ML070300881

(Superceded-see ML070720224) IR 05000327-06-005, IR 05000328-06-005; IR 07200034-06-002; 10/01/06 - 12/31/06; Sequoyah Nuclear Plant, Units 1 & 2; Licensed Operator Requalification Program

ML070300881
Person / Time
Site:	Sequoyah
Issue date:	01/30/2007
From:	Widmann M Reactor Projects Region 2 Branch 6
To:	Singer K Tennessee Valley Authority
References
IR-06-002, IR-06-005
Download: ML070300881 (51)

See also: IR 05000327/2006005

Text

January 30, 2007

Tennessee Valley Authority

ATTN: Mr. Karl W. Singer

Chief Nuclear Officer and

Executive Vice President

6A Lookout Place

1101 Market Street

Chattanooga, TN 37402-2801

SUBJECT:

SEQUOYAH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT

05000327/2006005, 05000328/2006005 AND 07200034/2006002

Dear Mr. Singer:

On December 31, 2006, the United States Nuclear Regulatory Commission (NRC) completed

an inspection at your Sequoyah Nuclear Plant, Units 1 and 2. The enclosed integrated

inspection report documents the inspection results, which were discussed on January 3, 2007,

with Mr. R. Duet and other members of your staff.

The inspection examined activities conducted under your licenses as they relate to safety and

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

licenses. The inspectors reviewed selected procedures and records, observed activities, and

interviewed personnel.

The report documents one NRC-identified finding of very low safety significance. This finding

was determined to involve a violation of NRC requirements. Additionally, a licensee-identified

violation which was determined to be of very low safety significance is listed in this report.

However, because of their very low safety significance and because they are entered into your

corrective action program, the NRC is treating these findings as non-cited violations (NCVs)

consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this

report, you should provide a response within 30 days of the date of this inspection report, with

the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN.:

Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional

Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory

Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Sequoyah

Nuclear Plant.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its

enclosure, and your response (if any) will be available electronically for public inspection in the

NRC Public Document Room or from the Publically Available Records (PARS) component of

2

NRCs document system (ADAMS). ADAMS is accessible from the NRC Website at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Malcolm T. Widmann, Chief

Reactor Projects Branch 6

Division of Reactor Projects

Docket Nos.: 50-327, 50-328,72-034

License Nos.: DPR-77, DPR-79

Enclosure: Inspection Report 05000327/2006005 and 05000328/2006005 and

07200034/2006002 w/Attachment: Supplemental Information

cc: w/encl: (See page 3)

____ML070300881 __

OFFICE

RII:DRP

RII:DRP

RII:DRP

RII:DRP

RII:DRS

RII:DRS

RII:DRS

SIGNATURE

LXG /RA/

WTM /RA/

JBB via email

MES via email

JXD /RA/

FJE /RA/

LFL /RA/

NAME

LGarner

MWidmann

JBaptist

MSpeck

JDiaz-Velez

FEhrhardt

LLake

DATE

01/30/2007

01/30/2007

01/30/2007

01/30/2007

01/30/2007

01/30/2007

01/30/2007

E-MAIL COPY?

YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO

OFFICE

RII:DRS

RII:DRS

RII:DRS

RII:DRS

RII:DRS

RII:DRS

RII:DRS

SIGNATURE

GWL /RA/

DLM /RA/

ECM /RA/

BWM /RA/

CRO for

SDR /RA/

CRO for

NAME

GLaska

DMasPenaranda EMichel

BMiller

RMoore

SRose

CSmith

DATE

01/30/2007

01/30/2007

01/30/2007

01/30/2007

01/30/2007

01/30/2007

01/30/2007

E-MAIL COPY?

YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO

OFFICE

RII:DRS

SIGNATURE

CRS /RA/

NAME

CStancil

DATE

01/30/2007

E-MAIL COPY?

YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO YES

NO

3

cc w/encls:

Ashok S. Bhatnagar

Senior Vice President

Nuclear Operations

Tennessee Valley Authority

Electronic Mail Distribution

Preston D. Swafford

Senior Vice President

Nuclear Support

Tennessee Valley Authority

Electronic Mail Distribution

Larry S. Bryant, Vice President

Nuclear Engineering &

Technical Services

Tennessee Valley Authority

Electronic Mail Distribution

Randy Douet

Site Vice President

Sequoyah Nuclear Plant

Electronic Mail Distribution

General Counsel

Tennessee Valley Authority

Electronic Mail Distribution

John C. Fornicola, General Manager

Nuclear Assurance

Tennessee Valley Authority

Electronic Mail Distribution

Glenn W. Morris, Manager

Licensing and Industry Affairs

Sequoyah Nuclear Plant

Tennessee Valley Authority

Electronic Mail Distribution

Beth A. Wetzel, Manager

Corporate Nuclear Licensing and

Industry Affairs

Tennessee Valley Authority

4X Blue Ridge

1101 Market Street

Chattanooga, TN 37402-2801

Robert H. Bryan, Jr., General Manager

Licensing and Industry Affairs

Sequoyah Nuclear Plant

Tennessee Valley Authority

4X Blue Ridge

1101 Market Street

Chattanooga, TN 37402-2801

David A. Kulisek, Plant Manager

Sequoyah Nuclear Plant

Tennessee Valley Authority

Electronic Mail Distribution

Lawrence E. Nanney, Director

TN Dept. of Environment & Conservation

Division of Radiological Health

Electronic Mail Distribution

County Mayor

Hamilton County Courthouse

Chattanooga, TN 37402-2801

Ann Harris

341 Swing Loop

Rockwood, TN 37854

James H. Bassham, Director

Tennessee Emergency Management

Agency

Electronic Mail Distribution

Distribution w/encl: (See page 4)

4

Letter to Karl W. Singer from Malcolm T. Widmann dated January 30, 2007

SUBJECT:

SEQUOYAH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT

05000327/2006005, 05000328/2006005 AND 07200034/2006002

Distribution w/encl:

Bob Pascarelli, NRR

D. Pickett, NRR

C. Evans, RII

L. Slack, RII EICS

OE Mail

RIDSNRRDIRS

PUBLIC

TABLE OF CONTENTS

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1R01

Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1R02

Evaluations of Changes, Tests or Experiments . . . . . . . . . . . . . . . . . . . . . . . . . 4

1R04

Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1R05

Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1R07

Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1R08

Inservice Inspection (ISI) Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R11

Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

1R12

Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

1R13

Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 12

1R15

Operability Evaluations

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1R17

Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

1R19

Post-Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

1R20

Refueling and Other Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

1R22

Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

1EP6

Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

2OS1 Access Control To Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 20

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

4OA2 Identification & Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

4OA6 Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

4OA7 Licensee Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

ATTACHMENT: SUPPLEMENTARY INFORMATION

Key Points of Contact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

List of Items Opened, Closed, and Discussed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

List of Documents Reviewed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3

List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-14

Enclosure

U. S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos:

50-327, 50-328,72-034

License Nos:

DPR-77, DPR-79

Report No:

05000327/2006005 and 05000328/2006005 and

07200034/2006002

Licensee:

Tennessee Valley Authority (TVA)

Facility:

Sequoyah Nuclear Plant

Location:

Sequoyah Access Road

Soddy-Daisy, TN 37379

Dates:

October 1, 2006 - December 31, 2006

Inspectors:

J. Baptist, Acting Senior Resident Inspector

J. Diaz-Velez, Health Physicist (Section 2OS1)

F. Ehrhardt, Operations Engineer (Section 1R11.2)

L. Lake, Reactor Inspector (Section 1R08)

G. Laska, Senior Operations Examiner (Section 1R11.3)

D. Mas-Penaranda, Reactor Inspector (Sections 1R02, 1R17)

E. Michel, Reactor Inspector (Section 4OA5.3)

B. Miller, Reactor Inspector (Sections 1R08, 4OA5.2)

R. Moore, Senior Reactor Inspector (Section 4OA5.3)

S. Rose, Senior Operations Engineer (Section 1R11.3)

C. Smith Senior Reactor Inspector (Sections 1R02, 1R17)

M. Speck, Resident Inspector

C. Stancil, Resident Inspector (Section 1EP6)

Approved by:

M. Widmann, Chief

Reactor Projects Branch 6

Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000327/2006005, IR 05000328/2006005; IR 07200034/2006002; 10/01/2006 -

12/31/2006; Sequoyah Nuclear Plant, Units 1 & 2; Licensed Operator Requalification

Program.

The report covered a three-month period of inspection by resident inspectors and

announced inspections by 10 regional inspectors and one resident inspector from

another site. One NRC-identified Green finding, which was also a non-cited violation,

was 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 NRC's

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.

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green. The inspectors identified a Green, non-cited violation (NCV) of 10 CFR 55.53,

Conditions of Licenses for failure to certify the qualifications and status of licensed

operators were current and valid prior to their resumption of license duties. Specific

aspects of the requalification program that were not valid included plant tours that were

not completed with another licensed operator and not completing all shift functions in

positions to which the individuals will be assigned. The licensee entered the finding into

the corrective action program as PER No.112004.

The finding is greater than minor because it is associated with the human performance

attribute of the Mitigating Systems Cornerstone that affects the cornerstone objective of

ensuring the availability, reliability, and capability of operators to respond to initiating

events to prevent undesirable consequences that could pose a potential risk to

operations. The finding was evaluated using the Operator Requalification Human

Performance Significance Determination Process. Under this SDP, record deficiencies

can be either minor or of very low safety significance (Green). This finding was

determined to be Green because it was related to the program for maintaining active

licenses and more than 20% of the records reviewed had deficiencies. (Section 1R11.3).

B.

Licensee-Identified Violations

A violation of very low safety significance, which was identified by the licensee, was

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

been entered into the licensees corrective action program. This violation and corrective

action are listed in Section 4OA7.

Enclosure

REPORT DETAILS

Summary of Plant Status:

Unit 1 operated at or near 100% rated thermal power (RTP) for the duration of the

reporting period.

Unit 2 operated at or near 100% RTP until November 27, 2006 when it shut down for a

refueling outage. Unit 2 achieved criticality on December 24, 2006, and reached 100%

RTP on December 29, 2006, where it remained for the duration of the reporting period.

1.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01

Adverse Weather Protection

a.

Inspection Scope

The inspectors reviewed design features and licensee preparations for protecting the

essential raw cooling water (ERCW) intake structure and both Unit 1 and 2 refueling

water storage tanks (RWSTs) from extreme cold and freezing conditions. The

inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), and Technical

Specifications (TS), reviewed and observed implementation of licensee freeze protection

procedures, and walked down portions of the systems to assess the status of system

deficiencies and the system readiness for extreme cold weather. Inspectors performed

corrective action program keyword searches to verify deficiencies were being identified

at an appropriate level and that actions were taken to correct problems. Documents

reviewed are listed in the Attachment to this report.

b.

Findings

No findings of significance were identified.

1R02

Evaluations of Changes, Tests or Experiments

a.

Inspection Scope

The inspectors reviewed selected samples of 10 CFR 50.59 evaluations to verify that

the licensee had appropriately considered the conditions under which changes to the

facility, Updated Final Safety Analysis Report (UFSAR), or procedures may be made,

and tests conducted, without prior NRC approval. The inspectors reviewed ten

evaluations completed for changes made by the licensee without prior NRC approval.

The inspectors also reviewed documents prepared in connection with the changes.

Documents reviewed included supporting analyses, the UFSAR, and drawings to verify

that the licensee had correctly concluded that the changes could be made without

obtaining a license amendment. The ten evaluations reviewed are listed in the

Attachment to this report.

4

Enclosure

Additionally, the inspectors reviewed samples of changes for which the licensee had

determined that evaluations were not required. The reviews were performed to verify

that the licensees conclusions to screen out these changes were correct, and the

changes were made in compliance with the requirements of 10 CFR 50.59. The sixteen

screened out changes reviewed are listed in the Attachment to this report.

