As a result, the inspectors reviewed this issue in accordance with IMC 0609

Significance Determination Process, utilizing the SDP Phase 1 Screening

Worksheet for IE, MS and B Cornerstones. The inspectors determined that none

of the above cornerstones were directly impacted by this finding. Therefore, the

inspectors concluded that this issue was not suited for SDP analysis, in accordance

with Section 0506.b(3) of IMC 0612. Because this issue had not resulted in an

ineffective weld examination, the inspectors concluded that it was of very low risk

significance (Green).

16

Enforcement

Requirements of 10 CFR 50.55a(g)(4) are, in part, that throughout the service life of a

pressurized water-cooled nuclear power facility, components must meet the

requirements set forth in ASME Code,Section XI. Section XI, Article I-2100 required

Ultrasonic examination of vessel welds greater than 2 inches thickness shall be

conducted in accordance with Article 4 of Section V... Section V, Article 4, T-423,

Written Procedure Requirements, required Each procedure shall include at least the

following information: ..(f) angles and mode(s) of wave propagation in the material.

Contrary to these requirements, on November 20, 2002, the inspectors identified

that procedures ISI-UT-3, Ultrasonic Examination of Ferritic Vessels, Revision 10,

ISI-UT-3A, Ultrasonic Examination of Reactor Vessel Welds, Revision 8, and

ISI-UT-5E, Ultrasonic Examination of Steam Generator Primary and Main Steam

Nozzle Inner Radii, Revision 1, did not specify the mode(s) of wave propagation in

the material. The failure to specify the mode(s) of wave propagation in the material in

these procedures were examples where the requirements of 10 CFR 50.55a(g)(4) were

not met and was a violation. However, because of the very low safety significance

and because the issue was entered into the licensees corrective action program

(CAP 026513), it is being treated as an NCV, consistent with Section VI.A.1 of the

Enforcement Policy (NCV 50-282/306/02-09-03).

(3)

Missed Technical Review for Ultrasonic Examination Procedure

Introduction

The inspectors identified a finding of very low significance (Green) and an associated

NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,

related to a failure to conduct a periodic technical review for an ultrasonic examination

procedure used to detect cracks in SG and main steam nozzle inner radii.

Description

On November 20, 2002, the inspectors identified that the licensee had failed to perform

a periodic review for technical adequacy of procedure ISI-UT-5E used to perform

ultrasonic examination of SG and main steam nozzle inner radii. The licensee issued

this procedure in 1997, and as of November 20, 2002, had not performed a review to

confirm that it was up-to-date with current requirements and technically accurate.

Further, the inspectors had discovered a technical error associated with the mode of

wave propagation in this procedure as discussed in Section 1R08.b.(2) above, which

could have affected the effectiveness of the UT examination. During the extent of

condition review for this issue, the licensee staff identified 11 other non-destructive

examination procedures associated with the erosion-corrosion control program

(e.g., monitors pipe wall loss) that had not received this periodic review. The licensee

personnel had failed to enter these procedures into the Document Review Database,

which the licensee used to track implementation of the required procedure reviews.

17

Analysis

The licensee performance deficiency associated with this finding, was failure to perform

a periodic review for technical adequacy of procedure ISI-UT-5E. The inspectors

reviewed this issue against the guidance contained in Appendix B, Issue Dispositioning

Screening, of IMC 0612, Power Reactor Inspection Reports. In particular, the

inspectors compared this finding to the findings identified in Appendix E, Examples of

Minor Issues, of IMC 0612 to determine whether the finding was minor. The inspectors

concluded that the guidance in Appendix E was not applicable for the specific finding

since no examples were provided which involved failure to conduct technical reviews of

procedures which are used to confirm the integrity of the reactor coolant pressure

boundary. As a result, the inspectors compared this performance deficiency to the

minor questions contained in Section C, Minor Questions, to Appendix B of IMC 0612.

The inspectors concluded that the issue was more than minor because the finding, if left

uncorrected, could become a more significant safety concern. Specifically, the

inspectors were concerned that the failure to perform this review for procedure

ISI-UT-5E could result in failure to incorporate the appropriate technical requirements

and consequently lead to an ineffective examination of plant components. The licensee

subsequently completed the reviews for procedure ISI-UT-5E (and the 11 others

identified by the licensee) and did not identify any technical errors, other than the one

technical error associated with mode(s) of wave propagation as discussed in Section

1R08.b.(2). As a result, the inspectors reviewed this issue in accordance with IMC 0609

Significance Determination Process, utilizing the SDP Phase 1 Screening Worksheet

for IE, MS and B Cornerstones. The inspectors determined that none of the above

cornerstones were directly impacted by this finding; therefore, this issue was not suited

for SDP analysis in accordance with Section 0506.b(3) of IMC 0612. Because this issue

had not resulted in ineffective examinations of plant components, the inspectors

concluded that it was of very low risk significance (Green).

Enforcement

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,

required, in part, that Activities affecting quality shall be prescribed by documented

instructions, procedures, or drawings, of a type appropriate to the circumstances and

be accomplished in accordance with these instructions, procedures, or drawings.

Procedure MMRN 1.1, Reference Manual Policy and Administration, Revision 0

required that all procedures shall be reviewed and/or revised within a 36-month period.

Contrary to these requirements, the inspectors identified that as of November 20, 2002,

procedure ISI-UT-5E, Ultrasonic Examination of Steam Generator Primary and Main

Steam Nozzle Inner Radii Revision 1, had not received a review/revision within the

36-month period following the initial procedure issue date of October 6, 1997. The

failure to conduct a periodic review of this procedure for technical adequacy was an

example of where the requirements of 10 CFR 50, Appendix B, Criterion V, were not

met and was a violation. However, because of the very low safety significance and

because the issue was entered into the licensees corrective action program

(CAP 026514 and CAP 026574), it is being treated as an NCV, consistent with

Section VI.A.1 of the Enforcement Policy (NCV 50-282/306/02-09-04).

18

1R11

Licensed Operator Requalification (71111.11)

.1

Written Examination and Operating Test Results

a.

Inspection Scope

The inspectors reviewed the pass/fail results of individual written tests, operating tests,

and simulator operating tests (required to be given per 10 CFR 55.59(a)(2))

administered by the licensee during calendar year 2002.

b.

Findings

No findings of significance were identified.

1R12

Maintenance Effectiveness (71111.12)

.1

Multiple Cooling Water Pump Bearing/Seal Water Failures

a.

Inspection Scope

On October 19, 2002, the inspectors reviewed AR CAPs 023088, 024290, 024661,

024872, 025483, 025825, and 025866 that identified problems with safety-related

CL pump bearing/seal water. The proper operation of CL pump bearing/seal water

supports the operability of the safety-related CL pumps that provide several safety-

significant maintenance rule functions.

The inspectors performed an in-office review of corrective action program documents

associated with the bearing/seal water failures. The inspectors compared the licensees

maintenance documentation to the requirements contained in the administrative work

instruction (AWI) procedures for the performance of nuclear maintenance, investigation,

and troubleshooting. The documents reviewed are listed at the end of this report.

The inspectors reviewed the licensees implementation of the maintenance rule for the

repeat failures of the bearing/seal water by comparing their actions to the requirements

contained in the Maintenance Rule, 10 CFR 50.65, and Industry Guidelines for

Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, NUMARC 93-01.

The inspectors evaluated whether the safety-related CL pumps were scoped in

accordance with the maintenance rule, and whether the performance problems

associated with bearing/seal water constituted maintenance preventable functional

failures.

b.

Findings

No findings of significance were identified.

19

.2

Auxiliary Building Roof Leakage

a.

Inspection Scope

On October 25, 2002, the inspectors evaluated the licensees disposition of the

problems documented in General Condition Report (GEN) 200202455 and AR

CAP 024598. Both of these corrective action documents identified equipment failures

caused by auxiliary building roof leakage. During the review of these problems, the

inspectors evaluated the licensees use of appropriate work practices, review of

problems for common cause failures, Maintenance Rule scoping, Maintenance Rule

classification, Maintenance Rule performance criteria, and the trending of key

performance parameters. The inspectors compared the actions taken by the licensee in

response to these problems to established maintenance, Maintenance Rule

implementation procedures, and documents listed at the end of this report. In addition,

the inspectors reviewed the corrective action program documents listed at the end of

this report to verify that the licensee had entered problems identified with effectiveness

of maintenance and the implementation of the Maintenance Rule into their corrective

action program.

b.

Findings

No findings of significance were identified.

.3

Resolution of External Circulating Water Intake Screen Bypass Gate Repeat Failures

URI 50-282/306/02-08-02

a.

Inspection Scope

On August 20, 2002, during a previous inspection, while investigating the repeat failures

of the external circulating water intake screen bypass gates, the inspectors identified

that the licensee had inappropriately classified the bypass gates as low safety significant

components. Since the bypass gates were improperly classified, the licensees

performance criteria were also inappropriate and bypass gate failures were not properly

evaluated for maintenance preventable functional failures. The inspectors determined

that the inappropriate maintenance rule safety significance classification of the intake

bypass gates was a Green Finding. The inspectors concluded that a violation

determination could not be completed until appropriate performance criteria for the low

safety significant standby safety significance classification were first established by the

maintenance rule expert panel. The need to evaluate the finding for violations of NRC

requirements was left as an Unresolved Item (URI 50-282/306/02-08-02).

During the current inspection, on November 29, the inspectors reviewed the

licensees new performance criteria for the bypass gates, (a)(1) evaluation of gate

failures in the previous 2 years, and the Maintenance Rule Expert Panel minutes

from November 27. The inspectors compared the changes to the guidance provided in

NUMARC 93-01 and the requirements of the Maintenance Rule, 10 CFR 50.65.

20

b.

Findings

The inspectors determined that the performance of the bypass gates had not exceeded

(a)(2) performance criteria. URI 50-282/306/02-08-02 is closed. No findings were

identified.

1R13

Maintenance Risk Assessments and Emergent Work Control (71111.13)

a.

Inspection Scope

The inspectors reviewed the licensees management of plant risk during emergent

maintenance activities and during activities where more than one risk significant system

or train was unavailable. The activities were chosen based on their potential for

increasing the probability of an initiating event or impacting the operation of safety

significant mitigating equipment. The inspection was conducted to verify 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 reviewed daily configuration risk assessment

records, observed shift turnover meetings, observed daily plant status meetings, and

reviewed risk assessment documents listed at the end of this report to verify that the

equipment configurations were properly listed, that protected equipment was identified

and controlled, and that significant aspects of plant risk were communicated to the

necessary personnel. The inspectors discussed daily and emergent risk assessments

with risk assessment engineers and operators.

The inspectors reviewed the following emergent and planned maintenance activities

associated with the simultaneous unavailability of the listed maintenance rule risk

significant systems:

on October 16, 2002, the simultaneous unavailability of the 22 turbine-driven

auxiliary feedwater (AFW) pump, 124 air compressor, 121 intake bypass gate,

and 121 screenwash pump;

on October 21, the simultaneous unavailability of the 22 DDCL pump and the

D2 emergency diesel generator;

on October 28, the simultaneous unavailability of the 21 RHR pump and

123 instrument air compressor; and

on November 4, the simultaneous unavailability of the 121 instrument air

compressor, 121 screenwash pump, 121 bypass gate, D1 emergency diesel

generator, 11 RHR pump discharge to 11 SI pump suction motor-operated valve

MV 32206, and 11 AFW pump.

The inspectors reviewed several ARs to verify that problems associated with plant risk

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

commensurate with the significance of the issue were identified and implemented. A

detailed list of the documents reviewed during this inspection is included at the end of

the report.

21

b.

Findings

No findings of significance were identified.

1R14

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

.1

Licensee Response to a Seismic Alarm Received Following Alaskan Earthquake

a.

Inspection Scope

On November 3, 2002, a seismic alarm was received in the control room. Operators

entered Abnormal Operating Procedure AB-3, Earthquakes. The inspectors reviewed

the operators response to this unplanned event and compared their actions to the

actions specified in annunciator response procedures, abnormal operating procedures,

and the emergency plan implementing procedures.

b.

Findings

The licensee entered AB-3 on receipt of the alarm and confirmed the occurrence of an

earthquake in Alaska by contacting the National Earthquake Information Center in

Boulder, Colorado. The control room seismic monitor energized, the Seismic Event

annunciator was received, and magnetic tape recorder operation initiated. However, a

failure of the seismic monitor chart paper recorder to produce a visible indication on its

chart paper prevented the timely evaluation of the peak acceleration experienced during

the event. Additionally, the failure of operators to follow the emergency plan

implementing procedure for event classification prevented classification and declaration

of the event. This finding is discussed in detail in Section 4OA3 of this report.

.2

Planned Non-Routine Evolution Observed During the Unit 1 Refueling Outage

a.

Inspection Scope

The inspectors observed planned non-routine activities performed during the Unit 1

refueling outage. The inspectors reviewed operator performance and compared their

actions to the specified actions contained in plant operating, annunciator response, and

abnormal operating procedures. Among the significant activities the inspectors

observed during the refueling outage were the unit shutdown, cooldown, and entry into

RHR operations on November 16, 2002; RCS draindown activities and reactor vessel

head removal on November 20; RCS operation at reduced inventory conditions for

installation and removal of SG nozzle dams on November 18 and 27; RCS fill and

venting; RCS heat up to normal operating temperature and pressure; reactor startup;

and synchronization of the main generator to the grid from December 2 through

December 5. The inspectors reviewed CAP ARs to verify that minor issues identified

during the performance of these activities were identified and entered into the licensees

corrective action system for resolution.

b.

Findings

No findings of significance were identified.

22

1R15

Operability Evaluations (71111.15)

a.

Inspection Scope

The inspectors evaluated plant conditions, selected action requests, and other

corrective action process documents associated with risk significant components and

systems for which operability was questioned. On October 8, 2002, the inspectors

evaluated the licensees assessment of operability for the Units 1 and 2 containment

buildings after the most recent loss-of-coolant accident analysis revealed a post-

accident containment temperature in excess of the temperature assumed in the

containment fan cooling unit heat removal analysis. This condition was evaluated to

determine whether the continued operability of the containment structure and the

systems located inside the containment structure were justified. The inspectors

compared the containment structure and systems design criteria in TSs and USAR to

the operability evaluation to verify that the containment structure and systems would

remain operable. The inspectors verified that compensatory measures identified in the

operability evaluation were in place, functioned as intended, and were properly

controlled. A detailed list of the documents reviewed during this inspection is included at

the end of the report.

b.

Findings

No findings of significance were identified.

1R16

Operator Workarounds (OWAs) (71111.16)

.1

Review of Selected Workarounds

a.