The inspectors also reviewed selected problem evaluation reports (PERs) to verify that

plant problems were evaluated for root/apparent causes; extent of condition; and that

the developed corrective actions were adequate to ensure recurrence control of the

identified plant problem.

b.

Findings

No findings of significance were identified.

1R04

Equipment Alignment

a.

Inspection Scope

Partial System Walkdowns. The inspectors performed a partial walkdown of the

following three systems to verify the operability of redundant or diverse trains and

components when safety equipment was inoperable. The inspectors attempted to

identify any discrepancies that could impact the function of the system, and, therefore,

potentially increase risk. The inspectors reviewed applicable operating procedures,

walked down control system components and verified that selected breakers, valves,

and support equipment were in the correct position to support system operation. The

inspectors also verified that the licensee had properly identified and resolved equipment

alignment problems that could cause initiating events or impact the capability of

mitigating systems or barriers and entered them into the corrective action program.

Documents reviewed are listed in the Attachment to this report.

Residual Heat Removal (RHR) Train 2B during maintenance on Train 2A

Emergency Diesels 1A, 1B, and 2A during diesel 2B Outage

Unit 2 Spent Fuel Pool Cooling during full core offload

b.

Findings

No findings of significance were identified.

1R05

Fire Protection

a.

Inspection Scope

The inspectors conducted a tour of the eight areas listed below to assess the material

condition and operational status of fire protection features. The inspectors verified that

combustibles and ignition sources were controlled in accordance with the licensees

administrative procedures, fire detection and suppression equipment was available for

use; that passive fire barriers were maintained in good material condition; and that

compensatory measures for out-of-service, degraded, or inoperable fire protection

5

Enclosure

equipment were implemented in accordance with the licensees fire plan. Documents

reviewed are listed in the Attachment to this report.

Control Building Elevation 669 (Mechanical Equipment Room, 250-VDC Battery

and Battery Board Rooms)

Control Building Elevation 706 (Cable Spreading Room)

Control Building Elevation 685 (Auxiliary Instrument Rooms)

Auxiliary Building Elevation 690 (Corridor)

Emergency Diesel Generator Building

Control Building Elevation 732 (Mechanical Equipment Room and Relay Room)

Auxiliary Building Elevation 714 (Corridor)

Unit 2 Residual Heat Removal/Containment Spray Heat Exchanger Rooms

The inspectors observed the performance of the site fire brigade during unannounced

drills on March 29, 2006, and September 30, 23006, and reviewed the drill critique

report for an unannounced drill on October 3, 2006, to evaluate the readiness of the fire

brigade to fight fires and to assess the drill against the requirements of the Sequoyah

Nuclear Plant Fire Protection Report, Revision 17. The observed drills simulated fires at

the 480-volt Reactor Motor Operated Valve Board 1B1-B and the Motor-driven Auxiliary

Feedwater Pump 2A-A. The reviewed drill critique was for fire brigade response to a fire

alarm report from the Unit 1 RWST. Specifically, the inspectors reviewed the following

aspects of the drills: use of protective clothing, use of breathing apparatus, proper use

of fire hoses, control of the drill scenario, and recurrence of identified deficiencies.

b.

Findings

No findings of significance were identified.

1R07

Heat Sink Performance

a.

Inspection Scope

The inspectors observed performance and reviewed the results of the following activity

to verify the heat exchangers readiness and availability. Inspectors interviewed

maintenance and testing personnel and the system engineer, reviewed corrective action

program documents, previous heat exchanger flow rate data, and inspected the heat

exchanger internals for cleanliness. Inspectors also walked down the system while in

operation looking for evidence of leaks following system restoration. Documents

reviewed are listed in the Attachment to this report.

WO 06-777564-000, Open 2B Containment Spray Heat Exchanger for Eddy

Current Inspection

b.

Findings

No findings of significance were identified.

6

Enclosure

1R08

Inservice Inspection (ISI) Activities (71111.08)

.1

Piping and Pressure Boundary Systems ISI

a.

Inspection Scope

From December 4 - December 8, 2006, the inspectors observed and reviewed the

licensees implementation of their ISI program for monitoring degradation of the reactor

coolant system (RCS) boundary and other risk significant piping system boundaries for

Unit 2. The inspectors observed and reviewed a sample of American Society of

Mechanical Engineers (ASME),Section XI, Section III, and Risk Informed ISI required

examinations, in order of risk priority, as identified in Section 71111.08-03 of inspection

procedure 71111.08, Inservice Inspection Activities based upon the ISI activities

available for review during the onsite inspection period.

The inspectors conducted an on-site review of nondestructive examination (NDE)

activities to evaluate compliance with TSs and the applicable editions of ASME Section

V and Section XI to verify that indications and defects (if present) were appropriately

evaluated and dispositioned in accordance with the requirements of ASME Section XI

acceptance standards.

The inspectors observed the following examinations:

Manual Ultrasonic Examination:

13SIF-142

Visual (VT3) examination of the following Hangers:

2-CVCH-004

2-CVCH-007

2-CVCH-010

2-CVCH-037

Qualification and certification records for examiners, inspection equipment, and

consumables along with the applicable NDE procedures for the above ISI examination

activities were reviewed and compared to requirements stated in ASME Section V and

Section XI.

The inspectors observed in-process welding activities for the following ASME pressure

boundary locations. Inspectors reviewed quality records for welding procedures,

procedure qualification, welder qualification, and filler metal certification.

The inspectors observed a sample of in-process weld-overlay activities for the following

Pressurizer nozzles:

Pressurizer Spray Nozzle

Pressurizer Surge Nozzle

7

Enclosure

b.

Findings

No findings of significance were identified.

.2

Reactor Vessel Upper Head Penetrations

The inspectors completed TI2515/150, Reactor Pressure Vessel Head and Head

Penetration Nozzles (NRC Order EA-03009) (Unit2), this outage. See Section 4OA5.2.

.3

Boric Acid Corrosion Control (BACC) ISI

a.

Inspection Scope

The inspectors reviewed the licensees BACC activities to ensure implementation with

commitments made in response to NRC Generic Letter 88-05 Boric Acid Corrosion of

Carbon Steel Reactor Pressure Boundary and Bulletin 2002-01 Reactor Pressure

Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity.

The inspectors conducted an on-site record review as well as an independent walkdown

of parts of the reactor building that are not normally accessible during at-power

operations to evaluate compliance with licensee BACC program requirements. In

particular, the inspectors assessed whether the visual examinations focused on

locations where boric acid leaks can cause degradation of safety significant components

and that degraded or non-conforming conditions were properly identified in the

licensees corrective action program.

The inspectors reviewed a sample of engineering evaluations completed for boric acid

found on reactor coolant system piping and components. The inspectors also reviewed

licensee corrective actions implemented for evidence of boric acid leakage to confirm

that they were consistent with requirements of Section XI of the ASME Code and 10 CFR 50 Appendix B Criterion XVI.

b.

Findings

No findings of significance were identified.

.4

Steam Generator ISI

a.

Inspection Scope

From December 11-15, 2006, the inspectors reviewed the Unit 2 Steam Generator (SG)

tube eddy current testing (ECT) examination activities to ensure compliance with TSs,

applicable industry operating experience and technical guidance documents, and ASME

Code Section XI requirements.

The inspectors reviewed licensee SG inspection activities to ensure that ECT

inspections were conducted in accordance with the licensees SG Program and

applicable industry standards. The inspectors reviewed the SG examination scope,

8

Enclosure

ECT acquisition procedures, Examination Technique Specification Sheets (ETSS), ECT

analysis guidelines, the most recent SG degradation assessment and operational

assessment, and also the condition monitoring results as they became available. The

inspectors reviewed documentation to ensure that the ECT probes and equipment

configurations used were qualified to detect the expected types of SG tube degradation.

The inspectors ensured that all tubes evaluated in condition monitoring were

appropriately screened for in-situ testing. No tubes met the criteria for in-situ testing. In

addition, the inspectors ensured that the licensee had appropriately implemented the

NRC-approved Alternate Repair Criteria (ARC) applicable to tubes that experienced

outer diameter stress corrosion cracking (ODSCC) at tube support plates.

The inspectors monitored the licensees secondary side activities, which included a

foreign object search and recovery (FOSAR) for loose parts, and sludge lancing. As

part of an industry commitment, the licensee was required to remove a tube from

service for destructive testing. The inspectors monitored this evolution to ensure there

was no damage to other tubes or other parts of the SG.

b.

Findings

No findings of significance were identified.

.5

Identification and Resolution of Problems

a.

Inspection Scope

The inspectors performed a review of piping system ISI related problems that were

identified by the licensee and entered into the corrective action program. The inspectors

reviewed corrective action documents to confirm that the licensee had appropriately

described the scope of the problems. Additionally, the inspectors review included

confirmation that the licensee had an appropriate threshold for identifying issues and

had implemented effective corrective actions. The inspectors evaluated the threshold

for identifying issues through interviews with licensee staff and review of licensee

actions to incorporate lessons learned from industry issues related to the ISI program.

The inspectors performed these reviews to ensure compliance with 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action

documents reviewed by the inspectors are listed in the Attachment to this report.

b.

Findings

No findings of significance were identified.

9

Enclosure

1R11

Licensed Operator Requalification Program

.1

Quarterly Inspection

a.

Inspection Scope

The inspectors observed licensed operator requalification simulator testing on October

24, 2006. The testing involved a failed impulse pressure transmitter failure followed by

loss of condenser vacuum and automatic turbine trip. The reactor failed to automatically

trip and resulted in an anticipated transient without scram (ATWS). The ATWS was

compounded by the inability to trip the reactor from the Main Control Room, auxiliary

feedwater control valves failed to operate automatically for Steam Generators Number 1

and 2, and the Turbine Driven Auxiliary Feedwater Pump (TDAFP) was unable to supply

feedwater, all of which required operator action. As plant conditions were being

stabilized, a pressurizer power operated relief valve (PORV) failed open and required

operators to shut its blocking valve.

The inspectors observed crew performance in terms of communications; ability to take

timely and proper actions; prioritizing, interpreting and verifying alarms; correct use and

implementation of procedures, including the alarm response procedures and emergency

plan event classification; timely control board operation and manipulation, including high

risk operator actions; oversight and direction provided by shift manager, including the

ability to identify and implement appropriate TS actions; independent event classification

by the Shift Technical Advisor; and group dynamics involved in crew performance. The

inspectors also observed the examining staffs assessment of the crews performance

and compared them to inspector observations. Documents reviewed are listed in the

Attachment to this report.

b.

Findings

No findings of significance were identified.

.2

Annual Review of Licensee Requalification Examination Results

a.

Inspection Scope

On November 17, 2006, the licensee completed the comprehensive requalification

biennial written examinations and annual operating tests required to be given to all

licensed operators by 10 CFR 55.59(a)(2). The inspectors performed an in-office review

of the overall pass/fail results of the written examinations, individual operating tests, and

the crew simulator operating tests. These results were compared to the thresholds

established in Manual Chapter 609 Appendix I, Operator Requalification Human

Performance Significance Determination Process.

b.

Findings

No findings of significance were identified.

10

Enclosure

.3

Licensed Operator Requalification Program - Biennial Review

a.

Inspection Scope

The inspectors reviewed facility operating history and associated documents in

preparation for this inspection. While onsite the inspectors reviewed documentation,

interviewed licensee personnel, and observed the administration of operating tests and

written examinations associated with the licensees operator requalification program.

Each of the activities performed by the inspectors was done to assess the effectiveness

of the licensee in implementing requalification requirements identified in 10 CFR 55,

Operators Licenses. The evaluations were also performed to determine if the licensee

effectively implemented operator requalification guidelines established in NUREG 1021,

Operator Licensing Examination Standards for Power Reactors, and Inspection

Procedure 71111.11, Licensed Operator Requalification Program. The inspectors also

evaluated the licensees simulation facility for adequacy for use in operator licensing

examinations using ANSI/ANS-3.5-1985, American National Standard for Nuclear

Power Plant Simulators for use in Operator Training and Examination. The inspectors

observed two crews during the performance of the operating tests. Documentation

reviewed included written examinations, job performance measures, simulator

scenarios, licensee procedures, on-shift records, licensed operator qualification records,

watchstanding and medical records, simulator modification request records and

performance test records, the feedback process, and remediation plans. Documents

reviewed during the inspection are listed in the Attachment to this report.

b.