Inspection Scope

On November 1, 2002, the inspectors reviewed OWAs associated with venting of

SI pumps to mitigate possible gas intrusion. The venting activity required operators to

stand on the respective SI pump. The inspectors verified that the functional capability

of the system, human reliability in responding to an initiating event, or the ability of

operators to implement abnormal or emergency operating procedures were not

significantly affected. The inspectors reviewed the applicable sections of the USAR

and TSs and discussed the OWAs with control room operators. The inspectors also

reviewed operator logs to identify any potential conditions that should be considered

OWAs. A detailed list of the documents reviewed during this inspection is included at

the end of the report.

b.

Findings

No findings of significance were identified.

23

.2

Cumulative Effects of OWAs

a.

Inspection Scope

On December 12, 2002, the inspectors reviewed the cumulative effect of all identified

OWAs to determine if there was a significant impact on plant risk or on the operators

ability to respond to a transient or an accident. The inspectors used the documents

listed at the end of this report to evaluate the list of OWAs. The inspectors discussed

the list of current OWAs with the operations support manager.

b.

Findings

No findings of significance were identified.

1R17

Permanent Plant Modifications (71111.17)

a.

Inspection Scope

During the week ending November 16, 2002, the inspectors reviewed design change

modification 02CL01. This modification provided a new normal source of bearing and

shaft lubrication water from the well water system, while retaining the safety-related

supply from the CL system on the 22 DDCL pump. The inspectors reviewed and

compared the systems design basis, licensing basis, and performance capability to the

installed modification in order to verify that the system performance had not been

degraded by the installation of the modification. The inspectors also reviewed changes

that the modification installation did not place the plant in an unsafe configuration.

The inspectors considered the design adequacy of the modification by performing a

review of the modifications impact on the plants material requirements and

replacement components, response time, control signals, equipment protection,

operation, failure modes, and other related process requirements.

b.

Findings

No findings of significance were identified.

1R19

Post-Maintenance Testing (71111.19)

a.

Inspection Scope

The inspectors reviewed post-maintenance testing activities associated with

maintenance on important mitigating, barrier integrity, and support systems to ensure

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

successful, and that operability was restored. The inspectors reviewed the appropriate

sections of the TSs, USAR, and maintenance documents to determine the systems

safety functions and the scope of the maintenance. In addition, the inspectors reviewed

ARs to verify that minor deficiencies identified during these inspections were entered

into the licensees corrective action system. A detailed list of the documents reviewed

during this inspection is included at the end of the report.

24

The inspectors observed and evaluated the post-maintenance activities for the following:

124 air compressor following 1000-hour preventive maintenance (PM) on

October 17, 2002, WO 0206295;

22 DDCL pump following annual inspection and other maintenance activities on

October 24, WO 025889;

11 SI pump following corrective and preventive maintenance on November 6,

WO 0114563;

22 DDCL pump following PM on November 15, WO 0204494; and

22 DDCL pump following installation of a new source of bearing water on

December 16, WO 0211272.

b.

Findings

No findings of significance were identified.

1R20

Refueling and Other Outage Activities (71111.20)

a.

Inspection Scope

The inspectors observed activities and/or reviewed documents associated with the

Unit 1 refueling outage. The inspectors reviewed the outage plan and schedule in order

to verify that the shutdown risk had been adequately evaluated in accordance with the

licensees shutdown safety assessment procedures. The inspectors routinely reviewed

the licensees shutdown risk assessments comparing the licensees assessment to plant

equipment configuration and procedural requirements for shutdown risk assessments.

During this review, the inspectors also reviewed the capability of plant equipment to

perform critical safety functions. The inspectors also observed portions of the fuel

handling operations in containment, in the spent fuel pool, and in the control room. The

inspectors verified that the licensee performed these activities in accordance with TSs

and approved fuel handling procedures. The inspectors conducted a containment

cleanliness inspection near the end of the outage to verify that no material remained in

containment that could impair flow to the containment recirculation sump.

b.

Findings

No findings of significance were identified.

1R22

Surveillance Testing (71111.22)

a.

Inspection Scope

The inspectors observed selected surveillance tests and/or reviewed test data to verify

that the equipment performance met surveillance procedure (SP) acceptance criteria.

The inspectors verified that the tested equipment was capable of performing its intended

safety functions as described in TSs and the USAR. The inspectors verified that the

testing met the required TS frequency; that the tests were conducted in accordance with

the applicable procedures; that operators met prerequisites and established the proper

plant conditions; and that the results of the tests were properly reviewed and recorded.

25

In addition, the inspectors reviewed several ARs to verify that the licensee was

identifying surveillance problems at an appropriate threshold, and that corrective actions

commensurate with the significance of the issue were identified and implemented. A

detailed list of the documents reviewed during this inspection is included at the end of

the report.

The following tests were observed and/or evaluated:

Unit 1 RCS Bolting Inspection, SP 1392, on November 16, 2002;

Unit 2 Integrated Safety Injection Test with Simulated Loss of Offsite Power,

SP 1083, on November 17;

Safety Injection Check Valve Test (Head Off) Part B: Refueling Water Storage

Tank (RWST) to RHR Flow Path Verification, SP 1092B, on November 20;

SI Check Valve Test (Head Off) Part A: High Head SI Flow Path Verification,

SP 1092A, on November 21;

Core Inventory Verification, SP 1177, on November 25;

D2 Diesel Generator Monthly Slow Start Test, SP 1305, and D2 Diesel

Generator 18-Month 24-Hour Load Test, SP 1335, on November 25 - 26;

Reactor Protection Logic Time Response Test, SP 1008, on December 2;

Safety Injection Check Valve Test (Head On) Part D, SP 1092D, and Turbine

Building Cooling Water Header Isolation SI Relays 1SI-12X and 1SI-22X Contact

Verification Test, SP 1126, on December 2 - 3;

Unit 1 Containment Coating Inspection, SP 1834, on December 4;

Reactor Coolant System Integrity Test, SP 1070, on December 4; and

Post-Outage Containment Close-Out Inspection, SP 1750, on December 5.

b.

Findings

No findings of significance were identified.

1R23

Temporary Plant Modifications (71111.23)

.1

Temporary Modification 02T131 Temporary Pipe Patch on a Pinhole Leak in Line

14-ZX-6

a.

Inspection Scope

On October 3, 2002, the inspectors reviewed Temporary Modification 02T131 that

installed a temporary pipe patch on a pinhole leak in line 14-ZX-6, the cooling water

supply line to Unit 1 and Unit 2 . The cooling water line itself was not considered a

risk significant component; however, the location of the leak was in close proximity to a

480-volt motor control center (MCC) that provided power to risk significant mitigating

system components. Due to the close proximity of the patch to the safety-related MCC,

the inspectors considered this temporary modification appropriate for inspection since it

could adversely affect the availability, reliability, or functional capability of risk significant

mitigating system components powered from the MCC.

The inspectors reviewed the associated 10 CFR 50.59 safety evaluation screening,

comparing it with system design basis requirements in the USAR. The inspectors

26

discussed the installation of the pipe patch with design engineers and compared the use

of the pipe patch temporary repair to Construction Code B-31.1 (1969) criteria.

b.

Findings

No findings of significance were identified.

.2

Temporary Modification 02T147 Temporary Pipe Clamp on the Instrument Air Supply

Header to the Unit 2 Containment

On October 22, 2002, an air leak was discovered on the 2-inch instrument air header

that feeds the Unit 2 containment. The air leak was caused by degradation of a solder

joint between supply piping and an adjacent elbow. The licensee installed a pipe clamp

as a preventive measure to preclude separation of the pipe from the elbow if solder joint

integrity were to further degrade.

On October 31, the inspectors reviewed Temporary Modification 02T147, which was

used for installation of the clamp on the header. The inspectors reviewed the

associated 10 CFR 50.59 safety evaluation screening, comparing it with system design

basis requirements in the USAR. The inspectors discussed the installations of the pipe

clamp with the system engineer and conducted a visual inspection of the pipe clamp

installation to assess if its installation adversely affected availability, reliability, or

functional capability of the instrument air supply to the Unit 2 containment.

b.

Findings

No findings of significance were identified.

1EP4

Emergency Action Level and Emergency Plan Changes (71114.04)

a.

Inspection Scope

The inspector reviewed Revision 24 of the Prairie Island Plants Emergency Plan to

determine whether changes identified reduced the effectiveness of the licensees

emergency planning, pending onsite inspection of the implementation of these changes.

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

October 23, 2002. The inspectors observed activities in the control room simulator. The

inspectors also attended the post-drill facility critique for the control room simulator

immediately following the drill and reviewed the final drill critique report. The inspectors

focused on weaknesses and deficiencies in the drill performance and ensured that the

27

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. As part of the inspection, the inspectors

reviewed the drill package listed at the end of this report.

b.

Findings

No findings of significance were identified.

2.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1

Plant Walkdowns

a.

Inspection Scope

The inspectors performed walkdowns of the radiologically controlled area (RCA) to verify

the adequacy of radiological boundaries and postings. Specifically, the inspectors

performed confirmatory radiation measurements in the Unit 1 containment and auxiliary

and waste buildings to verify that radiologically significant work areas (high radiation

areas (HRAs), radiation areas, and airborne radioactivity areas) were properly posted

and controlled in accordance with 10 CFR Part 20 and the licensees procedures.

Additionally, the inspectors reviewed practices during the ongoing refueling outage for

controlling access to contaminated areas and for posting and controlling airborne

contamination areas to determine if controls were acceptable. During this review, the

inspectors evaluated the adequacy of the dose assessments for any actual internal

exposures greater than 50 millirem committed effective dose equivalent.

b.

Findings

No findings of significance were identified.

.2

High Risk Significant, High Dose Rate HRA and Very High Radiation Area (VHRA)

Controls

a.

Inspection Scope

The inspectors reviewed the licensees controls for access to risk significant HRAs and

VHRAs to ensure that the licensees controls were consistent with the requirements in

10 CFR Part 20 and TSs. Specifically, the inspectors discussed the controls with the

radiation protection staff and reviewed applicable procedures. The inspectors also

performed walkdowns of the Unit 1 containment building to ensure adequate posting

and locking of entrances to high dose rate (>25 rem in one hour at 30 centimeters)

HRAs and VHRAs.

28

b.

Findings

No findings of significance were identified.

.3

Problem Identification and Resolution

a.

Inspection Scope

The inspectors reviewed condition reports completed during the previous six months

which identified issues in radiation worker and radiation protection technician

performance. The inspectors reviewed these documents to assess the licensees ability

to identify repetitive problems, contributing causes, the extent of conditions, and to

implement corrective actions which would achieve lasting results.

b.

Findings

No findings of significance were identified.

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

.1

Radiological Work/ALARA Planning

a.

Inspection Scope

The inspectors examined the stations procedures for radiological work/ALARA

planning and scheduling, and evaluated the dose projection methodologies and

practices implemented for the 2002 Unit 1 refueling outage to verify that sound

technical bases for outage dose estimates existed.

The inspectors reviewed the exposure results and ALARA reviews for selected refueling

outage activities to evaluate the accuracy of exposure estimates in the ALARA plans.

The inspectors compared the actual exposure results versus the initial exposure

estimates, the estimated and actual dose rates, as well as the estimated and actual

man-hours expended. The inspectors reviewed the exposure history for each activity

and evaluated management involvement in exposure tracking to assess outage dose

performance and dose management practices. The inspectors reviewed selected work-

in-progress ALARA reviews to determine if additional engineering/dose controls for

those activities were necessary, and if required corrective action documents had been

generated. Those work activities included:

Unit 1 SG manway removal;

Unit 1 SG nozzle dam installation;

SG diaphragm hot particle retrieval;

selected inservice inspection (ISI) work;

removal of insulation; and

assembling and disassembling of scaffolding.

29

b.

Findings

No findings of significance were identified.

.2

Verification of Exposure Estimate Goals and Exposure Tracking System

g.

Inspection Scope

The inspectors reviewed the methodology and assumptions used by the licensee for

developing refueling outage exposure estimates and exposure goals. Actual job

exposure data was compared with estimates to verify that the licensee could project

and, thus, control radiological exposure. The inspectors also reviewed the licensees

exposure tracking system to verify that the level of exposure tracking detail, exposure

report timeliness, and exposure report distribution were sufficient to support control of

collective exposures. The inspectors evaluated how the licensee had identified

problems with its exposure estimates for some jobs, the processes being utilized to

revise dose estimates, and methods to improve its dose forecasting procedures to verify

that the licensee could adequately track dose.

b.

Findings

No findings of significance were identified.

.3

Job Site Inspections and ALARA Controls

a.

Inspection Scope

The inspectors observed work activities in the RCA that were performed in radiation

areas or HRAs to evaluate the use of ALARA controls. Specifically, the inspectors

assessed the implementation of radiation work permits, engineering and ALARA

controls, and radiological surveys, and observed pre-job radiological briefings (as

available) and radiation protection technician performance for the following Unit 1

refueling work activities:

Unit 1 SG manway removal;

Unit 1 SG nozzle dam installation;

SG diaphragm hot particle retrieval; and

selected inservice inspection work.

The inspectors also observed radiation worker performance to verify that the training

and skill levels demonstrated by the workers was sufficient with respect to the

radiological hazards present and the work involved. The inspectors evaluated workers

use of low dose waiting areas and the level of on-the-job supervision to ensure that

ALARA requirements were met.

b.

Findings

No findings of significance were identified.

30

.4

Problem Identification and Resolution

a.

Inspection Scope

The inspectors reviewed self-assessments, audits, and condition reports completed

during the previous four months which focused on ALARA planning and controls and the

radiological source term reduction program. The inspectors reviewed these documents

to assess the licensees ability to identify repetitive problems, contributing causes, the

extent of conditions, and to implement corrective actions which will achieve lasting

results.

b.

Findings

No findings of significance were identified.

3.

SAFEGUARDS

Cornerstone: Physical Protection

3PP3

Response to Contingency Events (71130.03)

a.

Inspection Scope

The Office of Homeland Security developed a Homeland Security Advisory System

(HSAS) to disseminate information regarding the risk of terrorist attacks. The HSAS

implements five color-coded threat conditions with a description of corresponding

actions at each level. NRC Regulatory Information Summary (RIS) 2002-12a, dated

August 19, 2002, NRC Threat Advisory and Protective Measures System, discusses

the HSAS and provides additional information on protective measures to licensees.

On September 10, the NRC issued a Safeguards Advisory to reactor licensees to

implement the protective measures described in RIS 2002-12a in response to the

Federal government declaration of threat level Orange. Subsequently, on

September 24, the Office of Homeland Security downgraded the national security threat

condition to Yellow and a corresponding reduction in the risk of a terrorist threat.

The inspectors interviewed licensee personnel and security staff, observed the conduct

of security operations, and assessed licensee implementation of the threat level

Orange protective measures. Inspection results were communicated to Region III and

Headquarters security staff for further evaluation.

b.

Findings

No findings of significance were identified.

31

4.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

Cornerstones: Mitigating Systems, Barrier Integrity, and Occupational

Radiation Safety

a.

Inspection Scope

The inspectors reviewed the performance indicator data submitted by the licensee for

completeness and accuracy, and to verify that the licensee had reported data in

accordance with the guidance provided by the Nuclear Energy Institute (NEI). The

inspectors reviewed documents listed at the end of this report for performance indicator

data for mitigating systems and barrier integrity cornerstones. The inspectors reviewed

the following performance indicators from the 3rd quarter 2001 through the 2nd quarter

2002:

Reactor Coolant System Leak Rate on October 11, 2002; and

Safety System Unavailability - Emergency Alternating Current (AC) Power

System on October 24, 2002.

Under the occupational radiation safety cornerstone, the inspectors verified the

licensees assessment of its performance indicator for occupational radiation safety.

One reportable element was identified by the licensee for the 2nd quarter of 2002. The

inspectors selectively reviewed the licensees data elements to verify that there were no

additional occurrences during the 4th quarter of 2001 and the first three quarters

of 2002.

b.

Findings

No findings of significance were identified.

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 system at an appropriate threshold,

that corrective actions were performed in a timely manner, and that adverse trends were

identified and addressed. Minor issues entered into the licensees corrective action

system as a result of inspectors observations are generally denoted in the report.

b.

Findings

No findings of significance were identified.

32

.2

Licensee Resolution of Issues Associated With Unit 1 Emergency Diesel Generators

a.

Inspection Scope

On October 1, 2002, the inspectors reviewed the actions taken by the licensee to

resolve URI 50/282-01-10-01. This issue dated back to May 16, 2001, and was

concerned with the resolution of inadequacies identified in Prairie Island calculations

ENG-PI-002, Probabilistic Risk Assessment of D1 EDG [emergency diesel generator]

Room Door Vulnerability to Tornado Missile, and ENG-PI-005, Tornado & Seismic

Evaluation of D1/D2 Components. The inspectors assessed whether the timeliness of

the licensees corrective actions to resolve this issue were commensurate with the

safety significance of the issue. The inspectors reviewed USAR and IPEEE sections

discussing tornado hardness and seismic qualification for the Unit 1 EDGs and their

associated structures, discussed probabilistic risk assessment results assuming that

both Unit 1 EDGs and all connections to offsite power are lost during a tornado event

with plant risk engineers, and discussed probabilistic risk assessment results with the

Region III Senior Reactor Analyst. The inspectors also reviewed the licensees timeline

for correction of the inadequacies in the above referenced calculations.

b.

Findings

No findings of significance were identified. Based on licensee corrective actions

currently in progress, the inspectors consider URI 50/282-01-10-01 closed.

4OA3 Event Followup (71153)

a.

Inspection Scope

The purpose of this inspection was to assess Prairie Islands emergency preparedness

response during a seismic event which occurred on November 3, 2002. The inspectors

reviewed the operators response to this unplanned event and compared their actions to

the actions specified in annunciator response procedures, abnormal operating

procedures, and the emergency plan and implementing procedures.

b.

Findings

Introduction

The inspectors identified that the licensee failed to classify and declare an Unusual

Event in accordance with emergency plan implementing procedures following receipt of

the Seismic Event annunciator with confirmation of the occurrence of an earthquake in

Alaska. The finding was considered to be of very low safety significance (Green) and

was determined to be a Non-Cited Violation.

Discussion

On November 3, 2002, a seismic alarm was received in the control room. The licensee

entered Abnormal Operating Procedure AB-3 and confirmed the occurrence of the

Alaskan earthquake by contacting the National Earthquake Information Center in

33

Boulder, Colorado. The control room seismic monitor energized, the Seismic Event

annunciator was received, and magnetic tape operation initiated. However, a failure of

the seismic monitor chart paper recorder to produce a visible indication on its chart

paper prevented the timely evaluation of the peak acceleration experienced during the

event. Additionally, the failure of operators to follow the emergency plan implementing

procedure for event classification prevented classification and declaration of the event.

Abnormal Operating Procedure AB-3, Attachment B, directed operators to remove the

paper chart from the seismic recorder; determine the peak acceleration of the seismic

event; compare the peak acceleration recorded to the acceleration definitions for the

Seismic Event, Operational Basis Earthquake, and Design Basis Earthquake; and

declare the appropriate emergency action level if necessary. When operators removed

the chart paper from the seismic recorder they were unable to read markings on the

paper and were unable to promptly determine the peak acceleration of the event. This

problem was entered into the corrective action program with AR CAP 026100.

The inability to promptly determine peak acceleration resulted in the inability to complete

AB-3, Attachment B. Referring to Step 5.0 of Attachment A of AB-3, operators directed

instrument maintenance and engineering personnel to evaluate the magnetic tape

recorders. Five hours after the initial indication of the earthquake was received,

instrument maintenance and engineering personnel determined the peak acceleration

reached during the seismic event was 1 percent of the acceleration due to gravity (g).

Operators determined that no emergency action levels were reached and exited AB-3.

The licensee recognized the excessive amount of time needed to determine the peak

acceleration of the seismic event and entered the condition into their corrective action

program with AR CAP 026101.

The licensee declared the seismic monitor inoperable and commenced troubleshooting

activities. The inspectors discussed with instrument maintenance personnel the failure

of the seismic monitor chart recorder to produce a readable indication of the seismic

activity. The inspectors were told that the chart recorder was the light beam

galvanometer type and required ultra-violet light sensitive paper to be exposed. The

inspectors inquired as to the age of the paper installed in the seismic monitor with

respect to its shelf life and was told that there was no shelf life on the paper. After

additional prompting by the inspectors and consultation with the manufacturer of the

paper, the licensee confirmed that the paper did indeed have a shelf life and the paper

installed in the seismic monitor at the time of the event was beyond its 5-year shelf life.

The supply chain manager told the inspectors that the paper had not been included in

the sites shelf life program. The inspectors identified that the licensee had failed to

properly maintain the seismic monitoring equipment. The licensee ordered, received,

and installed new ultra-violet sensitive paper into the seismic monitor. The seismic

monitor was satisfactorily tested following the installation of the new paper. The

corrective actions for this condition were documented in condition evaluation

(CE) 001350.

The inspectors reviewed the annunciator response procedures 47023-603 and C81000

for the Seismic Event alarm. The inspectors noted that the annunciator response

procedure C81000 indicated that the instrument setpoint for the Seismic Event alarm

was 3 percent of the acceleration due to gravity (g) in the vertical or horizontal

34

directions. Analysis of the seismic monitor magnetic tapes showed only a 1 percent g

peak acceleration indicating the alarm setpoint was set low in the conservative direction.

Instrument maintenance personnel told the inspectors that the seismic monitor had been

recently calibrated.

The inspectors reviewed operator actions with respect to the emergency plan

implementing procedure F3-2, Classification of Emergencies. The inspectors reviewed

the operator control room log entries for November 3, 2002, from 4:31 p.m. through

9:31 p.m., noting that the operators only entered the annunciator response procedures

C81000 and 47023-603, and abnormal operating procedure AB-3. No log entries were

noted that indicated the operators entered F3-2, Attachment 1, Condition 19a,

Earthquake. Procedure AB-3, Attachment A, would have directed the operators to

enter F3-2, Attachment 1, Condition 19a, if the seismic monitor paper chart would have

functioned properly allowing completion of AB-3, Attachment B, and a peak

acceleration of greater than or equal to 3 percent g was recorded during the seismic

event. As mentioned previously, operators were unable to complete AB-3, Attachment

B, and AB-3, Attachment A, Step 2.0. Since Step 2.0 could not be completed, operators

skipped Steps 2.0, 3.0, and 4.0. Step 3.0 of AB-3 was the step that referred operators

to emergency plan implementing procedure F3-2 for event classification.

Operators should have entered F3-2, Attachment 1, Condition 19a, immediately after

the receipt of the Seismic Event alarm. F3-2 requires two conditions to be met

necessitating the declaration of an Unusual Event classification. The first condition was

the receipt of the Seismic Event annunciator on the seismic monitor. This condition was

met on receipt of the alarm at 4:31 p.m. The second condition to confirm the seismic

event by one or more offsite sources was met when the licensee confirmed the event

with the National Earthquake Information Center in Boulder, Colorado at 4:40 p.m. The

inspectors identified that the licensee failed to follow its emergency plan implementing

procedure for this event. The licensee entered the issue into their corrective action

program as Other (OTH) 023756. This document specified an evaluation of the

licensees actions for the November 3, 2002, event.

The licensee told the inspectors that the operators did not enter F3-2 and classify the

event because they did not believe the event to be of sufficient magnitude to warrant an

unusual event declaration. Operators based their decision on the significant distance

between the plant site and the earthquakes epicenter, the absence of earth motion at

the plant site as sensed by on-shift plant personnel, and confirmation from the nearby

Monticello plant that the event was not detected on their seismic monitors. The

verification of seismic activity with the Monticello plant occurred approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />

after the Seismic Event annunciator was received.

The inspectors reviewed the licensees reasoning for not declaring the event and

determined that the actions taken by the licensee did not meet the timeliness

requirements for event classification and declaration. The regulations do not provide an

explicit time limit for classification but do imply that the classification should be made

without delay. An event classification time limit of 15 minutes has been accepted by

both the NRC and industry. In August of 1995, the NRC issued Emergency

Preparedness Position (EPPOS) Number 2, discussing NRC expectations for the

timeliness of the classification of emergency conditions. This expectation has been

35

further communicated in industry guidance. Nuclear Energy Institute 99-02, Section 2.4,

provided a definition of timely that stated that classifications are made consistent with

the goal of 15 minutes once plant parameters reach an Emergency Action Level. In this

case, plant parameters (i.e., the Seismic Event annunciator) reached a Emergency

Action Level at 4:31 p.m. The information possessed by the licensee at 4:46 p.m.

(15 minutes after the receipt of the Seismic Event annunciator) met all criteria for the

classification and declaration of an Unusual Event and, therefore, should have been

declared at that time.

The inspectors also identified that the procedural guidance contained in AB-3 and

F3-2 conflicted. For example, following AB-3, operators must receive a seismic monitor

alarm, verify the magnitude of the peak acceleration, and confirm the event with at least

one off-site source; whereas, following F3-2, operators need only to receive a seismic

monitor alarm and confirm the event with at least one off-site source before declaring an

Unusual Event. The issue of conflicting procedural guidance was entered into the

corrective action program with AR CAPs 027232 and 027233.

Analysis

The inspectors determined that this event did not have any actual safety consequences

or potential for impacting NRCs regulatory function. However, the licensees failure to

make an emergency classification was considered more than minor since it affected an

Emergency Preparedness Cornerstone objective. The affected objective is the

emergency response organizations performance in an event to ensure that Prairie

Island is capable of implementing adequate measures to protect public health and

safety during an emergency.

Consequently, this issue represents a finding that is more than minor and which was

evaluated using the Emergency Preparedness Significance Determination Process

contained in Appendix B to Manual Chapter 0609. Since the finding involved a failure

to meet a regulatory requirement, but did not represent a failure to meet the planning

standards of 10 CFR 50.47(b) or those of Appendix E to 10 CFR Part 50, the finding

was determined to be of very low safety significance (Green).

Enforcement

In part, 10 CFR 50.54(q), 50.47(b)(4), Sections IV.B and IV.D.3 of Appendix E of

10 CFR Part 50 require that an emergency classification declaration be made promptly

after an emergency action level is met. Contrary to the above, the licensee failed to

classify and declare an Unusual Event on November 3, 2002, when all required

conditions necessitating classification and declaration of an Unusual Event were met.

Since the licensee entered the conditions identified by the inspectors into their corrective

action program with OTH 023756, this violation is being treated as an NCV in

accordance with VI.A.1 of the NRCs Enforcement Policy (NCV 50-282/306/02-09-05).

36

4OA5 Other Activities

.1

Reactor Pressure Vessel Head and Vessel Head Penetration Nozzles (Temporary

Instruction (TI) 2515/150)

a.

Inspection Scope

On August 9, 2002, the NRC issued Bulletin 2002-02, Reactor Pressure Vessel Head

and Vessel Head Penetration Nozzle Inspection Programs. The purpose of this

Bulleting was to: (1) Advise pressurized water reactor (PWR) licensees that visual

examinations, as a primary inspection method for reactor pressure vessel head and

vessel head penetration (VHP) nozzles, may need to be supplemented with additional

measures; (2) Advise PWR licensees that inspection methods and frequencies to

demonstrate compliance with applicable regulations should be demonstrated as

effective and reliable; (3) Request information from all PWR addressees concerning the

reactor pressure vessel (RPV) head and VHP nozzle inspection programs; and

(4) Require all PWR addressees to provide written responses to this bulletin related to

their inspection program plans.

The objective of TI 2515/150, Reactor Pressure Vessel Head and Vessel Head

Penetration Nozzles, was to implement an on-site NRC review of the licensees

activities in response to NRC Bulletin 2002-02. Specifically, licensee procedures,

equipment, and personnel used for VHP examinations were evaluated by the inspectors

to confirm that the licensee met commitments associated with Bulletin 2002-02.

From November 18 through November 26, 2002, the inspectors performed a review of

the licensees activities in response to commitments made to NRC Bulletin 2002-02. In

response to Bulletin 2002-02, the licensee referred to previous commitments made in

response to Bulletin 2001-01, Circumferential Cracking of Reactor Pressure Vessel

Head Penetration Nozzles. In response to Bulletin 2001-01, the licensee committed to

perform an effective visual examination of the vessel head and penetration nozzles.

To assess the licensees efforts in conducting an effective visual examination of the

RPV head and VHP nozzles, the inspectors:

performed an independent direct visual examination of the nozzle-to-head

interface for portions of 20 VHPs;

observed the licensees visual examination of the VHPs;

interviewed nondestructive examination personnel;

reviewed the head inspection work order; and

reviewed the head inspection examination results.

Additionally, the inspectors reviewed the licensees VHP nozzle susceptibility ranking

calculation to:

verify that appropriate plant-specific information was used as input;

confirm the basis for the head temperature used by licensee; and

determine if previous VHP cracks had been identified and if so, used in the

susceptibility ranking calculation.

37

b.

Observations

Summary

The licensee did not identify any leaking VHP nozzles. The licensee identified three

nozzles with white deposits at the VHP nozzle-to-head interface which were not

considered indications of VHP leakage.

Evaluation of Inspection Requirements

In accordance with requirements of TI 2515/150, the inspectors evaluated and

answered the following questions:

1.

Was the examination:

a.

Performed by qualified and knowledgeable personnel? (Briefly describe the

personnel training/qualification process used by the licensee for this activity.)

Yes. The licensee conducted a direct visual examination of the head with a

knowledgeable staff member certified to Level II as a VT-2 examiner in

accordance with programs meeting the American Society for Nondestructive

Testing Recommended Practice SNT-TC-1A.

b.