Findings

Introduction: A Green NCV was identified for failure to certify that the qualifications and

status of licensed operators were current and valid prior to their resumption of license

duties. The applicable requirements of 10 CFR 55.53, Conditions of Licenses for

license reactivation were not met. Specific aspects of the requalification program that

were not valid included plant tours that were not completed with another licensed

operator and not completing all shift functions in the position to which the individual will

be assigned.

Description: The inspectors identified problems with several aspects of the reactivation

process for licensed operators who had been reactivated between October 1, 2004 and

September 30, 2006. The inspectors performed a detailed review for 5 of the 15

individuals who had licenses reactivated during this time period.

The inspectors identified that complete tours of the plant were not being conducted in

accordance with OPDP-1 Operations Department Procedure, Revision 6 and 10 CFR 55.53 requirements. Some individuals reactivating their licenses were performing the

required plant tours without being accompanied by another licensed individual. The

inspectors also identified that some individuals reactivating their licenses had

documented standing watch in non-TS positions, i.e., those positions that TSs do not

require a licensed operator to fill. 10 CFR 55.53, requires that an authorized

representative of the facility certify that individuals reactivating their license must

complete a minimum of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of shift functions in the position to which the individual

11

Enclosure

will be assigned and under the direction of a reactor operator or senior reactor operator

as appropriate. The 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> shall also include a complete tour of the plant.

The inspectors noted that the licensee performed a self assessment of the licensed

operator requalification program on September 11-26, 2006. The assessment identified

problems in several different areas related to operator license reactivation and

maintenance of active license process. Specifically, one licensed operators reactivation

documents could not be located, two licensed operators were returned to active status

without all required training completed, and one inactive licensed operator assumed

licensed duties without being reactivated.

Analysis: The inspectors determined that the licensees failure to properly certify and

maintain the reactivation records of licensed operators and the failure to perform plant

tours with another licensed operator and complete shift functions in the position to which

the individual will be assigned is a performance deficiency because the licensee must

satisfy the requirements of 10 CFR 55.53 for license reactivation.

The finding is more than minor because it is associated with the human performance

attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone

objective of ensuring the availability, reliability, and capability of operators to response to

initiating events to prevent undesirable consequences. The failure to properly reactivate

the licenses of operators could adversely impact their performance. The finding was

evaluated using the Operator Requalification Human Performance Significance

Determination Process. Under this SDP, record deficiencies can be either minor or of

very low safety significance (Green). This finding was determined to be Green because

it was related to the program for maintaining active licenses and more than 20% of the

records reviewed had deficiencies.

Enforcement: 10 CFR 55.53.(f) Conditions of Licenses requires, in part, that an

authorized representative of the facility licensee shall certify that qualifications and

status of operator licensees are current and valid prior to the resumption of license

duties. Included in the certification required by 10 CRF 55.53 is that the individual

complete a minimum of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of shift functions in the position to be assigned and

also complete a plant tour while accompanied by a licensed operator. Contrary to the

above, the licensee did not properly certify that qualifications and status were current

and valid prior to allowing operators to perform licensed duties.

The failure to properly reactivate licensed operators was determined to be of very low

safety significance (Green) and has been entered into the licensees corrective action

program as PER No.112004. The finding is being treated as an NCV consistent with

Section VI.A of the NRC Enforcement Policy: NCV 05000327,328/2006005-01, Failure

to certify qualifications and status of licensed operators were current and valid in

accordance with 10CFR 55.53.

12

Enclosure

1R12

Maintenance Effectiveness

a.

Inspection Scope

The inspectors reviewed the following three maintenance activities to verify the

effectiveness of the activities in terms of: 1) appropriate work practices; 2) identifying

and addressing common cause failures; 3) scoping in accordance with 10 CFR 50.65

(b); 4) characterizing reliability issues for performance; 5) trending key parameters for

condition monitoring; 6) charging unavailability for performance; 7) classification in

accordance with 10 CFR 50.65(a)(1) or (a)(2); 8) appropriateness of performance

criteria for Systems, Structures, and Components (SSCs) and functions classified as

(a)(2); and 9) appropriateness of goals and corrective actions for SSCs and functions

classified as (a)(1). Documents reviewed are listed in the Attachment to this report.

PER 115421, B-B Main Control Room Ventilation

PER 115780, 2B Residual Heat Removal HX Outlet Valve 74-28 Failure

PER 85481, Repeated Packing Leaks of Safety Injection (SI) Valve 2-FCV-63-156

b.

Findings

No findings of significance were identified.

1R13

Maintenance Risk Assessments and Emergent Work Control

a.

Inspection Scope

The inspectors reviewed the following six activities to verify that the appropriate risk

assessments were performed prior to removing equipment from service for

maintenance. The inspectors verified that risk assessments were performed as

required by 10 CFR 50.65 (a)(4), and were accurate and complete. When emergent

work was performed, the inspectors verified that the plant risk was promptly reassessed

and managed. The inspectors verified the appropriate use of the licensees risk

assessment tool and risk categories in accordance with Procedure SPP-7.1, On-Line

Work Management, Revision 8, and Instruction 0-TI-DSM-000-007.1, Risk Assessment

Guidelines, Revision 8. Documents reviewed are listed in the Attachment to this report.

Unit 2 ECCS Train A Room Cooler Outage

Unplanned EDG 2B Inoperability

2-SI-OPS-082-26A, Loss of Offsite Power with SI - DG 2A-A Test, Revision 35

ORAM Orange risk condition from Unit 2 midloop activities prior to vacuum refill

Franklin 500KV line tripped resulting in Technical Specification 3.8.1.1 entry

Unit 2 initial RCS level drain to partial draindown condition

b.

Findings

No findings of significance were identified.

13

Enclosure

1R15

Operability Evaluations

a.

Inspection Scope

For the five operability evaluations described in the PERs listed below, the inspectors

evaluated the technical adequacy of the evaluations to ensure that TS operability was

properly justified and the subject component or system remained available, such that no

unrecognized increase in risk occurred. The inspectors reviewed the UFSAR to verify

that the system or component remained available to perform its intended function. In

addition, the inspectors reviewed compensatory measures implemented to verify that

the compensatory measures worked as stated and the measures were adequately

controlled. The inspectors also reviewed a sampling of PERs to verify that the licensee

was identifying and correcting any deficiencies associated with operability evaluations.

Documents reviewed are listed in the Attachment to this report.

PER 111814, Train A MCR Air-Conditioning System Air Flow Greater Than

Acceptance Criteria

PERs 114769, 114941, Emergency Diesel Generator 2B Feeder Breaker Failed

to Close When Required

PER 109326, ERCW Screen Wash Pump B-B Failed Pump Performance Test

PER 115490, Charging Pump Discharge Manual Isolation Valve Appendix R

Operability

PER 117113, Unit 1 Steam Generator Levels Exhibited Lowering Trend

b.

Findings

No findings of significance were identified. An unresolved item (URI) is discussed

below.

Inability to Perform Actions Required by AOP-N.08, Appendix R Fire Safe Shutdown

Introduction: The inspectors identified an Unresolved Item (URI) for not promptly

identifying and correcting problems associated with manual valve 2-62-527. These

problems resulted in operators not being able to comply with licensee procedure AOP-

N.08, Appendix R Fire Safe Shutdown due to manual valve 2-62-527 not being able to

be closed within the 13 minutes required.

Description: On October 28, 2005, a procedure change to AOP-N.08, Appendix R Fire

Safe Shutdown, was implemented. This change incorporated updated guidance

provided by a Westinghouse technical bulletin (TB -04-022) concerning RCP seal

performance during Appendix R fires and a loss of all pump seal cooling. This change

reduced the time available to perform manual actions and restore RCP seal flow from 24

minutes to 13 minutes. In the event of an Appendix R fire resulting in a spurious safety

injection signal, plant procedures required that all RCS injection sources be stopped to

prevent filling the pressurizer solid. The vendor guidance stated that actions taken to

prevent this condition and restore RCP seal flow should be completed within 13 minutes

to prevent seal damage. The actions outlined by AOP-N.08 required an auxiliary unit

operator (AUO) to manipulate several valves in the appropriate Charging Pump room

14

Enclosure

and then a CCP restarted to restore seal flow. Specifically, the AUO was to open a

dedicated flow path to the RCP seals using manual valve 62-526 (A-train), or 62-534 (B-

train) and close the associated CCP manual discharge valve,62-527 (A-train) or 62-533

(B-train) to the CCP Injection Tank (CCPIT). To support the procedure change, these

manipulations were subjected to a manual action validation that consisted of a table top

review of the necessary steps. The licensee determined that the CCP manual

discharge valves to the CCPIT could be closed by an individual AUO in 5 minutes and

20 seconds.

Prior to the procedure being approved, PER 91383 was written on October 24, 2005.

The PER addressed concerns by at least one plant AUO that the manual actions

required by the change to procedure AOP-N.08 may not be able to be completed within

the time required. PER 91383 requested the need to further evaluate the time

necessary to perform the manual actions by actual valve manipulations, or whether

additional procedure changes were needed to provide more margin to the required time.

The corrective action planned was to perform a timed valve stroke of CCP discharge

valve 2-62-527 to validate procedural change assumptions. Work Order (WO) 06-

771729-000 was written to implement and track this action during an appropriate CCP

maintenance period. PER 91383 was closed as completed on February 24, 2006 based

on the WO being written. On November 9, 2006, during a self-assessment, the licensee

determined that the WO had not been completed and was not scheduled for

performance until January 22, 2007. PER 114455 was written to document the

incomplete corrective action. Upon review of PER 114455, the inspectors questioned

the licensee on the valves history, the status of corrective actions, and whether a valid

safety concern existed if the valve could not be operated within the prescribed time.

Prior to resolution by the licensee, on November 27, 2006, during Unit 2 refueling

outage activities, operators closed valve 2-62-527 to support maintenance. The

operators reported that the valve was very difficult to operate and required

approximately 30 minutes for two AUOs to shut the valve. This observation was

documented in in PER 115490 and supported the initial concern expressed in PER

91383.

This information prompted the license to evaluate the consequences of the additional

time needed to operate valve 2-62-527 with plant Appendix R procedures. Functional

Evaluation (FE) 41722 was drafted and the licensee determined that RCP seal

degradation would not occur if RCP seal flow was restored with a CCP prior to

completing of the Appendix R Fire safe shutdown manual actions The licensee also

evaluated whether the same problems were likely for other Appendix R manual valves. .

The licensee drafted a document to support the determination that other valves in both

units could be operated in adequate time in the event of an Appendix R fire.

Analysis: The inspectors determined that the delay in implementing the WO resulted in

not promptly identifying and correcting problems with manual valve 2-62-527 resulting in

operators not being able to comply with procedure AOP-N.08, Appendix R Fire Safe

Shutdown. The corrective action for PER 91383 was closed to a WO and rescheduled

several times in the work control process with a performance date of January 22, 2007.

The inspectors referenced Inspection Manual Chapter (IMC) 0612 and determined the

finding is more than minor because if left uncorrected, the licensee would not be able to

15

Enclosure

comply with AOP-N.08. The finding is associated with the mitigating system

cornerstone and could be reasonably viewed as affecting the cornerstone objective to

ensure the availability, reliability, and capability of systems that respond to initiating

events to prevent undesirable consequences. This finding is unresolved pending the

review of supporting documentation and completion of the significance determination.

Enforcement: Pending additional information involving the circumstances surrounding

the event, its extent of condition and completion of the significance determination, this

finding is identified as URI 05000328/2006005-02, Inability to Perform Required Actions

of AOP-N.08, Appendix R Fire Safe Shutdown.