Performed in accordance with approved procedures?

No. The licensee conducted direct visual examinations in accordance with

requirements of a reviewed and approved work order (WO 0200959, Inspect RV

[reactor vessel] Head Penetrations for Leakage). The use of a work order was

consistent with licensee commitments to Bulletin 2001-01. The licensee

acceptance criteria established in this work order included the lack of any

relevant indications of the type described in Electric Power Research Institute

TR-1006899, Visual Examination for Leakage of PWR Reactor Head

Penetrations on Top of RPV Head. The inspector concluded that this criterion

was consistent with the licensees commitment to Bulletin 2001-01, which stated

no visual indications of cracks or leaks. The licensees visual inspection scope

was not explicitly defined in the work order. The work order required the

licensee inspection personnel to document the examination coverage on an

attached worksheet. The inspectors confirmed that the licensee had not

committed to complete a 360 degree visual examination of each penetration

nozzle.

The inspectors identified that the work order did not implement visual

examination quality standards such as those described for visual VT-1, VT-2,

and VT-3 examinations in Section XI of the ASME Code. Based on this

observation, the licensee changed the work order to implemented a visual quality

check for this examination that included resolution of a 1/32 black line on an

18-percent neutral gray card (visual acuity card). The work order did not specify

at what distance the licensees inspector was required to resolve the line on the

visual acuity card. The inspectors noted that the licensee inspector was able to

38

resolve this line at distances in excess of five feet. Specifically, the licensee

inspector mounted the visual acuity card on a pole and placed it on the vessel

head with the portable lighting used during the head examination and was able

to resolve the line.

c.

Able to identify, disposition, and resolve deficiencies?

Yes. Based on direct observation of the head and penetration nozzles, the

inspectors concluded that the lighting and access for the visual examination was

adequate to detect boric acid deposits. The licensees examinations identified

three locations (D-12, D-10 and I-11) with white deposits at the VHP nozzle-to-

head interface. The licensee characterized these deposits as white flakes and

fluffy-yellow/white deposits. The size of two deposit particles was recorded as

1/4- by 1/16-inch and 1/16- by 1/16-inch. The licensee subsequently removed

these deposits with a vacuum. Because of the small size and the loose/readily

removable nature of these deposits, the licensee did not consider the deposits to

be indicative of leakage. The licensee documented the vessel head inspection

results in the corrective action system (CAP 026636).

d.

Capable of identifying the primary water stress corrosion cracking phenomenon

described in the bulletin?

Yes. The inspectors determined through direct observations, interviews with

inspection personnel, and reviews of the work order and examination reports that

the licensees efforts were capable of detecting and characterizing leakage from

cracking in VHP nozzles. The inspectors determined that the inspection

personnel had access to each of the head penetrations (40 total) and head vent

nozzle.

2.

What was the condition of the reactor head (debris, insulation, dirt, boron from

other sources, physical layout, viewing obstructions)?

The reactor head was covered with reflective metal insulation panels installed on

a support structure over the top of the reactor head. The insulation was

nominally 3 inches thick and was composed of layers of thin stainless steel

sheets. Clearance between the head and insulation was approximately 1 inch at

the center and 18 inches at the outside nozzles. The insulation structure

included four rectangular view ports (5.5 inches by 16 inches), which allowed the

licensee access to the bare metal head. The inspector confirmed that most

nozzles were readily visible through these viewing ports and that the head was

relatively free of debris which would hinder an effective visual examination. With

the aid of a mirror, the licensees inspection staff were able to obtain a 360-

degree visual examination of each VHP nozzle-to-head interface through these

viewing ports. However, the inspectors could not confirm that the licensee had

sufficient access to penetration nozzle L-10 to permit a 360-degree inspection.

This nozzle was in close proximity to the vertical reflective metal head insulation

panel on the downhill side. The licensees inspector considered that his

inspection was adequate to have detected leakage with the penetration in this

configuration.

39

The licensees examinations identified three locations (D-12, D-10 and I-11) with

white deposits at the VHP nozzle-to-head interface (CAP 026636). The

inspectors questioned if these deposits would obstruct or mask leakage deposits

at the VHP nozzle-to-head interface. The licensees inspector did not consider

that these deposits would mask any leakage deposits because leakage deposits

would be tightly adherent and would remain at the interface following removal of

the loose deposits with a vacuum. The inspectors observed VHP nozzle D-12

(with white deposits) prior to, and after vacuum cleaning. The inspectors did not

see any deposits remaining at the VHP nozzle-to-head interface following

cleaning.

3.

Could small boron deposits, as described in Bulletin 2001-01, be identified and

characterized?

Yes. The inspectors determined through direct observations, interviews with

inspection personnel, and reviews of the work order and examination reports that

small boron deposits, as described in the Bulletin 2001-01, could be identified

and characterized.

4.

What material deficiencies (associated with the concerns identified in the

bulletin) were identified that require repair?

None. The licensee did not identify any materiel deficiencies associated with the

40 VHP nozzles or head vent nozzle that were considered indicative of leakage.

Thus, the licensee did not identify material deficiencies associated with concerns

identified in the bulletin which required repair.

5.

What, if any, significant items that could impede effective examinations?

The inspectors did not identify any significant items which would impede an

effective visual examination.

Nozzle Susceptibility Ranking Calculation

The licensee performed Calculation ENG-ME-535 to determine the effective degradation

years (EDY) for the VHP nozzles in Units 1 and 2. In Bulletin 2002-02, the EDY is used

as a basis to establish appropriate inspection programs for VHP nozzles based on

increasing susceptibility to nozzle cracking with increasing EDY. For Unit 1, the licensee

calculated an EDY of 10.58 years through September of 2002. Based on this EDY and

the guidance on acceptable inspection programs discussed in Bulletin 2002-02, the

licensee chose to perform a visual examination of the head during this refueling outage.

The inspectors confirmed that the formula used by the licensee in Calculation

ENG-ME-535 was identical to the formula discussed in Bulletin 2002 to calculate EDY.

As an input to Calculation ENG-ME-535, the licensee used a normal operating reactor

vessel head temperature of 580.2 degrees Fahrenheit (F). This temperature was

taken from Table 5-2 in a proprietary Westinghouse document WCAP 14918,

Probabilistic Evaluation of Reactor Vessel Closure Head Penetration Integrity for Prairie

Island Units 1 and 2. The licensee did not have any records onsite to confirm the

40

inputs used by the vendor in determining the vessel head temperature. The licensee

subsequently entered this issue into the corrective action program CAP 026603 and

initiated Engineering Work Request (EWR) 0036068, Heat Temperature Input to Calc

ENG-ME-535," to obtain appropriate documentation.

The inspectors questions about the input temperature used in the calculation prompted

the licensee to contact Westinghouse, who identified that the 580.2 F head

temperature was based, in part, on Calculation Note EMT-97-78. This calculation used

a computer program (THRIVE) to determine upper bulk mean fluid temperature of the

vessel head area for use in loss-of-coolant accident analysis blowdown load

calculations. For that application, the Westinghouse had used a cold leg temperature of

527 F vice the actual in-plant measured value of 530 F. Westinghouse reported that

the output of this calculation performed in 1992 for the upper bulk mean fluid

temperature was 577.2 F. Westinghouse then added 3 F to adjust for the plant

specific cold leg temperature difference to obtain the 580.2 F value used in WCAP

14918 and as the input value for head temperature in Calculation ENG-ME-535.

In addition to the EDY, an acceptable VHP inspection program was based on

whether the licensee had identified cracks or leakage during previous inspections of

VHP nozzles. Based on discussions with licensee inspection personnel, the inspectors

confirmed that no indications of VHP nozzle leakage had been identified during previous

Unit 1 head inspections. However, the licensee inspector reported that a complete

360 degree visual examination of each VHP nozzle-to head interface had not been

performed during the previous Unit 1 visual examination.

c.

Findings

No findings of significance were identified.

.2

Completion of TI 2515/149, Mitigating Systems Performance Index (MSPI) Pilot

Verification

From November 25 through December 20, 2002, the inspectors completed the

requirements of the TI to verify that the licensee had correctly implemented the MSPI

pilot guidance for reporting unavailability and unreliability of the monitored safety

systems. Documents reviewed during this inspection are listed at the end of this report.

The detailed results of this inspection are documented in a memorandum included as an

attachment to this report.

.3

Completion of Appendix A to TI 2515/148, Inspection of Nuclear Reactor Safeguards

Interim Compensatory Measures, Revision 1

The inspectors completed the pre-inspection audit for interim compensatory measures

at nuclear power plants, dated September 13, 2002.

4OA6 Meeting(s)

.1

Interim Exit Meetings

41

Results of Licensed Operator Requalification Testing for Calender Year 2002 and

Applicability of NRC IMC 0609, Appendix I, Operator Requalification Human

Performance Significance Determination Process, with Mr. T. Bacon on November 14,

2002.

Access Control to Radiologically Controlled Areas and ALARA inspection with Mr. M.

Nazar on November 22.

TI 2515/150 and inservice inspection (IP 7111108) with Mr. M. Nazar on November 26.

.2

Exit Meeting

The resident inspectors presented the inspection results to Mr. M. Nazar and other

members of licensee management on January 13, 2003. The inspectors asked the

licensee whether any materials examined during the inspection should be considered

proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

The following violations of very low significance were identified by the licensee and are

violations of NRC requirements which meets the criteria of Section VI of the NRC

Enforcement Manual, NUREG-1600, for being dispositioned as NCVs.

Cornerstone: Mitigating Systems

.1

Missed Technical Specification Surveillance Test

Technical Specification Condition 3.7.8.A, Cooling Water System, states that with

no safeguards cooling water pumps operable in one train, then on Unit 1 enter the

applicable conditions of the required actions of the Limiting Condition for

Operation 3.8.1, AC Sources. Technical Specification Condition 3.8.1.A states that

surveillance requirement (SR) 3.8.1.1 shall be performed within one hour and every

eight hours thereafter. On October 26, 2002, the licensee identified that they had failed

to meet these requirements on October 24, when the 22 safety-related DDCL pump was

declared inoperable for planned maintenance. Upon discovery of the missed

surveillance activity, the licensee performed and successfully completed SP 1118,

Verifying Paths from the Grid to Unit 1 Buses, and conducted an investigation that did

not identify any degradations in the offsite alternating current power sources. The

finding was determined to be of very low safety significance since it did not result in any

actual loss of safety function. This issue was entered into the licensees corrective

action program with AR CAP 025986.

.2

Inoperable RHR Suction Relief Valve

The Design Basis Document (DBD) System 15, Residual Heat Removal System,

requires that the RHR system be protected from over-pressure in accordance with the

ASME Boiler and Pressure Vessel Code, 1968 Winter. Relief Valve RH-8-1 was

intended to perform this function on Unit 1. However, on November 18, 2002, the

42

licensee identified that RH-8-1 had been gagged and was not able to perform its

pressure relief function. The valvess work history indicated that it had been gagged

since its installation in April 1999. The installation of the gagging device on RH-8-1

constituted a change to the design of the RHR system as described in its design basis

and was inconsistent with the design control requirements of 10 CFR 50, Appendix B,

Criterion III. The finding was determined to be of very low safety significance since at

no time did RHR system pressure approach the piping design pressure nor did it result

in non-compliance with low temperature over-pressure protection TSs, increase the

likelihood that a loss of decay heat removal would occur, increase the likelihood that a

loss of RCS inventory would occur, increase the likelihood that a loss of offsite power

would occur, degrade the capability to terminate a leak path or add RCS inventory,

degrade the ability to recover decay heat removal once lost, degrade the ability to

establish an alternate core cooling path, or degrade the ability of containment to remain

intact following a severe accident. This issue was entered into the corrective action

program with AR CAP 026440.

43

KEY POINTS OF CONTACT

Licensee

T. Amundson, Manager Business Support

P. Huffman, Manager of System Engineering

J. Jensen, Production Planning Manager

A. Johnson, Radiation Protection Manager

J. Kivi, Licensing Engineer

R. Lingle, Operations Manager

M. McKeown, Manager of Design Engineering

M. Ladd, General Superintendent Plant Maintenance

M. Nazar, Site Vice President

S. Northard, Director of Engineering

J. Waddell, Superintendent Security

M. Werner, Plant Manager

P. Wildenborg, Lead Technical Health Physicist

R. Womack, Manager of Engineering Programs

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-282/306/02-09-01

NCV

Failure to Follow Internal Flood Control Procedure

(Section 1R06)

50-282/306/02-09-02

URI

Missed UT Examinations for SG 12 and SG 21 W-A Welds

(Section 1R08.b.(1))

50-282/306/02-09-03

NCV

Lack of ASME Code Requirement in 3 UT procedures

(Section 1R08.b.(2))

50-282/306/02-09-04

NCV

Missed Technical Review for UT Procedure

(Section 1R08.b.(3))

50-282/306/02-09-05

NCV

Missed Emergency Classification and Declaration

(Section 4OA3)

Closed

50-282/306/02-09-01

NCV

Failure to Follow Internal Flood Control Procedure

(Section 1R06)

50-282/306/02-09-03

NCV

Lack of ASME Code Requirement in 3 UT Procedures

(Section 1R08.b.(2))

50-282/306/02-09-04

NCV

Missed Technical Review for UT Procedure

(Section 1R08.b.(3))

44

50-282/306/02-09-05

NCV

Missed Emergency Classification and Declaration

(Section 4OA3)

50-282/01-10-01

URI

Ability of D1 and D2 Exhaust Lines to Survive a Design

Basis Tornado or Seismic Event (Section 4OA2.2)

50-282/306/02-08-02

URI

Maintenance Rule Functional Failure Evaluation of Bypass

Gate Failures (Section 1R12.3)

Discussed

None.

45

LIST OF DOCUMENTS REVIEWED

1R01

Adverse Weather

Cold Weather Preparations

Test Procedure TP 1637; Winter Plant Operation; Revision 29

IPEEE, Appendix C; Assessment of Other External Events for Prairie Island

ENG-ME-178; Screenhouse Ventilation Evaluation Operating Procedure; Revision 0

C37.8; Screenhouse Safeguard Equipment Cooling Operating Procedure; Revision 7

C37.5; Screenhouse Normal Ventilation Operating Procedure; Revision 5

C25; Circulating Water System Operating Procedure; Revision 24

AR CAP 026024; Glycol System ZY Has Inadequate Antifreeze Protection;

October 29, 2002

AR CAP 025798; Auxiliary Building Make Up Air Handlers Tripping Off; October 16,

2002

AR CAP 025774; Possible Rework on 121 Administration Building Hot Water Circulating

Pump; October 15, 2002

WO 0100562; Enclose the Auxiliary Building Cooling Water Dump-to-Grade to Prevent

Ice Buildup

1R04

Equipment Alignment

12 DDCL Pump Partial Walkdown

TS 3.7.8; Cooling Water System; Amendment 158

USAR 10.4.1; Cooling Water System; Revision 24

C35; Cooling Water Operating Procedure; Revision 49

C1.1.35-1; Cooling Water System Unit One Integrated Checklist; Revision 8

C1.1.35-3; Cooling Water System Integrated Checklist; Revision 21

Cooling Water System Health Update; April 22, 2002

AR CAP 025178; 12 Diesel Driven Cooling Water Pump; September 12, 2002

AR CAP 025186; 12 DDCL Pump Fell in the Performance Curve Alert Range During the

9/12/02 Run; September 12, 2002

46

AR CAP 025837; 121 MDCLP [Motor-Driven Cooling Water Pump] per SP 1106C

Showed a Step Drop in Performance; October 17, 2002

21 Component Cooling Heat Exchanger Partial Walkdown

Integrated Checklist C1.1.14-2; Unit 2 Component Cooling System; Revision 23

WO 0209384; Oil Leak on 2CC-1-7; September 26, 2002

AR CAP 027285; Evaluate AWIs and Maintenance Standards Implementing Procedures

(MSIPs) to Ensure Consistent Requirements for Blocking Wheels; December 18, 2002

MSIP 1003; Use and Storage of Service Equipment; Revision 4W

Unit 1 Safety Injection Complete Walkdown

Plant Procedure B18A; Safety Injection System; Revision 4

TS 3.5.2 and Bases; Emergency Core Cooling Systems - Operating; Amendment 158

USAR 6.2; Safety Injection System; Revision 22

Operating Procedure C18; Engineered Safeguards System Unit 1; Revision 11

Integrated Checklist C1.1.18-1; SI [Safety Injection], CS [Containment Spray], CA

[Caustic Addition] & HC [Hydrogen Control] System Checklist Unit 1; Revision 41

Operating Procedure 1C1.2; Unit 1 Startup Procedure; Revision 29

5AWI 3.12.6; Fluid Leak Management Program; Revision 0

AR CAP 023138; Okonite/Scotch EQ Tape Splices Installed in Non-Tested

Configurations; April 17, 2002

WO 9407097; Wire Code Changes at MV-32162 11 SI Pump Suction;

November 16, 1994

WO 0200533; Body to Bonnet Leak on SI-10-1; January 17, 2002

WO 0203653; Boric Acid Residue on Cap for SI-20-37; April 17, 2002

WO 0203719; Install 11 SI Mini Recirc Line Flowmeter; April 25, 2002

WO 0203720; Install 12 Minimum Recirc Line Flowmeter; April 25, 2002

WOs 0206251, 0206252, 0206254, 0206255, and 0206258; Replace Okonite Splice

with EQ Qualified Splice; July 17, 2002

WO 0210039; Broken Drain Stem on Manifold Valve; October 14, 2002

1R05

Fire Protection

47

Area Walkdowns

Plant Safety Procedure F5, Appendix A; Fire Strategies for Fire Areas 86; Revision 7

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

Plant Safety Procedure F5, Appendix F; Fire Hazard Analysis for Fire Areas 86;

Revision 16

AR CAP 026044; Fire Door Requirements and Operability; October 30, 2002

1R06

Flood Protection Measures (Internal)

IPE NSPLMI-94001 Section 3.3.8; Internal Flooding Evaluation; Revision 0

DBD-TOP-05; Design Bases Document for Hazards; Revision 2

H36; Plant Flooding Procedure; Revision 0

5AWI 8.9.0; Internal Flooding Drainage Control; Revision 0

AR CAP 025766; Need Operability Evaluation for Non-Safeguards Cooling Water

Pumps; October 14, 2002

AR CAP 026010; Loose Oil Absorbent Materials Were Found in 22 Diesel Driven

Cooling Water Pump Room; October 28, 2002

GEN 200200252; Oil Absorbent Materials Were Found in the Vital Area of Plant

Screenhouse; January 9, 2002

AR CAP 026158; Temporary Power Cables Routed Through Critical Drainage Path

Without Evaluation; November 6, 2002

AR CAP 026291; Foreign Material in 121 Cooling Water Pump Room While Lined Up as

Safeguards Pump; November 13, 2002

CE 001406; Evaluate Past Operability Impact on the Cooling Water Pumps;

November 13, 2002

Apparent Cause Evaluation (ACE) 008603; Conduct ACE Regarding CAP 026291;

November 14, 2002

ENG-ME-458; Calculation of the Highest Acceptable Leak Rate in the Cooling Water

Pump Rooms; Revision 1

1R07

Heat Sink Performance

TS 3.7.7; Component Cooling Water System; Amendment 158

48

USAR, Section 10.4.2; Component Cooling Water System; Revision 24

DBD System 14; Component Cooling Water System; Revision 3

WO 0114307; Perform SP 1304 Unit 1 Component Cooling Water Heat Exchanger

Performance Test; November 16, 2002

SP 1304; Unit 1 Component Cooling Water Heat Exchanger Performance Test;

Revision 5

AR CAP 026355; Potential Silting/Sediment Concerns with Plant Equipment and

Systems; November 16, 2002

CE 001474; Evaluate and If Necessary Initiate Corrective Action Regarding

CAP 026355; November 19, 2002

EWR 003548; Determine If Additional Flushing Procedures for Auxiliary Building

Coolers is Desirable; December 18, 2002

EWR 003549; Evaluate Quarterly Flushing of Steam Generator Blowdown Heat

Exchangers; December 18, 2002

EWR 003550; Determine If It Is Desirable to Add Small Bore Vents and Drains to

Current Program; December 18, 2002

1R08

Inservice Inspection Activities

Audit

Observation Report 2002-004-6-010; October 30, 2002

Corrective Action Reports

AR CAP 026473; Mixed Residual Indications Not Evaluated for Voltage Based Repair

Criteria; November 19, 2002

AR CAP 023120; Errors Found in ISI Relief Request Submitted to NRC; April 15, 2002

AR CAP 023017; Reference Error in Prairie Island Technical Specification; April 3, 2002

AR CAP 024378; Tube Pull at Sequoia May Affect ODSCC ARC Curves; July 30, 2002

AR CAP 023573; Incorporate Updated In-Situ Screening Guidelines into H25.2;

May 21, 2002

AR CAP 025203; ISI Code Percentages Not Used for First Period of the Third Interval

for Category B-B Welds; September 13, 2002

AR CAP 012058; Reduced Internal Diameter of Four Sleeves in 12 SG;

October 30, 1997

49

AR CAP 0001588; RCS Leakage VT-2 Visual Examination Not Performed in

Accordance with ASME XI Code; September 14, 2001

AR CAP 000809; Primary Coolant Leakage Through SG Cold Leg Primary Manway

Cover; March 26, 2002

Condition Report 200201449; Eddy Current Testing Had to be Repeated in SG 21;

February 13, 2002

Condition Report 200100475; SG 12 Hot Leg Manway Leak; January 21, 2001

Corrective Action Process Reports Issued As a Result of Inspection Activities

AR CAP 026513; Three Non-Destructive Examination Procedures Do Not State Modes

of Wave Propagation as Required by the ASME Code; November 20, 2002

AR CAP 026514; Procedure ISI-UT-5E Was Not Periodically Reviewed; November 20,

2002

AR CAP 026563; Weld WA on SG-11 Was Not Scheduled for Successive Examinations

as Required; November 21, 2002

AR CAP 026603; Assess Head Temperature Used in EDY Calculation ENG-ME-535;

November 22, 2002

Code Replacement/Repair Activities

WO 0004477; Perform Preventative LCSW Buildup on RV Head; February 10, 2001

WOs 0100722, 0100505, 0003101; Loop B Pressurizer Spray Valve (CV 31225)

Replacement

Drawing

A-6733; Reactor Coolant Lines 111 and 113; March 4, 1971

Nondestructive Examination Reports

Radiograph Test report for WO 07F4188; February 7, 8, 9, 12, and 13, 2001

99-0143; Pipe-to-Elbow Weld W-21 Resistance Thermal Detector Take Off on Loop A

Cold Leg; May 4, 1999

99-0352; SG-11 Tube Sheet-to-Head Weld WA; May 24, 1999

99-0353; SG-11 Tube Sheet-to-Head Weld WA; May 24, 1999

2001P020; Reactor Coolant (RC) Pipe-to-Flange W-4; February 2, 2001

2002V216; RC Support H2; November 20, 2002

2002U055; RC Safe End-to-45 Degree Elbow Weld W-2; November 22, 2002

50

2002U056; RC 45 Degree Elbow-to-Pipe Weld W-3; November 22, 2002

2002U057; RC Reducer-to-Safe End Weld W-13; November 22, 2002

Procedures

MMRN 1.1; Reference Manual Policy and Administration; Revision 0

ISI-MT-1; Dry Powder Magnetic Particle Examination; October 18, 2001

ISI-PT-1; Solvent Removable, Visible Dye Penetrant Examination; October 18, 2001

ISI-UT-1A; Ultrasonic Examination of Ferritic Piping Welds to Appendix VIII;

November 2, 2001

ISI-UT-3; Ultrasonic Examination of Ferritic Vessels; August 14, 2002

ISI-UT-3A ; Ultrasonic Examination of Reactor Vessel Welds; January 5, 2000

ISI-UT-3B; Ultrasonic Examination of Reactor Vessel Welds to Appendix VIII;

October 10, 2001

ISI-UT-5D; Ultrasonic Examination of Pressurizer Nozzle Inner Radii; August 14, 2002

ISI-UT-5E; Ultrasonic Examination of Steam Generator Primary and Main Steam Nozzle

Inner Radii; October 6, 1997

ISI-UT-11; Ultrasonic Examination of Centrifugally Cast Stainless Steel Pipe;

August 14, 2002

ISI-UT-16; UT Examination of Welds in Austenitic and High Nickel Alloy Materials;

January 28, 2002

ISI-UT-16A; Ultrasonic Examination of Austenitic Piping Welds to Appendix VIII;

November 1, 2002

ISI-ET-1.0; Bobbin Coil Data Analysis Guidelines; February 6, 2002

ISI-ET-3.0; Multiple Rotating Pancake Coil Data Analysis Guidelines; January 9, 2002

H25.2; Steam Generator Condition Monitoring; Revision 8

H25.1; Assessment of SG Tube Degradation Mechanisms; July 26, 2002

PI-SG-01; In-Situ Pressure Test Using the Computerized Data Acquisition System;

Revision 1

WPS AO 8155; Gas Tungsten Arc Welding (GTAW) of Stainless Steel; July 10, 1996

51

WPS P8P8GTN0; GTAW Welding of P8 toP8 Materials Without Impacts;

December 10, 1999

Miscellaneous Documents

Letter from NSP [Northern States Power] to NRC; Unit 1, Cycle 19 Steam Generator

Tube Support Plate Voltage Based Repair Criteria 90-Day Report; March 13, 1998

Letter from NSP to NRC; Response to Generic Letter 97-05: Steam Generator Tube

Inspection Techniques; March 13, 1998

Letter from NSP to NRC; Response to Generic Letter 97-06: Steam Generator Internals

Degradation; March 30, 1998

Letter from NSP to NRC; Response to Generic Letter 95-03: Circumferential Cracking

of Steam Generator Tubes; June 27, 1995

Letter from NRC to NEI; Flaw Evaluation Criteria; September 24, 2001

Condition Monitoring and Operational Assessment of Steam Generator Tubing at Prairie

Island, Unit 1 Cycle 20; February 2001

Prairie Island Unit 2 Site Qualification Document; January 30, 2002

INCO Alloys International CMTR 100523; January 16, 2001

Weld Data Sheet 31004; January 25, 2001

Procedure Qualification Record A08202 3-1; October 28, 1998

Procedure Qualification Record A08202 3-2; October 28, 1998

Procedure Qualification Record A08202 3-3; January 8, 1998

Procedure Qualification Record 1137; February 9, 1982

Procedure Qualification Record 1139 ; February 15, 1982

Procedure Qualification Record 1141; February 12, 1982

In-Situ Pressure Test Using the Computerized Data Acquisition System; Revision 1

WCAP 14166; Handbook of Flaw Evaluation for Prairie Island Units 1 and 2 Steam

Generators and Pressurizer; January 1995

TI 2515/150

Reactor Pressure Vessel Head and Vessel Head Penetration Nozzles

Calculation

ENG-ME-535; Effective Degradation Years for Unit 1 and 2; November 8, 2002

52

Corrective Action Documents

AR CAP 026636; Evaluate Indications Identified During RV Closure Head Bare Metal

Visual Examination; November 22, 2002

AR CAP 026603; Assess Head Temperature Used in EDY Calculation ENG-ME-535;

November 22, 2002

Engineering Work Request

EWR 003068; Inputs and Results of WCAP 14918 Should Be Verified; November 21,

2002

Drawings

NSP-521; Reactor Vessel Loops; Revision F

NSP-002; Reactor Vessel Loops; Revision E

NSP-001; Reactor Vessel Loops; Revision K

Miscellaneous Documents

Letter from Nuclear Management Corporation, LLC (NMC) to NRC; Response to NRC

Bulletin 2001-01; September 4, 2001

Letter from NMC to NRC; Response to NRC Bulletin 2001-01; March 29, 2002

Letter from NMC to NRC; 15-Day Response to NRC Bulletin 2002-01; April 3, 2002

Letter from NMC to NRC; NRC Bulletin 2002-01 60-Day Response; May 17, 2002

Letter from NMC to NRC; Supplemental Response to NRC Bulletin 2002-01;

July 19, 2002

Letter from NMC to NRC; NRC Bulletin 2002-02 15-Day Response; August 25, 2002

WO 0200959; Inspect RV Head Penetrations for Leakage; November 18, 2002

EPRI TR-1006899; Visual Examination for Leakage of PWR Reactor Head Penetrations

on Top of RPV Head; March 2002

WCAP 14918; Probabilistic Evaluation of Reactor Vessel Closure Head Penetration

Integrity for Prairie Island Units 1 and 2; July 1997

SWI GSE-23; Engineering Department Personnel Certification Program;

October 5, 2001

1R11

Licensed Operator Requalification Program

USAR 14.5.4; Steam Generator Tube Rupture; Revision 22

Procedure 1E-0; Reactor Trip or Safety Injection; Revision 21

53

NRC Inspection Report; Prairie Island Nuclear Generating Plant (PINGP) NRC

Inspection Report 50-282/01-18; 50-306/01-18; January 17, 2002

AR CAP 000232; November 2001 INPO [Institute of Nuclear Power Operations]

Evaluation; December 18, 2001

Simulator Team Evaluation PITCQ-83; Simulator Team Evaluation; September 4, 2002

1R12

Maintenance Rule Implementation

Safety-Related Cooling Water Pump Bearing/Seal Water Problems

Plant Procedure H24; PINGP Maintenance Rule Program; Revision 5

PINGP Maintenance Rule System Specific Basis Document, Cooling Water Section ;