1R17

Permanent Plant Modifications

a.

Inspection Scope

The inspectors performed independent design reviews of six plant modifications in the

Initiating Events, Mitigating Systems, and Barrier Integrity cornerstone areas, to verify

that the plant modifications did not have any adverse effects on system availability,

reliability, and functional capability. Documents reviewed included procedures,

engineering calculations, modification design and implementation packages, work

orders, Condition Reports (CRs), applicable sections of the UFSAR, TSs, and design

basis information. The plant modifications and the associated attributes reviewed are as

follows:

DCN D22050, Pressurizer Relief Tank Level Transmitter Removed (Barrier Integrity)

Control Signal

Energy Needs

Process Medium

Update of Licensee Documents

DCN D21781, Change Steam Generator Narrow Range Level Transmitter Scaling

(Mitigating System)

Control Signal

Energy Needs

Process Medium

Update of Licensee Documents

Operations

DCN D21911, Replace Containment Isolation Valve 2-FCV-030-0014(Barrier Integrity)

Pressure Boundary

Structural

Process Medium

Update of Licensee Documents

Materials/Replacement Components

DCN 21900, Replace Unit 1B Main Bank Transformer and Associated Fire Protection

Ring Header, Revision A.(Initiating Event)

Energy Needs

Control Signals

Post-Installation Testing

16

Enclosure

Update of Licensee Documents

Functional Testing Adequacy and Results

DCN D21971, Replace Cable PP351A for D/G 1A-A, Revision A. (Mitigating Systems)

Materials/ Replacement

Failure Modes

Post-Installation Testing

Update of Licensee Documents

Functional Testing Adequacy and Results

DCN D21827, Revise Setting on Raw Cooling Water Pump Breaker, Revision A.

Control Signals

Response Time

Post-Insulation Testing

Update of Licensee Documents

Functional Testing Adequacy and Results

The inspectors also performed field inspections of selected plant modifications to verify

that the as-built installation complied with design requirements delineated in approved

design documents. Additionally, the inspectors reviewed selected PERs to verify that

plant problems were evaluated for root/apparent causes, extent of condition, and that

the developed corrective actions were adequate to ensure recurrence control of the

identified plant problem.

b.

Findings

No findings of significance were identified.

1R19

Post-Maintenance Testing

a.

Inspection Scope

The inspectors reviewed the five post-maintenance tests listed below to verify that

procedures and test activities ensured system operability and functional capability. The

inspectors reviewed the licensees test procedure to verify that the procedure

adequately tested the safety function(s) that may have been affected by the

maintenance activity, that the acceptance criteria in the procedure were consistent with

information in the applicable licensing basis and/or design basis documents, and that

the procedure had been properly reviewed and approved. The inspectors also

witnessed the test or reviewed the test data, to verify that test results adequately

demonstrated restoration of the affected safety function(s). Documents reviewed are

listed in the Attachment to this report.

WO 05-782379-000, Breaker Changeout for Motor-driven Auxiliary Feedwater

(AFW) Pump 2B

2-SI-OPS-000-009.0, Actuation of Emergency Core Cooling Systems (ECCS)

and Boron Injection Flowpath Valves Via SI Signal, Revision 1

WO 05-777912-001, Repack SI system Hot Leg Injection Valve, 2-FCV-63-156

17

Enclosure

WO 06-780773-000, Calibrate FCV and Limit Switches on 2-FCV-074-28

2-SI-SLT-088-156.0, Containment Integrated Leak Rate Test, Revision 2

b.

Findings

No findings of significance were identified.

1R20

Refueling and Other Outage Activities

a.

Inspection Scope

For the Unit 2 refueling outage that began on November 27, 2006, the inspectors

evaluated licensee activities to verify that the licensee considered risk in developing

outage schedules, followed risk reduction methods developed to control plant

configuration, developed mitigation strategies for the loss of key safety functions, and

adhered to operating license and TS requirements that ensure defense-in-depth. The

inspectors also walked down portions of Unit 2 not normally accessible during at-power

operations to verify that safety-related and risk-significant SSCs were maintained in an

operable condition. Specifically, between November 27, 2006, and December 26, 2006,

the inspectors performed inspections and reviews of the following outage activities.

Documents reviewed are listed in the Attachment to this report.

Outage Plan. The inspectors reviewed the outage safety plan and contingency

plans to confirm that the licensee had appropriately considered risk, industry

experience, and previous site-specific problems in developing and implementing

a plan that assured maintenance of defense-in-depth.

Reactor Shutdown. The inspectors observed the shutdown in the control room

from the time the reactor was tripped until operators placed it on the RHR

system for decay heat removal to verify that TS cooldown restrictions were

followed. The inspectors also toured the lower containment as soon as

practicable after reactor shutdown to observe the general condition of the RCS

and emergency core cooling system components and to look for indications of

previously unidentified leakage inside the polar crane wall.

Licensee Control of Outage Activities. On a daily basis, the inspectors attended

the licensee outage turnover meeting, reviewed PERs, and reviewed the

defense-in-depth status sheets to verify that status control was commensurate

with the outage safety plan and in compliance with the applicable TS when

taking equipment out-of-service. The inspectors further toured the main control

room and areas of the plant daily to ensure that the following key safety

functions were maintained in accordance with the outage safety plan and TS:

electrical power, decay heat removal, spent fuel cooling, inventory control,

reactivity control, and containment closure. The inspectors also observed a

tagout of the containment spray heat exchanger to verify that the equipment was

appropriately configured to safely support the work or testing. To ensure that

RCS level instrumentation was properly installed and configured to give accurate

information, the inspectors reviewed the installation of the Mansell level

18

Enclosure

monitoring system. Specifically, the inspectors discussed the system with

engineering, walked it down to verify that it was installed in accordance with

procedures and adequately protected from inadvertent damage, verified that

Mansell indication properly overlapped with pressurizer level instruments during

pressurizer draindown, verified that operators properly set level alarms to

procedurally required setpoints, and verified that the system consistently tracked

while lowering RCS level to reduced inventory conditions. The inspectors also

observed operators compare the Mansell indications with locally-installed

ultrasonic level indicators during entry into mid-loop conditions.

Refueling Activities. The inspectors observed fuel movement at the spent fuel

pool and at the refueling cavity in order to verify compliance with TS and that

each assembly was properly tracked from core offload to core reload. In order to

verify proper licensee control of foreign material, the inspectors verified that

personnel were properly checked before entering any foreign material exclusion

(FME) areas, reviewed FME procedures, and verified that the licensee followed

the procedures. To ensure that fuel assemblies were loaded in the core

locations specified by the design, the inspectors independently reviewed the

recording of the licensees final core verification.

Reduced Inventory and Mid-Loop Conditions. Prior to the outage, the inspectors

reviewed the licensees commitments to Generic 88-17, Loss of Decay Heat

Removal. Before entering reduced inventory conditions the inspectors verified

that these commitments were in place, that plant configuration was in

accordance with those commitments, and that distractions from unexpected

conditions or emergent work did not affect operator ability to maintain the

required reactor vessel level. While in mid-loop conditions, the inspectors

verified that licensee procedures for closing the containment upon a loss of

decay heat removal were in effect, that operators were aware of how to

implement the procedures, and that other personnel were available to close

containment penetrations if needed.

Heatup and Startup Activities. The inspectors toured the containment prior to

reactor startup to verify that debris that could affect the performance of the

containment sump had not been left in the containment. The inspectors

reviewed the licensees mode change checklists to verify that appropriate

prerequisites were met prior to changing TS modes. To verify RCS integrity and

containment integrity, the inspectors further reviewed the licensees RCS

leakage calculations and containment isolation valve lineups. In order to verify

that core operating limit parameters were consistent with core design, the

inspectors also reviewed low power physics testing results and the Core

Operating Limits Report.

b.

Findings

No findings of significance were identified.

19

Enclosure

1R22

Surveillance Testing

a.

Inspection Scope

For the seven surveillance tests identified below, by witnessing testing and/or reviewing

the test data, the inspectors verified that the SSCs involved in these tests satisfied the

requirements described in the TS surveillance requirements, the UFSAR, applicable

licensee procedures, and that the tests demonstrated that the SSCs were capable of

performing their intended safety functions. Documents reviewed are listed in the

Attachment to this report. Those tests included the following:

1-SI-MIN-061-108.0, Ice Condenser Intermediate Deck Door Weekly Inspection,

Revision 2

2-SI-ICC-090-106.0, Channel Calibration of Containment Building Lower

Compartment Air Monitor 2-R-90-106, Revision 9***

0-SI-SXV-001-859.0, Testing and Setting of Main Steam Safety Valves, Revision 9

2-SI-OPS-082-026.A, Loss of Offsite Power with SI - DG 2A-A Test, Revision 35

0-SI-MIN-061-109.0, Ice Condenser Intermediate and Lower Inlet Doors and

Vent Curtains, Revision 4*

2-SI-OPS-003-118.0 AFW pump and Valve Auto Actuation, Revision 18

2-SI-SXP-003-003-202.S, Turbine Driven Auxiliary Feedwater Pump 2A-S

Comprehensive Performance Test, Revision 4**

• This procedure included an outage ice condenser system surveillance

• • This procedure included inservice testing requirements

• • • This procedure included a RCS leakage detection surveillance

b.

Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP6

Drill Evaluation

a.

Inspection Scope

Resident inspectors evaluated the conduct of a routine licensee emergency drill on

October 3, 2006, to identify any weaknesses and deficiencies in classification,

notification, and protective action recommendation (PARs) development activities. The

inspectors observed emergency response operations in the simulated control room to

verify that event classification and notifications were done in accordance with EPIP-1,

Emergency Plan Classification Matrix, Revision 38. The inspectors also attended the

licensee critique of the drill to compare any inspector-observed weakness with those

identified by the licensee in order to verify whether the licensee was properly identifying

failures. Documents reviewed are listed in the Attachment to this report.

20

Enclosure

b.

Findings

No findings of significance were identified.

2.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety (OS)

2OS1 Access Control To Radiologically Significant Areas

a.

Inspection Scope

Access Control Licensee program activities for monitoring workers and controlling

access to radiologically significant areas and tasks were inspected. The inspector

evaluated procedural guidance; directly observed implementation of administrative and

established physical controls; assessed worker exposures to radiation and radioactive

material; and appraised radiation worker and technician knowledge of, and proficiency

in, the implementation of Radiation Protection (RP) program activities.

During the inspection, radiological controls for ongoing refueling activities for Unit 2 were

observed and discussed. Reviewed tasks included steam generator non-destructive

testing, containment sump modifications, and refueling activities. In addition, licensee

controls for selected tasks scheduled and on-going during the current refueling outage

were assessed. The evaluations included, as applicable, Radiation Work Permit (RWP)

details; use and placement of dosimetry and air sampling equipment; electronic

dosimeter set-points, and monitoring and assessment of worker dose from direct

radiation and airborne radioactivity source terms. Effectiveness of established controls

was assessed against area radiation and contamination survey results, and

occupational doses received. Physical and administrative controls and their

implementation for locked high radiation areas (LHRAs) and very high radiation areas

were evaluated through discussions with cognizant licensee representatives, direct field

observations, and record reviews.

Occupational workers adherence to selected radiation work permits (RWPs) and Health

Physics Technician proficiency in providing job coverage were evaluated through direct

observations of staff performance during job coverage and routine surveillance

activities, review of selected exposure records, and interviews with cognizant licensee

staff. Radiological postings and physical controls for access to designated high

radiation (HRA) and LHRA locations within the Unit 2 Containment, Auxiliary Building,

and Refuel Floor areas were evaluated during facility tours. In addition, the inspectors

independently measured radiation dose rates and evaluated established posting and

access controls for selected Auxiliary Building locations. Occupational exposures

associated with direct radiation and potential radioactive material intakes for were

reviewed and discussed with cognizant licensee representatives.