Revision 3

PINGP Maintenance Rule Scope Determination and Performance Criteria Spreadsheet

5AWI 3.2.10; Investigation and Troubleshooting; Revision 7

5AWI 3.12.0; Nuclear Plant Maintenance; Revision 10

USAR, Section 10.4.1; Cooling Water System; Revision 22

AR CAP 023088; Unit 1 and 2 In Probabilistic Risk Assessment Orange Condition;

April 12, 2002

AR CAP 024290; Seal Water Flow on Safeguards Equipment; July 23, 2002

AR CAP 024661; 12 Diesel Driven Cooling Water Pump Declared Inoperable;

August 15, 2002

AR CAP 024872; Loss of Bearing Water Flow on 22 Diesel Driven Cooling Water Pump;

August 26, 2002

AR CAP 025866; Corrective Actions Associated with ACE 008558 Were Ineffective;

October 18, 2002

Maintenance Rule Evaluation (MRE) 000011; Evaluate High Differential Pressure on

121 Safeguards Traveling Screen; June 17, 2002

AR CAP 025920; Maintenance Preventable Functional Failure Definition for Safeguards

Traveling Screen in MRE 000011 is Not Correct; October 22, 2002

Auxiliary Building Roof Leakage

Plant Procedure H24; PINGP Maintenance Rule Program; Revision 5

PINGP Maintenance Rule System Specific Basis Document, Building Maintenance;

Revision 3

54

Volume 1C, PINGP Maintenance Rule Basis Document, Structures Monitoring Program;

Revision 2

5AWI 3.2.10; Investigation and Troubleshooting; Revision 7

5AWI 3.12.0; Nuclear Plant Maintenance; Revision 10

GEN 200202455; Water Intrusion Into TB [Terminal Box] A1265 Causing Inaccurate

Steam Release Flow; March 15, 2002

AR CAP 024598; Suspect Roof Leak Caused Water Damage to Critical Components

Internal TB-A1266; August 10, 2002

ACE 008522; Determine Roof Leakage Extent of Condition; August 14, 2002

ACE 008523; Determine If Installed Terminal Boxes and Panel That Contain Safety-

Related and/or Critical Components Are Being Properly Protected from Water Intrusion;

August 14, 2002

AR CAP 026021; No Maintenance Rule Evaluation Requested/Generated for

CAP 024598; October 29, 2002

MRE 000052; Water Damage to Critical Components of 1Z-826 Internal to TB A1266;

November 23, 2002

AR CAP 026025; Inconsistencies in Maintenance Rule Basis Documentation;

October 29, 2002

AR CAP 026063; Problems with Maintenance Rule Documentation: Consistency with

Design Basis Documents; October 31, 2002

AR CAP 027288; Auxiliary Building Roof Leakage Concerns Not Addressed in a Timely

Manner; December 18, 2002

Resolution of External Circulating Water Intake Screen Bypass Gate Repeat Failures

Unresolved Item

OTH 002196; Establish Reliability Performance Criteria for the Bypass Gates;

September 9, 2002

OTH 002199; Evaluate the Intake Screenhouse Bypass Gate Emergency Open

Solenoid Valve Reliability Against New Performance Criteria and Determine the

Maintenance Rule Status of the External Circulating Water System; September 9, 2002

Minutes of PINGP Maintenance Rule Expert Panel Meeting; November 27, 2002

1R13

Maintenance Risk Assessments and Emergent Work Control

October 16, 2002 Risk Assessment

55

Plant Status Report; October 16, 2002

Unit 2 Configuration Risk Assessment; October 16, 2002

PINGP Procedure H24.1; Assessment and Management of Risk Associated with

Maintenance Activities; Revision 5

WO 0206030; SP 2102 22 Turbine-Driven AFW Pump Monthly Test; October 16, 2002

Operating Procedure TP 1826; Outplant Safe Shutdown Equipment Check; Revision 7

October 21, 2002 Risk Assessment

Plant Status Report; October 21, 2002

Unit 2 Configuration Risk Assessment; October 21, 2002

PINGP Procedure H24.1; Assessment and Management of Risk Associated with

Maintenance Activities; Revision 5

22 Diesel Driven Cooling Water Pump Voluntary Limiting Condition of Operation Plan;

October 21, 2002

October 28, 2002 Risk Assessment

Plant Status Report; October 28, 2002

Unit 2 Configuration Risk Assessment; October 28, 2002

PINGP Procedure H24.1; Assessment and Management of Risk Associated with

Maintenance Activities; Revision 5

November 4, 2002 Risk Assessment

Plant Status Report; November 4, 2002

Unit 2 Configuration Risk Assessment; November 4, 2002

PINGP Procedure H24.1; Assessment and Management of Risk Associated with

Maintenance Activities; Revision 5

AR CAP 026066; Operations and Schedule Department-Level Implementing Procedures

Do Not Exist for Maintenance Rule (a)(4) (H24.1); October 31, 2002

1R14

Nonroutine Evolutions

Response to a Seismic Alarm Received Following Alaskan Earthquake

Abnormal Operating Procedure, AB-3; Earthquakes; Revision 18

56

Emergency Plan Implementing Procedure F3-2; Classification of Emergencies;

Revision 30

Technical Requirements Manual, Section 3.3.4; Miscellaneous Instrumentation;

Revision 3

Operations Logs, Control Room; November 3 through November 4, 2002

Alarm Response Procedure 47023-0603; Seismic Event; Revision 23

Remote Alarm Response Procedure C81000; Seismic Event; Revision 0

5AWI 8.2.4; Shelf Life Program; Revision 0

AR CAP 026100; Seismic Equipment, Unable to Read Chart; November 3, 2002

AR CAP 026101; Delay In Confirming Magnitude of Seismic Activity; November 3, 2002

AR CAP 027235; Evaluate and/or Determine Maintenance Department Shelf Life

Controls; December 13, 2002

CE 001350; Evaluate and If Necessary Initiate Corrective Action Regarding

CAP 026201; November 7, 2002

OPR 000350; Operability of Seismic Monitor Chart Recorder as Used In AB-3;

November 4, 2002

AR CAP 027232; Improved Guidance Needed in F3-2 Regarding Classification of

Earthquakes; December 13, 2002

AR CAP 027233; Improved Guidance Needed in AB-3 Earthquakes;

December 13, 2002

CA 003539; Evaluate and If Necessary Initiate Corrective Action Regarding

CAP 027232; December 17, 2002

CA 003540; Evaluate and If Necessary Initiate Corrective Action Regarding

CAP 027233; December 17, 2002

PINGP 1224; Crew Meeting Review of Noteworthy Event/Near Miss/Change;

November 8, 2002

SWI EP-300; Emergency Plan Activation Evaluation; Revision 0

OTH 023756; Using Guidance of SWI EP-300, Emergency Plan Activation Evaluation,

Relative to the November 3, 2002, Seismic Annunciator Alarm Event; January 9, 2003

Unit Shutdown and Cooldown

Operating Procedure 1C1.3; Unit 1 Shutdown; Revision 50

57

Operating Procedure 1C15; Residual Heat Removal System Unit 1; Revision 25

Operating Procedure 1C28.1; Auxiliary Feedwater System Unit 1; Revision 7

Emergency Operating Procedure 1ES-0.1; Reactor Trip Recovery; Revision 20

AR CAP 026338; Unit 1 Manual Reactor Trip from 12 percent Power Due to 13A

Feedwater Heater Level Problems; November 16, 2002

AR CAP 026333; 11 TDAFW [Turbine Driven Auxiliary Feedwater] Pump Auto Start Due

to Less Than Adequate Guidance in 1ES-0.1; November 16, 2002

ACE 008608; Evaluate Response and Followup to Unit 1 Manual Reactor Trip Event on

11/15/2002; December 4, 2002

AR CAP 027157; Equipment Not Quarantined Following Reactor Trip on 11/15/2002;

December 10, 2002

AR CAP 026346; Procedure C15 Has RHR Heat Exchanger Flow of 2600-2800,

Checklist C1.14 Has 2500; November 16, 2002

RCS Draindown

Integrated Checklist D2-1; Draining the Reactor Coolant System - Unit 1; Revision 24

Special Operations Procedure 1D2.1; RCS Reduced Inventory Operation After Pool

Flood; Revision 15

AR CAP 026447; RCS Level Indication Discrepancies During RCS Draindown to Top of

Hot Leg; November 19, 2002

Reactor Vessel Head Removal

WO 0114534; Unit 1 Reactor Vessel Head Removal; November 20, 2002

Maintenance Procedure D58.1.9; Unit 1- Reactor Vessel Head Removal; Revision 7

Reduced Inventory Operation

PINGP 1102; Unit 1 Shutdown Safety Assessment for Vessel Level 1 Foot Below Vessel

Flange; Revision 19

Operating Procedure 1C4.2; RCS Inventory Control - Post Refueling; Revision 12

Operating Procedure 1D2; RCS Reduced Inventory Operation; Revision 13

Unit Startup

Operating Procedure 1C1.2; Unit 1 Startup Procedure; Revision 29

Abnormal Operating Procedure 1C5 AOP3; Misalignment of Groups Within a Bank;

Revision 6

58

1R15

Operability Evaluations

Post-Loss-of-Coolant Accident (LOCA) Containment Integrity Analysis Peak

Containment Temperature

USAR 6.3.1.1; Containment Heat Removal Systems; Revision 22

5AWI 16.0.0; Action Request Process; Revision 1

AR CAP 025493; Peak Containment Temperature During LOCA; September 30, 2002

Memorandum, NAD File OC.PX.01.011; Updated Containment Pressure and

Temperature Response Following a Large Break LOCA; March 6, 2001

1R16

OWAs

SI Pump Venting

TS 3.5.2 and Bases; Emergency Core Cooling Systems - Operating; Revision 4

USAR 6.2; Safety Injection System; Amendment 158

Operator Workarounds; Venting of SI Pumps to Mitigate Possible Gas Intrusion;

October 30, 2002

AR CAP 023477; Free Climbing on 11 SI Pump to Operate Valve PT-17110;

May 13, 2002

WO 0206718, 0206719, 0206720, and 0206721; Install J-Hook Fitting for SI Pump

Venting; August 6, 2002

5AWI 3.10.8; Equipment Problem Resolution Process; Revision 1

Plant Status Report; November 6, 2002

Operating Procedure C11; Radiation Monitoring System; Revision 25

Cumulative Effects of OWAs

5AWI 3.10.8; Equipment Problem Resolution Process; Revision 1

PINGP List of Operator Workarounds for Unit 1 and Unit 2; December 10, 2002

Operator Workaround Aggregate Impact Analysis, Third Quarter 2002;

November 6, 2002

1R17

Permanent Plant Modifications

TS 3.7.8; Cooling Water System; Revision 131

USAR 10.4.1; Cooling Water System; Revision 22

WO 0204494; Tie In Additional Bearing Water Supply Piping to 22 Cooling Water Pump

59

Design Change 02CL01; Bearing Water to Cooling Water Pumps Modification;

Revision 0

10 CFR 50.59 Evaluation; Bearing Water to Cooling Water Pumps Modification 02CL01;

Revision 0

DBD SYS-35; Cooling Water System; Revision 4W

1R19

Post-Maintenance Testing

124 Air Compressor

WO 0206295; P3505-1-124 124 Air Compressor 1000 Hour PM; October 14, 2002

High Risk Maintenance Activities for the Work Week of October 14, 2002 (2403B);

October 14, 2002

AR CAP 025841; 124 Air Compressor Cooling Jacket Full of Mud; October 17, 2002

22 Diesel-Driven Cooling Water Pump

WO 025889; SP 1106B 22 Diesel Cooling Water Pump Monthly Test; October 26, 2002

AR CAP 025986; Missed Forced Cascade During 22 DDCL Pump Outage;

October 26, 2002

AR CAP 026010; Loose Oil Absorbent Materials Were Found in 22 DDCL Pump Room;

October 28, 2002

AR CAP 022335; Oil Absorbent Pads and a Snake Were Found in 12 and 22 DDCL

Pump Rooms; January 9, 2002

11 Safety Injection Pump

WO 0114563; PM 3117-1-11 11 SI Pump Inspection; November 6, 2002

Preventive Maintenance Procedure PM 3117-1-11; 11 Safety Injection Pump Refueling

Inspection; Revisions 8 and 9

22 Diesel-Driven Cooling Water Pump

WO 0204494; Tie In Additional Bearing Water Supply to 22 CL Pump;

November 11, 2002

SP 1106B; 22 Diesel Cooling Water Pump Monthly Test; Revision 59

22 Diesel-Driven Cooling Water Pump

WO 0211272; Restore Valve 2CL-136-1 for Bearing Water 22 DDCL Pump;

December 16, 2002

AR CAP 027261; 22 Diesel Cooling Water Pump Governor; December 17, 2002

1R20

Refueling and Other Outage Activities

60

5AWI 15.6.1; Shutdown Safety Assessment; Revision 1

PINGP 1102, Unit 1 Shutdown Safety Assessment; Unit 1 Shutdown Safety

Assessments; November 16, 2002 through November 29, 2002

Special Operations Procedure D5.2; Reactor Refueling Operations; Revision 34

AR CAP 026639; Four Inch Lockwire Potentially Dropped Into Innermast of Manipulator

Crane During Maintenance; November 23, 2002

AR CAP 027260; Evaluation/Action Not Initiated Following Screening of CAP 026366;

December 16, 2002

1R22

Surveillance Testing

SP 1392, Unit 1 RCS Bolting Inspection

WO 0200136; Unit 1 RCS Bolting Inspection; November 16, 2002

SP 1392; Unit 1 RCS Bolting Inspection; Revision 1

Plant Procedure H2; Program for Identification and Disposition of Small Reactor Coolant

Leakage on Low Alloy Reactor Coolant Pressure Boundary Components; Revision 3

SP 1083, Unit 1 Integrated SI Test With a Simulated Loss of Offsite Power

WO 0114254; Integrated SI Test with Simulated Loss of Offsite Power;

November 16, 2002

SP 1083; Unit 1 Integrated SI Test With a Simulated Loss of Offsite Power; Revision 27

AR CAP 026425; Continuous Use Procedure Compliance Issues During SP 1083

(Integrated SI); November 18, 2002

SP 1092B, Safety Injection Check Valve Test Part B

WO 0114257; SI Check Valve Test (Head Off) Part B: RWST; November 20, 2002

Surveillance Procedure P 1092B; Safety Injection Check Valve Test (Head Off) Part B:

RWST to RHR Flow Path Verification; Revision 10

SP 1092A, Safety Injection Check Valve Test Part A

WO 0114256; SI Check Valve Test Reactor Vessel Head Off Part A;