RP program activities were evaluated against 10 CFR 19.12; 10 CFR 20, Subparts B, C,

F, G, H, and J; UFSAR details in Section 12, RP; TSs Section 6.11, High Radiation

Area; and approved licensee procedures. Licensee procedures, guidance documents,

21

Enclosure

records, and data reviewed within this inspection area are listed in Section 2OS1 of the

Attachment to this report.

Problem Identification and Resolution Licensee Corrective Action Program documents

associated with access control to radiologically significant areas were reviewed and

assessed. The inspectors evaluated the licensees ability to identify, characterize,

prioritize, and resolve the identified issues in accordance with Standard Programs and

Processes procedure SPP-3.1, Corrective Action Program. Licensee self-assessments

and PER documents related to access control that were reviewed and evaluated in

detail during inspection of this program area are identified in Section 2OS1 of the

Attachment to this report.

The inspector completed 21 of the required 21 samples for Inspection Procedure (IP) 71121.01. All samples have now been completed for this IP.

b.

Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA2 Identification and Resolution of Problems

.1

Daily Review

As required by Inspection Procedure 71152, Identification and Resolution of Problems,

and in order to help identify repetitive equipment failures or specific human performance

issues for follow-up, the inspectors performed a daily screening of items entered into the

licensees corrective action program. This was accomplished by reviewing the

description of each new PER and attending daily management review committee

meetings.

.2

Semi-Annual Trend Review

a.

Inspection Scope

As required by Inspection Procedure 71152, the inspectors performed a review of the

licensees corrective action program and associated documents to identify trends that

could indicate the existence of a more significant safety issue. The inspectors review

was focused on procedure quality and compliance issues, but also included licensee

trending efforts and licensee human performance results. The inspectors review

nominally considered the six-month period of July 2006 through December 2006,

although some examples expanded beyond those dates when the scope of the trend

warranted.

Specifically, the inspectors consolidated the results of daily inspector screening

discussed in Section 4OA2.1 into a log, reviewed the log, and compared it to licensee

integrated quarterly trend reports for the period from July 2006 through September 2006

22

Enclosure

in order to determine the existence of any adverse trends that the licensee may not

have previously identified.

b.

Assessment and Observations

The inspectors identified issues with procedure quality and compliance over the period

of assessment. Noteworthy examples of deficient procedure quality or compliance

were:

PER 114003, Incorrect Procedure Revision used on 6.9kV Shutdown Board relay

testing

PER 115490, Inability to manually operate Appendix R valves within the required

time.

PER 115539, Emergency Gas Treatment System procedure cloning resulting in

failure of Unit 2 Phase A testing requirements.

PER 115534, Loss of RCS inventory during Unit 2 refueling outage Mansell

alignment.

PER 117008, Missed firewatch through plant areas with disabled fire detection.

No findings of significance were identified. In general, the licensee had identified trends

and appropriately communicated them to plant senior management. The inspectors

evaluated the licensee trending methodology and observed that the licensee had

performed a summary review of issues which were inputs to the plant Human

Performance Index. The licensee reviewed cause codes, involved organizations, key

words, and system links to identify potential trends in the data. The inspectors

compared the licensee process results with the results of the inspectors daily

screenings and did not identify any significant discrepancies or potential trends that the

licensee had failed to identify. The specifics surrounding PER 115490, regarding the

inability to manually operate Appendix R valves within the required time, are further

addressed in Section 1R15, Operability Evaluations.

.3

Annual Sample Review of Problems with Plant Venting Operations

a.

Inspection Scope

The inspectors reviewed licensee actions to resolve issues surrounding plant venting

operations. This review began as a look at how the licensee addressed problems

associated with two potentially significant events that had occurred during the venting of

plant systems. These events are common to nuclear plant operations and often are

required in restoration of a system after it has been removed from service or opened for

maintenance. PER 92485 was written on November 21, 2005, and identified that

operators had discovered the collapse of the A Chemical Volume Control System

(CVCS) Holdup Tank (HUT) due to the lack of an adequate vent path during drain down.

The licensee subsequently suspended use of the A CVCS HUT, performed a root

cause analysis, and implemented corrective actions to prevent a recurrence of this

activity. The inspectors reviewed the completion of required actions items spawned

from this event for timeliness, accuracy and adequacy. PER 102591 was written on

May 7, 2006, to address an event during drain down of the RCS to midloop conditions.

While making preparations for vacuum refill of the RCS, the evolution had to be

23

Enclosure

suspended when it was identified that a required reactor vessel head vent path was not

properly aligned. The licensee immediately vented the RCS and verified that the RCS

was not under vacuum conditions based on no observed change in RCS level indication

when the head vent was opened. The licensee declared that the apparent cause of the

event was due to failure to follow procedure, inadequate procedural guidance, and

inadequate scheduling. The event associated with PER 102591 was dispositioned as a

licensee-identified violation in Inspection Report 05000327, 328/2006003. The

inspectors reviewed the PER action items for adequacy and the associated procedures

to ensure changes were implemented to preclude repetition of this event. The

inspectors utilized these examples during the inspection period to observe similar

activities that had the potential to degrade in risk significant systems. The inspectors

were able to observe RCS drain down and refill activities during the Unit 2 Cycle 14

refueling outage, as well as, the venting operations of support systems during

restoration to their normal mode of operation.

b.

Findings and Observations

No findings of significance were identified. The inspectors noted that the licensee

appeared to have an adequate sensitivity to operational experience, procedural

guidance, scheduling conflicts, and foreign material exclusion. The licensee was

successful in properly performing the necessary venting activities associated with the

multiple system drain and refill operations accompanying Unit 2 refueling outage

maintenance.

4OA5 Other Activities

.1

Review of the Operation of an Independent Spent Fuel Storage Installation (ISFSI)

(60855.1)

a.

Inspection Scope

The inspectors reviewed ISFSI document control practices to verify that changes to the

required ISFSI procedures and equipment were performed in accordance with

guidelines established in licensee procedures and 10 CFR 72.48. Documents reviewed

are listed in the Attachment to this report.

b.

Findings

No findings of significance were identified.

.2

(Open) NRC Temporary Instruction 2515/150, Rev. 2, Reactor Pressure Vessel Head

and Vessel Head Penetration Nozzles (NRC Order EA-03-009) - Unit 2

a.

Inspection Scope

From December 4 - 8, 2006, the inspectors reviewed the licensees activities associated

with the NDE of the reactor pressure vessel head (RPVH) penetration nozzles, the bare

metal visual examination of the top surface of the RPVH, and the visual examination to

identify potential boric acid leaks from pressure-retaining components above the RPVH.

24

Enclosure

These activities were performed in response to NRC Bulletins 2001-01, 2002-01, 2002-

02, and the first revision of NRC Order EA-03-009 Modifying Licenses dated February

20, 2004 (hereafter referred to as the NRC Order).

The inspectors review of the NDE of RPVH penetration nozzles included independent

observation and evaluation of ultrasonic testing (UT) examinations (for both data

acquisition and analysis), review of NDE procedures, personnel qualifications and

training, and NDE equipment certifications. The inspectors also held interviews with

contractor representatives (Areva) and other licensee personnel involved with the RPVH

examination. The activities were reviewed to verify licensee compliance with the NRC

Order and to gather information to help the NRC staff identify possible further regulatory

positions and generic communications.

The inspectors reviewed a sample of the results from the volumetric UT examinations of

RPVH penetration nozzles. Specifically, the inspectors reviewed or observed the

following:

Observed in-process UT data acquisition scanning of RPVH penetration nozzles

57 and 52 (both with thermal sleeves)

Reviewed the UT electronic data with the Level III analyst for RPVH nozzles 4,

36, 43, 50, 56, 61, 69, 77, 126 and the calibration block (this included nozzles

both with and without thermal sleeves)

Reviewed the results of the UT examination performed to assess for leakage into

the annulus (interference fit zone) between the RPVH penetration nozzle and the

RPVH low-alloy steel for all penetration numbers listed in the previous bullet

Reviewed the procedures and results for the visual exam performed to identify

potential boric acid leaks from pressure-retaining components above the RPVH

Reviewed the RPVH susceptibility ranking and calculation of effective

degradation years (EDY), including the basis for the RPVH temperature used in

the calculation

b.

Observations and Findings

In accordance with the requirements of TI 2515/150, the inspectors evaluated and

answered the following questions:

1)

Were the examinations performed by qualified and knowledgeable personnel?

Yes. All personnel involved with the RPVH inspections were appropriately qualified in

accordance with the ASME Code, and most far exceeded the minimum requirements for

experience and training hours. The contractor (Areva) personnel responsible for

equipment manipulation, data acquisition, and data analysis frequently perform these

types of inspections nationwide.

25

Enclosure

2)

Were the examinations performed in accordance with demonstrated

procedures?

Yes. The Sequoyah Unit 2 RPVH has 57 control rod drive mechanism (CRDM) nozzles

with thermal sleeves, 13 with open housings (including 5 instrument column nozzles), 8

with part lengths, 4 upper head injection (UHI) nozzles, and 1 vent line nozzle, for a total

of 83 nozzles. All nozzles were subject to remote automated UT examination using one

of two types of probes. The blade probe was used for sleeved penetrations and the

open housing CRDMs using a dummy sleeve. The rotating probe was used for the

other open housing penetrations (UHI and instrument columns). A liquid penetrant

exam on the surface of the J-groove weld of the vent line was also performed to satisfy

the NRC Order.

Procedures 54-ISI-603-002 (UT with thermal sleeves), 54-ISI-604-001 (UT of open

housings), 54-ISI-605-02 (UT of vent line), and 54-ISI-240-44 (liquid penetrant) were

implemented to complete the exams described above. Further, the inspectors verified

that the 54-ISI-603-002 and 54-ISI-604-001 procedures were used during the Areva

demonstration to EPRIs Materials Reliability Program (MRP) to show flaw detection

capability in RPVH penetrations. By letter dated October 3, 2006, from Jack Spanner of

EPRI to Joel Whitaker of TVA (the licensee), EPRI stated that Arevas demonstration of

flaw detection techniques could reliably detect flaws in CRDM penetrations.

3)

Was the examination able to identify, disposition, and resolve deficiencies?

Yes. All indications of cracks or interference fit zone leakage are required to be

reported for further examination and disposition. Based on observation of the

examination process, the inspectors considered deficiencies would be appropriately

identified, dispositioned, and resolved. UT indications associated with the geometry of

the examined volume were identified in several penetration tubes. None of the

indications exhibited crack-like characteristics and were appropriately dispositioned in

accordance with procedures.

4)

Was the examination capable of identifying the primary water stress corrosion

cracking (PWSCC) and/or RPVH corrosion phenomena described in the NRC

Order?

Yes. The NDE techniques employed for the examination of RPVH nozzles had been

previously demonstrated under the EPRI MRP/Inspection Demonstration Program as

capable of detecting PWSCC-type manufactured cracks as well as cracks from actual

samples from another site. Based on the demonstration, observation of in-process

examinations, and review of NDE data, the inspectors determined that the licensee was

capable of identifying PWSCC and/or corrosion as required by the NRC Order.

5)

What was the physical condition of the RPVH (e.g. debris, insulation, dirt, boron

from other sources, physical layout, viewing obstructions)?

The licensee performed a 100% bare metal visual (BMV) inspection of the top of the

RPVH, including 360E around each penetration using a remote visual robotic crawler for

areas inside the lead shielding and underneath the raised insulation package. The

26

Enclosure

surface sloping down from the shielding to the flange was visually inspected directly by a

Level III VT-2 examiner. The inspectors independently reviewed portions of the remote

inspection video which revealed no insulation, dirt, or other general debris that caused

viewing obstructions in the areas of interest. Some small, loose particles of debris were

easily cleared from the surface with a low-pressure air stream mounted on the remote

crawler. The inspectors determined that the physical condition of the head was

adequate to meet the inspection requirements mandated by the NRC Order.

6)

Could small boron deposits, as described in NRC Bulletin 2001-01, be identified

and characterized?

Yes. The BMV examination was determined by the inspectors to be capable of

identifying and characterizing small boron deposits as described in NRC Bulletin 2001-

01. The remote exam was VT-2 qualified and able to resolve, at a minimum, the 0.105-

inch characters on an ASME IWA-2210-1 Visual Illumination Card.

7)

What material deficiencies (i.e., cracks, corrosion, etc.) were identified that

required repair?

There were no identified examples of RPVH penetration cracks, leakage, material

deficiencies, head corrosion, or other flaws that required repair. As discussed

previously, there were some UT indications at J-groove welds that were dispositioned as

metallurgical/geometric indications (not service related). One metallurgical indication on

tube 56 actually extended below the J-groove weld, and the inspector verified that

adequate coverage below this metallurgical indication was obtained. These indications

were likely due to weld repairs performed during initial RPVH fabrication.

8)

What, if any, impediments to effective examinations, for each of the applied

methods, were identified (e.g., centering rings, insulation, thermal sleeves,

instrumentation, nozzle distortion)?

The penetration nozzles with thermal sleeves and centering pads did not impede

effective examination. Concerning examination coverage, the NRC Order requires that

each tubes volume is inspected from a minimum of 2 inches above the highest point of

the J-groove weld to 2 inches below the lowest point of the J-groove weld, or 1 inch with

a stress analysis. The licensee had performed a stress analysis and the inspectors

verified that the minimum examination coverages required by the NRC Order were met.

9)

What was the basis for the temperature used in the susceptibility ranking

calculation?

NRC Order EA-03-009 requires that licensees calculate the EDY of the RPVH to

determine its susceptibility category, which subsequently determines the scope and

frequency of required RPVH examinations. The operating temperature of the RPVH is

an input to this calculation. Therefore, an incorrect temperature input could result in

placing the RPVH in an incorrect susceptibility category. The licensee uses the cold leg

temperature in this calculation.

27

Enclosure

In Supplement No. 1 to the NRCs Safety Evaluation Report (SER) dated February

1980, the NRC concluded that scale model tests provided reasonable assurance that

the upper head would operate at the cold leg temperature. However, the NRC staff also

required that plant data be acquired to confirm the head temperature. This data was

acquired for Unit 1 to satisfy both units because Unit 2 is considered a sister plant. The

inspectors reviewed this data which confirmed that the head operated at approximately

cold leg temperature with some minor thermocouple variations. In addition, both units

underwent a modification since this testing to increase bypass flow to the head from 4%

to about 7%. This gives further assurance that the RPVH operates at cold leg

temperature. For these reasons, the inspectors concluded that the licensee had an

adequate basis for their temperature input to the susceptibility ranking calculation, which

results in Unit 2 being placed in the Low category.

10)

During non-visual examinations, was the disposition of indications consistent with

the NRC flaw evaluation guidance?

There were no indications considered to be flaws found during the RPVH examination.

11)

Did procedures exist to identify potential boric acid leaks from pressure-retaining

components above the RPVH?

Yes. Procedure 0-PI-DXX-068-100.R, Monitoring of Reactor Head Canopy Seal Welds

for Leakage, is implemented every outage and meets the requirements of the NRC

Order. However, inspection of conoseals and other bolted connections above the

RPVH, such as the RVLIS line, are covered under the Boric Acid Program. The

inspectors determined that the program and procedure implementation met the

requirements of the NRC Order, however, the licensee also initiated actions to enhance

the method in which compliance with the NRC Order is documented. The inspectors

reviewed the inspection results for this outage and found that no indications of active or

recent boric acid leakage from pressure-retaining components above the RPVH were

identified.

12)

Did the licensee perform appropriate follow-on examinations for indications of

boric acid leaks from pressure-retaining components above the RPVH?

Yes. The licensee identified some boric acid residue that was later determined by

chemical analysis to be older than the recent operating cycle. The residue was

attributed to a conoseal leak in 2002. No other indications of boric acid leakage were

found during this outage.

.3

(Open) Temporary Instruction (TI) 2515/166, Pressurized Water Reactor Containment

Sump Blockage (NRC Generic Letter 2004-02) - Unit 2

a.

Inspection Scope

The inspectors verified the Unit 2 implementation of the licensees commitments

documented in their September 1, 2005, response to Generic Letter 2004-02, Potential

Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents

28

Enclosure

at Pressurized Water Reactors. The commitments included a permanent screen

assembly modification, a license amendment request to change the UFSAR description

of the sump screen analysis methodology, and submittal of a supplemental response to

GL 2004-02. This review included the sump screen assembly installation procedure,

screen assembly modification 10 CFR 50.59 evaluation, structural (debris) loading

calculation, and validation testing of the modified sump screen design. The inspectors

also reviewed the foreign materials exclusion controls and the completed Quality

Assurance/Quality Control records for the screen assembly installation. The inspectors

conducted a visual walkdown to verify the installed screen assembly configuration was

consistent with drawings and the tested configuration and verified the design criteria for

screen gap.

b.

Findings and Observations

No findings of significance were identified.

Unit 2 permanent modifications completed at the time of this inspection were

implemented in accordance with Sequoyah Generic Letter 2004-02 response and

supporting evaluations. The license amendment request to change the UFSAR screen

analysis methodology description had been submitted and approved. No modifications

were required to address downstream effects. TI 2515/166 will remain open pending

completion and NRC review of the licensees GL 2004-02 commitments for Unit 1 which

are scheduled for the fall 2007.

.4

(Closed) NRC Temporary Instruction (TI) 2515/169, Mitigating Systems Performance

Index (MSPI) Verification

a.

Inspection Scope

During this inspection period, the inspectors completed a review of the licensees

implementation of the Mitigating Systems Performance Index (MSPI) guidance for

reporting unavailability and unreliability of monitored safety systems in accordance with

TI 2515/169.

The inspectors examined surveillances that the licensee determined would not render

the train unavailable for greater than 15 minutes or during which the system could be

promptly restored through operator action and therefore, are not included in

unavailability calculations. As part of this review, the recovery actions were verified to

be uncomplicated and contained in written procedures.

On a sample basis, the inspectors reviewed operating logs, work history information,

maintenance rule information, corrective action program documents, and surveillance

procedures to determine the actual time periods the MSPI systems were not available

due to planned and unplanned activities. The results were then compared to the

baseline planned unavailability and actual planned and unplanned unavailability

determined by the licensee to ensure the datas accuracy and completeness. Likewise,

these documents were reviewed to ensure MSPI component unreliability data

determined by the licensee identified and properly characterized all failures of monitored

components. The unavailability and unreliability data were then compared with

29

Enclosure

performance indicator data submitted to the NRC to ensure it accurately reflected the

performance history of these systems.

b.

Findings and Observations

No findings of significance were identified. The licensee accurately documented the

baseline planned unavailability hours, the actual unavailability hours and the actual

unreliability information for the MSPI systems. No significant errors in the reported data

were identified, which resulted in a change to the indicated index color. No significant

discrepancies were identified in the MSPI basis document which resulted in: (1) a

change to the system boundary, (2) an addition of a monitored component, or (3) a

change in the reported index color.

.5

Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review

a.

Inspection Scope

The inspectors reviewed the interim report for the INPO plant assessment report of

Sequoyah conducted in July 2006. The inspectors reviewed the report to ensure that

issues identified were consistent with the NRC perspectives of licensee performance

and if any significant safety issues were identified that required further NRC follow-up.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

.1

Exit Meeting Summary

On January 3, 2007, the resident inspectors presented the inspection results to

Mr. R. Douet and other members of his staff, who acknowledged the findings. The

inspectors asked the licensee whether any of the material examined during the

inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the

licensee and is a violation of NRC requirements which meet the criteria of Section VI of

the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

TS 6.8.1 requires that written procedures shall be established, implemented, and

maintained covering the activities recommended in Appendix A of Regulatory

Guide 1.33, Revision 2, February 1978. Contrary to this, on November 28, 2006,

an AUO improperly implemented 0-GO-13,Reactor Coolant System Drain and

Fill Operations, Revision 54, Appendix AC by mispositioning an RCS loop 4 drain

valve. This revealed itself through the subsequent transfer of RCS inventory to

the Reactor Coolant Drain Tank and lowering of RCS pressurizer level. The

30

Enclosure

error was promptly corrected by operations staff and the event was identified in

the licensees corrective action program as PER 115534. This finding is of very

low safety significance because it did not challenge RCS inventory control by

exceeding available makeup capacity.

ATTACHMENT: SUPPLEMENTAL INFORMATION

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

J. Adams, Boric Acid

D. Bodine, Chemistry/Environmental Manager

R. Bruno, Training Manager

R. Douet, Site Vice President

B. Dungan, Outage and Site Scheduling Manager

J. Epperson, Licensed Operator Requal Lead

J. Goulart, ISI

K. Jones, Site Engineering Manager

Z. Kitts, Licensing Engineer

D. Kulisek, Plant Manager

G. Morris, Licensing and Industry Affairs Manager

T. Niessen, Site Quality Manager

M. A. Palmer, Radiation Protection Manager

M. H. Palmer, Operations Manager

K. Parker, Maintenance and Modifications Manager

J. Proffitt, (Acting) Site Licensing Supervisor

J. Reisenbuechler, Operations Training Manager

R. Reynolds, Site Security Manager

N. Thomas, Licensing Engineer

S. Tuthill, Chemistry Operations Manager

J. Whitaker, ISI

K. Wilkes, Emergency Preparedness Manager

NRC personnel:

R. Bernhard, Region II, Senior Reactor Analyst

D. Pickett, Project Manager, Office of Nuclear Reactor Regulation

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000327,328/2006005-01

NCV

Failure to Certify Qualifications and Status

of Licensed Operators Were Current and

Valid (Section 1R11.3)

Opened

05000328/2006005-02

URI

Appendix R Manual Isolation Valve Failure

to Close Within the Required Time text

(Section 1R15)

Closed

05000327,328/2515/169

TI

Mitigating Systems Performance Index

Verification (Section 4OA5.4)

A-2

Attachment

Discussed

05000327, 328/2515/150

TI

Reactor Pressure Vessel Head and Vessel

Head Penetration Nozzles (NRC Order EA-

03-009) - Unit 2 (Section 4OA5.2)

05000327, 328/2515/166

TI

Pressurized Water Reactor Containment

Sump Blockage (NRC Generic Letter 2004-

02) - Unit 2 Section 4OA5.3)

Attachment

LIST OF DOCUMENTS REVIEWED

Section 1R01: Adverse Weather Protection

SPP-10.14, Freeze Protection, Revision 0

M&AI-27, Freeze Protection, Revision 12

0-PI-OPS-000-006.0, Freeze Protection, Revision 45

1-PI-EFT-234-706.0, Freeze Protection Heat Trace Functional Test, Revision 30

Section 1R02: Evaluation of Changes, Tests, or Experiments

Full Evaluations:

DCN D21640A, Radiation Monitors Are Being Deleted/Abandoned On Unit 1.

DCN D21641A, Radiation Monitors Are Being Deleted/Abandoned On Unit 2.

DCN D21854A, DG Starting Air PCV Modification.

DCN D21247A, Replace The Existing Electrotechnical Controls For The MCR And EBR A/C

Condensing Units With Digital Controls.

DCN D21248A, Replace The Existing Electrotechnical Controls For The MCR And EBR A/C

Condensing Units with Digital Controls.

FSAR Section 15.2.10, Revision to Section 15.2.10 of the FSAR containing the transient

analysis for feed water malfunction event.

TACF 1-05-013-R1, Temporary configuration change involving installation of non-nuclear safety

low volume high pressure pump into the SI System.

TACF 1-05-002-063, R1, Temporary installation of TVA Class B piping/tubing and check valve

downstream of 1-VLV-63-834 to provide RHRS pressure relief leakage.