November 20, 2002

SP 1092A; SI Check Valve Test (Head Off) Part A: High Head SI Flow Path

Verification; Revision 22

SP 1177, Core Inventory Verification

61

WO 0114283; Core Inventory Verification; November 25, 2002

SP 1177; Core Inventory Verification; Revision 9

Core Operating Limits Report - Unit 1, Cycle 22; Revision 0

Core Operating Limits Report - Unit 1, Cycle 21; Revision 2

SP 1305, D2 Diesel Generator Monthly Slow Start Test, and SP 1335, D2 Diesel

Generator 18-Month 24-Hour Load Test

WO 0207269; D2 Diesel Generator Monthly Slow Start Test; November 25, 2002

SP 1305; D2 Diesel Generator Monthly Slow Start Test; Revision 28

WO 0209430; D2 Diesel Generator 18-Month 24-Hour Load Test; November 25, 2002

SP 1335; D2 Diesel Generator 18-Month 24-Hour Load Test; Revision 8

TS 3.8.1 and 3.8.2; AC Sources - Operating; and AC Sources - Shutdown; Amendment

No. 158

SP 1008, Reactor Protection Logic Time Response Test

WO 0114190; Reactor Protection Logic Time Response Test; November 14, 2002

SP 1008; Reactor Protection Logic Time Response Test; Revision 23

SP 1092D, Safety Injection Check Valve Test

WO 0114259; SI Check Valve Test Reactor Vessel Head On Part D: Low Head;

December 2, 2002

SP 1092D; Safety Injection Check Valve Test (Head On) Part D: Low Head SI

Discharge Flow Path Verification; Revision 3

WO 0114268; Turbine Building Cooling Water Header Isolation SI Relay Test;

December 2, 2002

SP 1126; Turbine Building Cooling Water Header Isolation SI Relays 1SI-12X and

1SI-22X Contact Verification Test; Revision 4

SP 1834, Unit 1 Containment Coating Inspection

WO 0115305; Unit 1 Containment Coating Inspection; November 24, 2002

SP 1834; Unit 1 Containment Coating Inspection; Revision 0

SP 1070, Reactor Coolant System Integrity Test

62

WO 0114211; Reactor Coolant System Integrity Test; December 3, 2002

SP 1070; Reactor Coolant System Integrity Test; Revision 33

AR CAP 027049; Excess Letdown Heat Exchanger Endbell Flange Leak During

SP 1070; December 5, 2002

SP 1750, Post Outage Containment Close-Out Inspection

WO 0114186; Post Outage Containment Close-Out Inspection; November 29, 2002

SP 1750; Post Outage Containment Close-Out Inspection; Revision 25

1R23

Temporary Modifications

Cooling Water Pipe Patch

Temporary Modification 02T131; Containment Cooling Line 14-ZX-6 Pipe Patch;

May 10, 2002

NMC Standard 10 CFR 50.59 Screening 1487; Revision 0

AR CAP 024556; ZX [Containment Cooling] Piping Inclusion On Top Ten Equipment

List; August 8, 2002

AR CAP 021192; Leak on Chill Water Line 14-ZX-6, the Common Header to Unit 1 and

Unit 2 ; March 27, 2002

CA001896; Perform Action Plan for ZX Piping to Increase Reliability; August 10, 2002

Construction Code B 31.1; 1969

Prairie Island USAR, Section 5.2.2.3.1; Containment Air Cooling Systems; Revision 22

Instrument Air Pipe Clamp

Temporary Modification 02T147; Instrument Air Pipe Clamp

NMC Standard 10 CFR 50.59 Screening 1632; Revision 0

Operations Logs; 10/22/02, 9:18 P.M.

5AWI 6.5.0; Temporary Modifications; Revision 11

DBD SYS-34; Design Basis Document - Station and Instrument Air System;

Revision 4W

Prairie Island USAR, Section 10.3.10.2.2; Instrument Air System; Revision 23

1EP6

Drill Evaluation

PINGP Emergency Plan Drill Package; October 23, 2002, Revision 0

63

PINGP Emergency Plan Drill Critique Report; October 23, 2002

AR CAP 025951; 2002 Fall Drill - Dosimeters Were Not Distributed to Security;

October 24, 2002

AR CAP 0025952; 2002 Fall Drill - Plant Evacuation Ordered in an Untimely Manner;

October 24, 2002

AR CAP 0025955; 2002 Fall Drill - Provide an Evacuation Switch in the Technical

Support Center; October 24, 2002

AR CAP 0025956; Establish Fast-Track Dispatch for Duty Operators from Operational

Support Center; October 24, 2002

AR CAP 0025957; 2002 Fall Drill - Cross-Tie of 480-Volt Safeguards Buses Considered

Untimely; October 24, 2002

2OS1 Access Controls for Radiologically Significant Areas

Radiation Protection Implementing Procedure (RPIP) 1133; Multiple TLD

[Thermoluminescent Luminescent Dosimeter] Badging; Revision 8

RPIP 1135; RWP [Radiation Work Permit] Coverage; Revision 13

AR CAP 023388; Radiological Postings Removed; May 6, 2002

AR CAP 023386; Contamination Found in a Clean Area Around U2 RHR Pits; May 6,

2002

AR CAP 023404; Operator Reached Across a Rad Boundary and Operated a Valve with

Bare Hands; May 7, 2002

AR CAP 026493; High Radiation Area Boundary Left Down; November 20, 2002

AR CAP 023449; Neutron Posting Left Down; May 9, 2002

AR CAP 023459; Roll-up of Rad Worker Practices Issues for the Week Ending 5/9/02;

May 10, 2002

AR CAP 023478; Operator Received a Dose Alarm While in the RHR Pit; May 13, 2002

AR CAP 023566; Worker Received Dose Alarm During Spent Fuel Pool Skimmer Filter

Change-out; May 20, 2002

64

AR CAP 023912; Barrel Yard RCA Boundary Was Left Down and Unattended; June 20,

2002

AR CAP 023914; Worker Exhibiting Poor Rad Practices; June 20, 2002

AR CAP 023930; Snubber Test Stand Found to be Contaminated During Routine

Survey; June 21, 2002

AR CAP 023974; Contaminated Area Incorrectly Posted; June 25, 2002

AR CAP 024061; Locked HRA Sign Was Found Laying on the Floor Near Locked HRA;

July 3, 2002

AR CAP 024220; Radiologically Controlled Areas Have Dual Postings; July 18, 2002

AR CAP 024286; Green Drain Hose Internally Contaminated; July 22, 2002

AR CAP 025715; Rad Worker Practice Changes Not Adequately Conveyed to Plant

Personnel; October 11, 2002

AR CAP 025915; Painter Received a Dose Alarm on His ED [Electronic Dosimeter]

While in ISFSI [Independent Spent Fuel Storage Installation]; October 22, 2002

AR CAP 026095; Individual Left RCA Prior to Clear Friskall; November 2, 2002

AR CAP 02339; Worker Sweeping from Inside Contaminated Area to Outside the Area;

November 16, 2002

AR CAP 026493; High Radiation Area Boundary Left Down; November 20, 2002

2OS2 ALARA Planning and Controls

SA 021671; Radiation Protection Self Assessment; September 13, 2002

D27.18; Special Operations Procedure - Stem Generator Nozzle Dam Installation;

Revision 22

MSIP 7009; Steam Generator Nozzle Dam Installation Pre-job Briefing

RPIP 1004; Radiation Protection ALARA Program; Revision 5

5AWI 10.1.1; ALARA Plan; Revision 0

RWP 1022; ALARA Review 2002 U1 SG Primary Manway Remove and Install;

October 8, 2002

RWP 1027; ALARA Review 2002 U1 SG Primary Nozzle Dam Install and Remove and

SG Closeout Inspection; October 14, 2002

65

PINGP 1112; Pre-job Brief - 12 CL Insert and Hot Particle Removal; November 19, 2002

AR CAP 023227; Investigate Potential Negative Trend in Entering Controlled Area

Without Electronic Dosimetry; April 22,2002

AR CAP 023724; Maintenance Working in Contaminated Area After Hours with No HP

[Health Physics] Support; June 6, 2002

AR CAP 023725; U2 CS Pump Room Scaffold Added to Work Week Without Informing

ALARA Contact; June 6, 2002

AR CAP 023992; Emergency Electronic Dosimeter Alarm Set-points Were Not Reset

Before Issue; June 26, 2002

AR CAP 024129; Operators Performed SP 2090A Under Wrong RWP; July 12, 2002

AR CAP 024140; Clean Area in U2 CS Pump Room Was Contaminated While

Performing SP 2090A; July 12, 2002

AR CAP 025131; WO 200241 is for Work in Containment and RWP Required Block

Was N; September 10, 2002

AR CAP 025490; Dose Goal Not Met 9/22 to 9/29/02; September 30, 2002

AR CAP 026489; Outage Delay and Extra Dose Due to Discreet Radioactive Particle on

12 S/G Cold Leg Diaphragm; November 20, 2002

4OA1 Performance Indicator Verification

Reactor Coolant System Leakage

TS 3.1.8; Reactor Coolant System Leakage; Revision 91

Operations Log Entries, Units 1 and 2; August 1, 2001, through September 1, 2002

AR CAP 025257; Potentially Incorrect Primary to Secondary Leak Rate Values;

September 17, 2002

SP 1001AA; Daily Reactor Coolant System Leakage Test; Revision 30

WO 0205837; SP 1001AA Daily Reactor Coolant System Leakage Test; October 10,

2002

Safety System Unavailability - Emergency AC Power System

Performance Indicator Data Summary Reports; Safety System Unavailability -

Emergency AC Power System; 4th Quarter 2001, 1st Quarter 2002, 2nd Quarter 2002,

and 3rd Quarter 2002

Operations Log Entries; Unit 1 and Unit 2 Control Room; October 1, 2001, through

October 24, 2002

66

SP 2093; D5 Diesel Generator Monthly Slow Start Test; Revision 71

SP 2305; D6 Diesel Generator Monthly Slow Start Test; Revision 19

Occupational Radiation Safety

AR CAP 024181; Radiation Area Sign Was Found Laying on the 695 Drop Area Floor;

July 16, 2002

AR CAP 025662; Radiation Area Sign Found Down; October 8, 2002

AR CAP 026004; Potential Adverse Trend in Rad Worker Practices; October 28, 2002

AR CAP 026093; High Radiation Area Key Locker Was Found Open and Unguarded at

Access; November 2, 2002

4OA2 Identification and Resolution of Problems

Letter From Walter Djordjevic To Mark McKeown; Walkdown Assessment of D1/D2

[Emergency Diesel Generators] Tornado Missile Vulnerability; September 10, 2002

GEN-PI-005; Tornado and Seismic Evaluation of D1 and D2 Components; Revision 0

ENG-CS-233; Tornado Missile Evaluation; Revision 0

ANSI/ANS-2.3-1983; Standard for Estimating Tornado and Extreme Wind

Characteristics at Nuclear Power Sites; American Nuclear Society, 1983

USAR Table 12.2-1; Classification of Structure, Systems, and Components; Revision 23

DBD TOP-05; Hazards; Revision 2W

DBD STR-03; Turbine Building; Revision 2W

GEN 20014805; Inadequate D1/D2 Diesel Tornado Damage Analysis; June 7, 2001

AR CAP 000137; Inadequate D1/D2 Diesel Tornado Damage Analysis; June 4, 2001

OPR 000054; Operability Recommendation CAP 000137

4OA3 Event Followup

Response to a Seismic Alarm Received Following Alaskan Earthquake

Abnormal Operating Procedure, AB-3; Earthquakes; Revision 18

Emergency Plan Implementing Procedure F3-2; Classification of Emergencies;

Revision 30

Technical Requirements Manual, Section 3.3.4; Miscellaneous Instrumentation; Revision

3

67

Operations Logs, Control Room; November 3 through November 4, 2002

Alarm Response Procedure 47023-0603; Seismic Event; Revision 23

Remote Alarm Response Procedure C81000; Seismic Event; Revision 0

5AWI 8.2.4; Shelf Life Program; Revision 0

AR CAP 026100; Seismic Equipment, Unable to Read Chart; November 3, 2002

AR CAP 026101; Delay In Confirming Magnitude of Seismic Activity; November 3, 2002

AR CAP 027235; Evaluate and/or Determine Maintenance Department Shelf Life

Controls; December 13, 2002

CE 001350; Evaluate and If Necessary Initiate Corrective Action Regarding CAP

026201; November 7, 2002

OPR 000350; Operability of Seismic Monitor Chart Recorder as Used In AB-3;

November 4, 2002

AR CAP 027232; Improved Guidance Needed In F3-2 Regarding Classification of

Earthquakes; December 13, 2002

AR CAP 027233; Improved Guidance Needed In AB-3 Earthquakes;

December 13, 2002

CA 003539; Evaluate and If Necessary Initiate Corrective Action Regarding

CAP 027232; December 17, 2002

CA 003540; Evaluate and If Necessary Initiate Corrective Action Regarding

CAP 027233; December 17, 2002

PINGP 1224; Crew Meeting Review of Noteworthy Event/Near Miss/Change;

November 8, 2002

SWI EP-300; Emergency Plan Activation Evaluation; Revision 0

OTH 023756; Using Guidance of SWI EP-300, Emergency Plan Activation Evaluation,

Relative to the November 3, 2002, Seismic Annunciator Alarm Event; January 9, 2003

EPPOS No. 2; Emergency Preparedness Position On Timeliness Of Classification Of

Emergency Conditions, Revision 0

NEI 99-02, Section 2.4; Emergency Preparedness Cornerstone; Revision 2

4OA5 Other Activities

TI 2515/149; Mitigating Systems Performance Index Pilot Verification; September 24,

2002

68

Draft NEI 99-02 MSPI, Appendix F; Methodologies for Computing the Unavailability

Index and Determining Performance Index Validity; Revision 0

Draft NEI 99-02 MSPI, Attachment A; Mitigating System Performance Index;

September 24, 2002

Electronic Control Room Logs; July 1, 2000, through September 30, 2002

Electronic Limiting Conditions for Operations Logs; July 1, 2000, through September 30,

2002

Excel Spreadsheets for MSPI Data Submittals, Baseline Data; 2nd Quarter 2002, and 3rd

Quarter 2002

Performance Indicator Data; from www.nrc.gov/NRR/OVERSIGHT/ website; 3rd Quarter

2000 through 3rd Quarter 2002

Prairie Island MSPI Notebook

4OA7 Licensee-Identified Violation

PINGP TS, Section 3.7.8; Cooling Water System; Amendment 158

PINGP TSs, Section 3.7.8; AC Sources; Amendment 158

AR CAP 025986; Missed Forced Cascade During 22 DDCL Pump Outage; October 26,

2002

CE 001282; Evaluate Potential Reportability of Failure to Complete SP 1118;