FSAR Section 10.4.7 and 10.4.8, Proposed FSAR change to allow Steam Generator Blowdown

to remain in service for various reasons.

ES-1.3, R12, Revised ES-1.3 to modify guidance on stopping and restarting SI pump (PER 04-

000344-000).

Screened Out Items:

1-SI-OPS-000-003.M R32, Add Glycol Valves In Accordance With 06-NSS-061-035.

TI-28 REV 198, Procedure Revision On Unit 1 NIS Power Range Calibration Data

0-SI-OPS-068-137.0, Added Precaution And Limitation G To Section 3.2.

0-SO-14-4 Rev 10, Added Section 8.5 To Provide Instructions For Manual Operation Of

Temporary Sump Pump.

0-SO-77-11 R15, Revised To Add A Precaution To Monitor Waste Gas Vent Header

Frequently.

1-SO-63-1, Rev. 45, Revised section 8.1 step 6 of procedure to make the step conditional.

2-SI-OPS-000-003.M, Rev. 26, Added note 5 to exempt monthly valve stroke of the glycol valve

when the valve was stroked in the previous 7 days.

0-GO-14-4, R12, Revised to incorporate changes in accordance with NB 060785.

0-GO-5, Rev. 47, Revised step in section 5.4 concerning control rods, ref. NB 060297; added

step to section 5.1 concerning MFPT master controller output, ref. PER 100196-03.

1-AR-M1-A, Rev. 38, Revised in response to 060738 which provided additional information

regarding the inputs for Window A-5.

DCN D20960A, Sequoyah Independent Spent Fuel Storage Installation, (ISFSI).

0-SO-30-10, R31, Revised section 8.15 to provide guidance for Auxiliary Building Chill Water

Feed and Bleed when system is set up for winter operation.

A-4

Attachment

2-SI-TDC-068-254, Rev. 5, Surveillance instruction is being changed from 18 months to

conditional.

0-SO-70-1, R34, Added a step and caution to sections 8.5.2 and 8.5.4 to initiate a Work Order

to backfill affected flow transmitter following restoration of CCCS HX. 0B1 or 0B2 after

maintenance.

0-SO-77-1, Rev.40, Revised to provide guidance on the transfer of the Laundry and Hot

Shower Tank to the CDCT; moved guidance on re-circulation of the CDCT to new appendix E.

1-SI-OPS-000-003.M, R33, Revise note 18 in Appendix A of surveillance instruction to show

allowable channel deviation of less than or equal to 5%.

Problem Evaluation Reports (PERs):

84897, 0-PI-ECC-313-595.0 Cannot Be Performed As Currently Written

31739, Westinghouse Advisory Letter NASL-02-3 Describes A Process Measurement Uncertain

99597, Water In Waste Gas Vent Header During Resin Transfer

64337, DG 2-PCV-082-262 Blow Down

98255, MCR B Chiller Oil Temperature Swinging

65752, Specified Post Maintenance Testing Deficiencies

76900, S/G Blowdown Isolation of AFWP Start.

20195, ES 1.3, Transfer to RHR Containment Sump requires stopping the SI Pumps if RCS

pressure is greater than 1500 psig.

Work Orders:

6-771849-000, Check TE Accuracy, if unsatisfactory, Then Replace the TE

6-771384-000, Replace the Oil Cooler TCV for the B MCR Chiller

Procedures:

TI-28, Rev. 198, Curve Book

0-SI-OPS-068-137.0, Rev. 19, Reactor Coolant System Water Inventory

1-SI-OPS-000-003.M, Rev. 32, Monthly Shift Log

1-SI-OPS-000-003.W, Rev. 37, Weekly Shift Log

0-SO-14-4, Rev. 10, Condensate Demineralizer waste Disposal

0-SO-77-11, Rev. 15, Waste Gas Compressor Operation

0-PI-ECC-313-595.0, Rev. 4, Periodic Calibration of Auxiliary Building Heating, Ventilating and

Air Conditioning

SPP - 9.4, 10 CFR 50.59 Evaluations of Changes, Tests and Experiments, Revision 7.

EN-1-102, 10 CFR 50.59 / 10 CFR 72.48, Reviews, Revision 7.

Miscellaneous Documents:

PMTI-SQN-21854, DG 1A-A Starting Air 5 Start Capacity Verification

SSD 1- L - 68-325, Low RCS Pressurizer Level

SSD 1 L - 68-326, High RCS Pressurizer Level.

SSD 2 -L -68-325, Low RCS Pressurizer Level

SSD 2- L - 68-326, High RCS Pressurizer Level.

NEI 96-07, Nuclear Energy Institute, Guidelines for 10 CFR 50.59 Implementation, Revision 1.

Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59 Changes, Tests and

Experiments, November 2000.

A-5

Attachment

Section 1R04: Equipment Alignment

1,2-47W810-1, Flow Diagram - Residual Heat Removal System, Revision 47

2-47W811-1, Flow Diagram - SI System, Revision 57

Section 1R05: Fire Protection

SQN Drawing 1,2-47W494-6 Fire Protection Compartmentation-Fire Cells Plan El. 669' & 685'

SQN Fire Protection Report Part II - Fire Protection Plan, Revision 20

SQN-26-D054/EPM-ABB-IMPFHA, SQN Fire Hazards Analysis Calculation, Appendix A

Spp-10.10, Control of Transient Combustibles, Revision 4

Section 1R07: Heat Sink Performance

PER 116021, Containment Spray Heat Exchangers Not in Chemical Layup

TVA Letter S64 950922 800, Program Update Regarding NRC GL 89-13 dated September 22,

1995

1,2-47W812-1, Flow Diagram Containment Spray System, Revision 42

Section 1R08: Inservice Inspection Activities

Programs/Procedures/Reports

2-SI-SXI-068-114.3, Steam Generator Tubing Inservice Inspection and Augmented Inspections,

Revision 2

Degradation Assessment for Sequoyah Unit 2 Cycle 14

Operational Assessment Report for Unit 2 Cycle 13 Refueling Outage

Self Assessment CRP-ENG-009 SQN ASME Section XI Program

Self Assessment 06SQN-12-ENG-XI ASME Section XI Inservice Inspection (ISI) Program

SQN-ENG-03-007 Boric Acid Program Effectiveness Assessment

SPP-9.7, Corrosion Control Program, Rev. 13

Technical Instruction 0-TI-DXX-000-097.1, Rev. 01, Boric Acid Corrosion Control Program

BP-257, Rev. 5, TVA Business Practice, Integrated Material Issues Management Plan,

Appendix A

Proc. No. N-UT-76, Rev. 6, Generic Procedure for Ultrasonic Examination of Ferritic Pipe

Welds.

Proc. No. N-UT-64, Rev. 9, Generic Procedure For The UT Examination of Austenitic Pipe

Welds

Proc. No. N-VT-1, Visual Examination Procedure for ASME Section XI Preservice and Inservice

Proc. No. N-VT-15, Rev. 5, Visual Examination of Class MC and Metallic Liners of Class CC

Components of Light-Water Cooled Plants

SQN Unit 2 Examination Schedule 0-SI-DXI-115.3, Att.5

Design Change Package 22061, Pressurizer Safe End Weld Overlays

WO # 06-775288-002, Pressurizer Safe End Weld Overlays

Vendor Instruction 0-VI-MOD-068-001

Welding Services Traveler 103804-001

A-6

Attachment

Corrective Action (PERS)

03-017128-000, NRC inspectors concern that a GAP between the support steel and the pipe

indicated that the dead weight was not being supported.

20732, NRC inspector expressed concern that the NDE procedure N-VT-1 does not address

GAPS observed during hanger inspections.

107387, Borated Water Leak on lower flange of 20LCV-62-1`8, Boron is dry

100794, 2A Containment Spray Pump outboard Seal leak.

106740, Boric Acid Corrosion on support for SQN-2-VLV-063-0578

90714, 2-FCV-63-156 packing leak

81632, Leakage observed on pressurizer safe-ends RCW-25-SE and RCW-26-SE.

Section 1R11: Licensed Operator Requalification

Quarterly Review

AOP-I.08, Turbine Impulse Pressure Instrument Malfunction, Revision 8

FR-S.1, Function Restoration Procedure - Nuclear power Generation/ATWS, Revision 20

E-0, Reactor Trip or SI, Revision 27

ES-0.1, Reactor Trip Response, Revision 30

Biennial Review

Procedures and Records

TRN 11.4 Continuing Training For Licensed Personnel, Rev. 11.

TRN 1 Administering Training, Rev 17.

OPDP-1 Conduct of Operations, Appendix 0, License Status-Active/Inactive License, Rev. 6.

Operations Directive Manual, Appendix B-Qualifications Tracking Requirements, Rev. 2.

Badge Access Transaction Reports

Licensed Operator Medical Records

Remedial Training Records

Written Exams: A3 RO Exam and A3 SRO Exam.

Simulator Work Request - PR4542

LER 2005-001-00 Units 1 and 2

LER 2005-002-00 Unit 2

LER 2006-001-00 Units 1and 2

Job Performance Measures

JPM 163 Steam line Pressure Transmitter fails low.

JPM 33AP Manual Control of AFW Following a Reactor Trip.

JPM 12 Pressurizer Level Control Malfunction.

JPM 59 Establish Excess Letdown.

JPM 80" Local Control of Charging Flow.

JPM 61A2 Transfer 480V SD Board 2A1-A From Normal to Alternate Supply.

JPM 72 Local Alignment of 1-RM-90-112 to Lower Containment.

JPM 32AP Local Manual Control of S/G PORV.

JPM 6 Perform Boration of the RCS From Outside the Main Control Room.

JPM 78 AP Respond to an ATWS Trip the Reactor Locally.

A-7

Attachment

Simulator Scenarios:

S-13 Uncontrolled Depressurization of All Steam Generators. Rev 12.

S-7 Pressurizer Vapor Space Accident. Rev 15.

S-11 LOCA with Loss of RHR Recirculation. Rev 13.

Simulator Malfunction Tests:

ED15 Loss of 250VDC Battery Board.

IA03

FW23

FW20

ED08

ED10

Transient Tests:

1. 2 Both Main Feedwater Pumps Trip , AFW fails to start.

1. 5 Trip of Any Single Reactor Coolant Pump.

1. 8 Loop 2 Cold-Leg Large Break LOCA with Loss of Offsite Power.

1. 9 Main Steam Line Break Inside Containment.

1. 10 Slow RCS Depressurization to Saturation.

Normal Tests:

2005 Steady State Operation Drift Test

2005 Steady State Operation Static Test for 100%, 66%, and 44% power.

Section 1R12: Maintenance Effectiveness

TI-4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting - 10 CFR 50.65, Revision 19

Section 1R13: Maintenance Risk Assessments and Emergent Work Evaluation

Sentinel Run, October 23 to November 12, 2006

SQN Plan-of-the-Day, October 26, 2006

SQN MSS-OPS Daily Schedule Report 24 Hour Look-Ahead, October 25, 2006

Sentinel Risk Assessment for Failed EDG 2B-B

Section 1R15: Operability Evaluations

0-SI-SFT-311-001.A, Control Room Air-Conditioning System Train A, Revision 1

UFSAR Section 6.4, Habitability Systems

UFSAR Section 9.4, Heating, Ventilating, and Air-Conditioning

FE 41643, Observed Air Flow Above Design Flow For MCR A Air Handling Unit

1,2-47W866-4, Flow Diagram Heating, Ventilation and Air-Conditioning - Control Building,

Revision 3

1,2-47W867-2, Mechanical Air-Conditioning Control Diagram - Control Building, Revision 12

B87 951205 003, ERCW Screen Wash System Hydraulic Analysis, Revisions 2 and 3

0-SI-SXP-067-202.B, ERCW Traveling Screen Wash Pump B-B Performance Test, Revision 8

A-8

Attachment

0-SO-67-1, Essential Raw Cooling Water, Revision 63

1,2-45N765-1, Wiring Diagram 6900V Shutdown Aux Power Schematic Diagram SH-1,

Revision 14

1,2-45N765-2, Wiring Diagram 6900V Shutdown Aux Power Schematic Diagram SH-2,

Revision 20

WO 04-774974-000, Replace Emergency Diesel Generator 2B-B Breaker

1,2-47W809-1, Flow Diagram Chemical & Volume Control System

1-108D273-18, Process Control Block Diagram Turbine Impulse Pressure Protection Sets I and

II, Revision 0

Section 1R17: Permanent Plant Modifications

Problem Evaluation Reports (PERs):

31739, Westinghouse Advisory Letter NASL-02-3 Describes A Process Measurement Uncertain

65752, Specified Post Maintenance Testing Deficiencies

84070, Diesel Generator 1A-A cable testing.