October 29, 2002

Root Cause Evaluation 000175; Perform Root Cause Evaluation into 22 DDCL Pump

Issue; October 29, 2002

Operator Logs from October 24 through October 26, 2002

SP 1118; Verifying Paths from the Grid to Unit 1 Buses; Revision 15

DBD SYS-15; Design Basis Document for the Residual Heat Removal System;

Revision 3

1C1.3; Unit 1 Shutdown Procedure; Revision 50

USAR Section 4.4.3.3; Low Temperature Overpressurization Mitigation; Revision 23

USAR Section 6.2; Safety Injection System; Revision 22

TS 3.4.12; Low Temperature Overpressure Protection; Amendment 158

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TS 3.4.13; Low Temperature Overpressure Protection; Amendment 158

AR CAP 026440; Discovered Test Rod Installed on RH-8-1, 11/12 RHR Pumps Suction;

November 18, 2002

ACE 008610; Conduct ACE Regarding CAP 026440; November 20, 2002

OPR 000358; Determine if Valve/RHR is Operable in This Configuration; November 19,

2002

LIST OF ACRONYMS USED

AC

Alternating Current

ACE

Apparent Cause Evaluation

ADAMS

Agencywide Documents Access and Management System

AFW

Auxiliary Feedwater

ALARA

As-Low-As-Is-Reasonably-Achievable

AR

Action Request

ASME

American Society of Mechanical Engineers

AWI

Administrative Work Instruction

B

Barrier Integrity

CA

Caustic Addition

CAP

Corrective Action Program

CC

Component Cooling Water

CE

Condition Evaluation

CL

Cooling Water

CS

Containment Spray

CFR

Code of Federal Regulations

DBD

Design Basis Document

DDCL

Diesel-Driven Cooling Water

F

Degrees Fahrenheit

DRP

Division of Reactor Projects

ED

Electronic Dosimeter

EDG

Emergency Diesel Generator

EDY

Effective Degradation Years

EPPOS

Emergency Preparedness Position

ET

Eddy Current

EWR

Engineering Work Request

GEN

General Condition Report

GTAW

Gas Tungsten Arc Welding

HC

Hydrogen Control

HP

Health Physics

HRA

High Radiation Area

HSAS

Homeland Security Advisory System

IE

Initiating Event

IMC

Inspection Manual Chapter

INPO

Institute of Nuclear Power Operations

IPEEE

Individual Plant Examination of External Events

70

IR

Inspection Report

ISFSI

Independent Spent Fuel Storage Installation

ISI

Inservice Inspection

LOCA

Loss of Coolant Accident

MCC

Motor Control Center

MDCL

Motor-Driven Cooling Water

MRE

Maintenance Rule Evaluation

MS

Mitigating System

MSIP

Maintenance Standards Implementing Procedure

MSPI

Mitigating Systems Performance Index

NCV

Non-Cited Violation

NEI

Nuclear Energy Institute

NMC

Nuclear Management Corporation, LLC

NRC

U.S. Nuclear Regulatory Commission

NSP

Northern States Power

OTH

Other

OPR

Operability Recommendation

OWA

Operator Workaround

PARS

Publicly Available Records

PINGP

Prairie Island Nuclear Generating Plant

PM

Preventive Maintenance

PMT

Post-Maintenance Test

PT

Dye Penetrant

PWR

Pressurized Water Reactor

RC

Reactor Coolant

RCA

Radiologically Controlled Area

RCS

Reactor Coolant System

RHR

Residual Heat Removal

RIS

Regulatory Information Summary

RPIP

Radiation Protection Implementing Procedure

RPV

Reactor Pressure Vessel

RV

Reactor Vessel

RWP

Radiation Work Permit

RWST

Refueling Water Storage Tank

SDP

Significance Determination Process

SG

Steam Generator

SI

Safety Injection

SP

Surveillance Procedure

SR

Surveillance Requirement

TB

Terminal Box

TDAFW

Turbine-Driven Auxiliary Feedwater

TI

Temporary Instruction

TLD

Thermoluminescent Dosimeter

TS

Technical Specification

URI

Unresolved Item

USAR

Updated Safety Analysis Report

UT

Ultrasonic

VHP

Vessel Head Penetration

VHRA

Very High Radiation Area

71

WO

Work Order

ZX

Containment Cooling

72

December 20, 2002

MEMORANDUM TO: John Thompson, Senior Reactor Operations Engineer

Inspection Programs Branch

Division of Inspection Program Management

Office of Nuclear Reactor Regulation

THRU:

Ken Riemer, Branch Chief

Reactor Programs Branch 5, Region III

FROM:

John Adams, Senior Resident Inspector, Prairie Island

SUBJECT:

COMPLETION OF TEMPORARY INSTRUCTION (TI) 2515/149 AT

PRAIRIE ISLAND

The inspectors completed the requirements of TI 2515/149, Mitigating Systems Performance

Index (MSPI) Pilot Verification, at Prairie Island on December 20, 2002. The inspectors

determined that the licensee made a reasonable best effort to provide accurate and complete

data for this voluntary pilot program. Most data errors were small and most other problems

were because the guidance for the MSPI program was still under development.

The following discrepancies/issues were noted: (Paragraph numbers correspond to the

inspection requirements sections of TI 2515/149.)

03.02 Risk-Significant Functions

The licensee did not originally specify which Maintenance Rule risk-significant

functions were to be counted as MSPI functions. All Maintenance Rule functions

were listed. Licensee engineers revised the list of functions during the

inspection.

The licensee originally listed the auxiliary feedwater (AFW) system function as

To provide water to the steam generators ... Since the success criterion is met

by only supplying flow to one steam generator, the function should have been

stated as To provide water to at least one steam generator ... to be consistent

with Nuclear Energy Institute (NEI) 99-02, draft Attachment A. Licensee

engineers corrected the function description during the inspection.

The licensee did not include the electrical cross-ties from the other units

safeguards busses as a risk-significant function of the emergency AC power

(EAC) system although it is modeled in its probabilistic risk assessment (PRA)

and is a significant factor in calculating the Fussell-Vesley (F-V) value. (See

additional comments under 03.04.)

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03.03 Success Criteria

The licensees MSPI and Maintenance Rule success criteria for AFW included

providing 200 gallons per minute (gpm) to at least one steam generator within

one minute at 1300 pounds per square inch - atmosphere (psia). The licensees

design basis documentation (DBD) stated success is 200 gpm to at least one

steam generator within one minute at 1142.6 pounds per square inch - gauge

(psig). Licensee engineers revised the MSPI success criteria to match the

design basis of 1142.6 psig during the inspection.

The licensees MSPI success criteria did not indicate where the parameters

specified came from (such as DBD, Updated Safety Analysis Report (USAR), or

PRA). The licensee was informed that this information should be available for

inspection.

One of the success criteria for the component cooling water (CC) system was

listed as 200 degrees. This was a piping design limit but obviously the system

could not meet its function of cooling front line systems if it were that hot. The

licensee was informed that this criterion should be revised.

03.04 Unreliability Boundary Definition

For AFW, the licensee did not document why the valves in the safety-related

backup water supply from the cooling water system were not included as active

components.

The licensee did not document why AFW steam generator isolation valves ( such

as MV-32242) are not considered active components like they did for the throttle

valves (such as MV-32238).

For AFW, the licensee included the recirculation valves (CV-31153, CV-31154,

CV-31418, and CV-31419) as active components but they have no F-V because

they are not modeled in the PRA. There was a statement in the licensees MSPI

documentation that the valves will be modified to be normally open, but that is

not true anymore. Since the valves have no F-V values, unreliability data

submitted for these valves do not get counted in the MSPI calculation.

For the cooling water (CL) system, the licensee did not document why dump-to-

grade valves MV-32329, 32322, and 32036 were not included as active

components.

For CC, the licensee included MV-32120 and other valves as active components

but they had zero F-V values assigned. The licensee documented a qualitative

discussion as to why the F-V valves would be negligible, but did not provide any

quantitative evaluation to support it. The licensee stated that the valves were

modeled in the PRA and that they would provide the quantitative importance

values. Since the valves have such low F-V values, their unreliability data do not

contribute to the MSPI calculation.

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For CL, the heat exchanger throttle valves (CV-31381, CV-31411, CV-31383,

and CV-31384) are included as active components but are not modeled in the

PRA and have F-V values of zero. Therefore, unreliability data reported for

these valves do not get counted in the MSPI calculation.

Emergency Operating Procedure E-0, Step 8, has an action to close MV-32115,

Component Cooling Water Supply to the Spent Fuel Pool Heat Exchanger.

The USAR indicates that a component cooling train could fail due to excessive

flow if the valve is not closed. The licensee did not include this valve as an

active component but agreed during the inspection that it should be included.

For EAC, the cross-tie breakers from the other unit are modeled in the PRA and

have a large effect on the F-V values for the emergency diesel generators.

However, the licensee did not include the cross-tie breakers as active

components. According to NEI 99-02, the breakers should be included as active

components since they are in the PRA. Licensee engineers stated during the

inspection that they intend to add the breakers as active components. However,

NEI 99-02, Draft Appendix F, Table 2, does not have industry information for

breakers, and they are not listed as one of the component types to choose from

in the MSPI spreadsheet. In order to add these active components, the NEI

spreadsheet will have to be revised.

The licensee did not document why the safety injection accumulator discharge

valves were not included as active components although the Emergency

Operating Procedures direct that they be closed during certain accidents.

For the high pressure safety injection (SI) system, valves, such as MV-32202,

were included as active components but are not in the PRA. F-V values were

assigned that the licensee PRA engineers say are conservative, but they did not

make similar assignments for other valves without F-V values. The licensee

should justify why number is conservative, and possibly apply the same

technique to other valves like CV-31381 discussed above. During the

inspection, the licensee stated that they will consider assigning conservative F-V

values to all active components not modeled in the PRA.

The licensees PRA model assumed the A train CC pump and both non-safety

CL pumps were continuously running. Since the model assumed they were

running, there was no unavailability F-V importance factor for them. Thus any

unavailability data for those pumps do not get counted in the MSPI calculation.

However, the licensee reported unavailability hours for those pumps.

Unavailablity hours for the pumps assumed to be running in the PRA should be

assigned to the pumps assumed to be in standby so that they get counted in the

MSPI calculation, or appropriate unavailability F-V values should be assigned to

the pumps. The licensees PRA engineer stated that this issue would be

reviewed.

75

03.05 Train/Segment Unavailability Boundary Definition

The licensee did not specify electrical boundaries. NEI 00-02 guidance stated

that the last breaker or relay for electrical power and controls should be in the

boundaries for pumps and valves.

03.06 Entry of Baseline Data - Planned Unavailability

The licensees calculation for subtracting unplanned unavailability from total

unavailability to get just the planned hours had a discrepancy in that some

cascading unplanned unavailability hours were more than the total unplanned

unavailability hours for the train. This resulted in errors in the baseline planned

unavailability. Licensee engineers found the source of the error during the

inspection.

03.07 Entry of Baseline Data - Unplanned Unavailability

No discrepancies were noted. Correct table values were used.

03.08 Entry of Base line Data - Unreliability

No discrepancies were noted. Correct table values were used.

03.09 Entry of Performance Data - Unavailability

The inspectors sampled data reported for the 2nd quarter 2002 for CC and CL

and the 3rd quarter 2002 for AFW for the current performance index and also

sampled data for the 3rd quarter 2000 for AFW and 4th quarter 2000 for CC and

CL for verification of historic values.

No discrepancies were identified in AFW unavailability data for the 3rd quarter

2002.

The licensee made a small error in the reported unavailable time for the 22 CC

train when there was a problem with the 22 CC heat exchanger temperature

control valve, CV-31384, on May 5-6, 2002. Licensee engineers found the

source of the error during the inspection.

No discrepancies were noted in the CL unavailability for the 2nd quarter 2002.

The inspectors identified errors in the reported data for unavailability of AFW for

the 3rd quarter 2000 for all except the 12 AFW pump. Licensee engineers later

identified that some unavailable time had been double counted.

03.10 Entry of Performance Data - Unreliability

The inspectors sampled data from the 2nd quarter 2002 for CC and CL and the 3rd

quarter 2002 for AFW for current performance and also sampled data for the 3rd quarter

76

2000 for AFW and 4th quarter 2000 for CC and CL for verification of historic values. The

inspectors also performed a very limited sampling of data for other systems.

For the AFW, SI, and RHR systems, the licensee estimated pump start

demands, run times, and valve stroke demands based on normal surveillance

schedules. The licensee did not provide auditable records of how those

estimated were obtained.

The inspectors noted that the licensee reported one start demand for each RHR

pump during the 2nd quarter 2002. According to the electronic control room log

and process book, there were two demands on the 22 RHR pump. This was one

example of an error due to estimating start demands and run times based only

on the number of surveillance tests that are typically done.

The licensee reported the correct number of start demands for the 11 and 12 CC

pumps for the 2nd quarter 2002. However, the inspectors identified that one of

the starts on each of the pumps was a post-maintenance test (PMT). In general,

the licensee did not eliminate PMTs from reported start demands for most

systems.

The inspectors identified that the run hours reported for the 11 CC pump were

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> short for the 2nd quarter 2002. Licensee engineers found the source of

the error during the inspection.

The licensee reported seven starts for each of the 21 and 22 CC pumps in the

2nd quarter 2002. However, the inspectors determined that one of the starts on

the 21 CC and two of the starts on the 22 CC were PMTs and should not have

been counted.

The inspectors identified that the licensee did not report the May 2, 2002, trip of

the 22 CL pump as a start demand failure (it was running less than an hour).

The trip was due to a spurious overspeed trip due to radio interference. The trip

happened during a surveillance test but took more than a trivial amount of time

to diagnose. The inspectors determined that the trip should have been

considered a start demand failure. During the inspection, the licensee agreed to

count it as a failure.

The licensee reported six start demands on the 22 CL pump during the 3rd

quarter 2002. The inspectors could only identify four. During the inspection, the

licensee found the source of the error.

03.11 MSPI Calculation

Some of the MSPI F-V coefficients were not verified because the licensee had

not identified all of the F-V coefficients due to certain components not being

modeled in their PRA (as noted in Section 03.04) or the F-V coefficient was

truncated out at a 1E-10 value. Specific components with no F-V value due to

truncation include:

77

Units 1 and 2 CC heat exchanger outlet valves, MV-32120, MV-32121,

MV-32122, and MV-32123;

Units 1 and 2 Turbine Building Loop A/B Cooling Water Header Valves,

MV-32031 and MV-32033;

Units 1 and 2 SI pump suction valves, MV-32163 and MV-32191;

Units 1 and 2 SI test to refueling water storage tank isolation valves,

MV-32202, MV-32203, MV-32204, and MV-32205;

Units 1 and 2 Bus 15 to Bus 25 tie breaker, 15-8; and

Units 1 and 2 Bus 25 to Bus 15 tie breaker, 25-17.

The NRC staff has not qualified the licensees PRA.