103766, Main Bank Transformer 1B Hot Spots

104337, Main Bank Transformer 1B Hot Spot

Calculations:

Calculation No. SQN- APS - 042, 480 V Turbine Building Common Board Load Coordination,

Short Circuit, Circuit Protection and Voltage Drop Analysis, Revision 4.

Calculation No. SQN-APS-041, 480 VAC Unit Board Load Coordination Study, Revision 4.

Work Orders:

6-771849-000, Check TE Accuracy, if unsatisfactory, Then Replace the TE

2-002298-000, Westinghouse Advisory Letter NSAL-02-3

03-012340-001, Replace degraded portion of 6900 V Diesel Generator 1A-A power cable

PP351A between Unit 1 Additional Equip. Bldg. And D/G exciter cubicle.

03-012340-002, Install section of new replacement cable PP351A from AEB-1 to MH-14 via

existing conduit.

Miscellaneous Documents:

Westinghouse Advisory Letter NSAL-03-9

ABB Power T&D- Sequoyah Nuclear Plant Final Report Main Generator Transformer Life

Assessment.

Drawings:

Drawing No. 1, 2-3591A28, Breaker Setting Sheet 480 V Unit Board 1A, Revision 5

Drawing No. 1, 2-3591A30, Breaker Setting Sheet 480 V Unit Board 1B, Revision 6.

Drawing No. 1, 2-3591A32, Breaker Setting Sheet 480 V Unit Board 2A, Revision 6.

Drawing No. 1, 2-3591A34, Breaker Setting Sheet 480 V Unit Board 2B, Revision 5

Drawing No. 1, 2-3591A36, Breaker Setting Sheet 480 V Turb. Building Common Board,

Revision 9 Drawing No. 1, 2-15E500-1, Key Diagram Station Auxiliary Power, Revision 25

Drawing No. 1, 2-15E500-3, Transformer Taps and Voltage Limits - Auxiliary Power System,

Revision 16.

Drawing No. 1-45N1504, Wiring Diagrams - Main Single Line 500 KV Switchyard, Revision 29

A-9

Attachment

Drawing No. 1-45W1541, Wiring Diagrams AC Schematic Unit 1 Generator & transformer

Circuits, Revision 14

Procedures:

TI-28, Rev. 198, Curve Book

PER Written Because of Inspection Finding

114743, Superseded ARP revision found in ACR

Section 1R19: Post Maintenance Testing

PER 115780, 2-FCV-74-28 Did Not Appear To Fully Open

2-SI-SXP-074-202.A, RHR Pump 2A-A Performance and Discharge Check Valve Test,

Revision 0

WO 06-780773-000, Calibrate 2-FCV-74-28 and Limit Switches

Section 1R20: Refueling and Outage Activities

0-GO-6, Power Reduction from 30& Reactor Power to Hot Standby, Revision 32

0-GO-7, Unit Shutdown From Hot Standby to Cold Shutdown, Revision 47

0-GO-15, Containment Closure Control, Revision 21

DVD Recording of U2C14 Core Load Verification

1,2-47W812-1, Flow Diagram Containment Spray System, Revision 42

Tagout Clearance 2-72-2406-RFO, Motor Operated Valve Maintenance on 2-FCV-72-21

0-GO-13, Reactor Coolant System Drain and Fill Operations, Revision 54

Sequoyah Nuclear Plant Unit 2 Cycle 15 Core Operating Limits Report

Section 1R22: Surveillance Testing

SPP-8.1 Conduct of Testing, Rev 4

Section 1EP6: Drill Evaluation

NEI 99-02 Rev 0, March 2000

Emergency Plan Implementing Procedure (EPIP) - 1, Emergency Plan Classification Matrix,

Rev 37

EPIP-3, Alert, Rev 29

EPIP-4, Site Area Emergency, Rev 29

EPIP-5, General Emergency, Rev 36

EPIP-6, Technical Support Center, Rev 41

EPIP-7, Operations Support Center, Rev 25

Section 2OS1: Access Control To Radiologically Significant Areas

Procedures, Instructions, Guidance Documents, and Operating Manuals

ANSI/ANS 3.1-1987, Selection, Qualification, and Training of Personnel for Nuclear Power

Plants

Tennessee Valley Authority (TVA), TVA Nuclear (TVAN), Standard Programs and

A-10

Attachment

Processes (SPP) - 3.1, Corrective Action Program, Rev. 11

Active Radiation Work Permits (RWPs) List, dated 12/11/2006

RP Personnel Identification by Craft Report, dated 12/14/2006

Task Qualification List (selected individuals), dated December 14, 2006

LHRA Key Control Log Sheets (several pages)

TVA, TVAN, TRN-20, Health Physics Technician Training, Rev. 13

High Radiation Areas at Sequoyah List, document not dated

SNP RP Organizational Chart (current and proposed changes), document not dated.

TVAN Radiation Protection Peer Team Challenge Update (MS Power Point presentation),

dated 12/13/2006

TVA, TVAN, SPP-5.2, ALARA Program, Rev. 3

RWP 06027010, Rev. 0, Routine Plant Maintenance-Lower Containment All Areas

RWP 06027035, Rev. 0, Routine Plant Maintenance-Inside Polar Crane All Areas

RWP 06027390, Rev. 1, Routine Plant Maintenance-Accumulator 1-4

RWP 06037020, Rev. 0, Inservice Inspection-Steam Generator Primary Side 1-4

RWP 06047141, Rev. 0, Refueling-U-2 Reactor Cavity

TVA, Sequoyah Nuclear Plant (SNP), Radiological Control Instruction (RCI)-01, Radiation

Protection Program

TVA, SNP, RCI-01, Training and Qualification of Health Physics Technicians-Radiation

Operations Technicians, effective date 02/24/05

TVA, SNP, RCI-14, Radiation Work Permit (RWP) Program, Rev. 37

TVA, SNP, RCI-15, Radiological Postings, Rev. 15

TVA, SNP, RCI-24, Control of Very High Radiation Areas, Rev. 7

TVA, SNP, RCI-28, Control of Locked High Radiation Areas, Rev. 5

TVA, SNP, RCI-29, Control of Radiation Protection Keys, Rev. 4

Records and Data Reviewed

SNS VSDS Survey Nos. 120506-2, 120606-8, 120506-15, 120606-10, 120606-7, 120706-2,

120106-10, 120606-6, and 120306-4

Air Sample Survey Nos. 120406018, 120506021, 120506024, 120506034, 120506037,

120506045, 120506048, 120506053, 120606020, 120706010,120406024, 120606028,

120506012, and 120606043

Corrective Action Program Documents

Nuclear Assurance (NA) - TVAN-Wide - Audit Report No. SSA0502 - Radiological Protection

and Control Audit, dated January 19, 2006

SQN-RP-05-001, Self-Assessment Report, dated 12/22/04

SQN-RP-05-003, Self-Assessment Report, dated 7/29/05

Problem Evaluation Report (PER) 82569, Presently U-1 Lower Containment Has a Ladder.

PER 115944, The Total Nozzle Dam Jumpers Dose Was Greater than the ALARA estimate

PER 101211, Posting and Control of Filter Cubicles...

PER 113913, Lock Box for Lifting Device Control

PER 109603, Radiation Posting

PER 109604, Radcon Use of Industry Information

PER 87610, Key Taken Home

PER 82027, High Radiation Readings on Valve

PER 82643, Unexpected Radiation Level Change

A-11

Attachment

PER 84532, VHRA Key Inventory

PER 99226, Locked High Radiation Door Locks Sticking

Section 4OA5: Other Activities - Operation of ISFSI

NEI 96-07, Guidelines for 10 CFR 72.48 Implementation, Appendix B

SPP-9.9, 10 CFR 72.48 Evaluations of Changes, Tests, and Experiments for Independent

Spent Fuel Storage Installation, Revision 1

Regulatory Guide 3.72 - Guidance for Implementation of 10 CFR 72.48, Changes, Tests and

Experiments

PER 95624, MPC-0011 Lid Did Not Fully Seat Due to Upper Fuel Spacers Not Vertical or

Plumb

10 CFR 48 Evaluation, Response to NRC IN 2003-16

10 CFR 48 Procedure Change Evaluation, Revision of NFTP-100, Fuel Selection for Dry MPC

Storage

10 CFR 48 Screening, Auxiliary Building Crane Truck Repairs

10 CFR 48 Screening, Auxiliary Building Crane Truck Replacements

10 CFR 48 Screening, Revision to Welding Procedures

10 CFR 48 Screening, Procedure Change to Fuel Handling Instruction FHI-14

10 CFR 48 Screening, Procedure Change to Fuel Handling Instruction FHI-3

Section 4OA5: Other Activities - TI 2515/150

Procedures

0-PI-DXX-068-100.R, Monitoring of Reactor Head Canopy Seal Welds For Leakage, Rev. 1

54-ISI-603-002, Automated Ultrasonic Examination of RPV Closure Head Penetrations

Containing Thermal Sleeves

54-ISI-604-001, Automated Ultrasonic Examination of Open Tube RPV Closure Head

Penetrations

54-ISI-605-02, Automated Ultrasonic Examination of RPV Closure Head Small Bore

Penetrations

54-ISI-240-44, Visible Solvent Removable Liquid Penetrant Examination Procedure

N-VT-17, Visual Examination for Leakage of PWR Reactor Head Penetrations, Rev. 4

SPP-9.7, Corrosion Control Program, Appendix D, Technical Requirements for the Boric Acid

Corrosion Control Program, Rev. 13

Records/Reports/Engineering Documents

Equipment Certification Records for the following NDE Equipment:

Blade Probes: S1035 NL, S5002 NL, and S5001 NL

Ultrasonic Transducers: 21GB-06001 and 2078-06001

Engineering Information Record 51-9027415-000, RPV Head Penetration Inspection Plan and

Coverage Assessment for Sequoyah Units 1 and 2

Calculation C-3217-00-02, Sequoyah 1 and 2 CRDM and Instrument Column Nozzle Stress

Analysis

Letter L44 030227 801, Response to issuance of NRC Order

A-12

Attachment

Corrective Action Documents

PER 115561, Evidence of leakage during canopy seal weld inspection

PER 116540*, EDY calculation not performed every outage

PER 116165*, Transducer frequencies documented incorrectly

• Problem Evaluation Reports generated as a result of this inspection

Section 4OA5: Other Activities - TI 2515/166

Surveillance Instruction 2-SI-SIN-063-009-02, Containment Sump Inspection, dated 11/08/06

DCN 22023, Modify Containment Sump Screens as required by NEI Methodology, dated

11/22/06

Amendment to Facility Operating License No. 302, DPR-79, Revised Transport Analysis

Methodology for Containment Debris Transport, dated 11/07/06

TVA letter to NRC, Sequoyah Response to GL 2004-02. dated 9/01/05

AREVA document No. 51-9008500-003, Test Report for Sure-Flow strainer (Prototype)

Headloss Evaluation for Sequoyah 1 & 2 ECCS Containment Sumps, dated 7/26/06

AREVA document No. 51-9008506-001, Sequoyah Advanced Design Reactor Building Sump

Strainer Test Results Summary, Units 1 & 2, dated 1/31/06

GL 2004-02 Supplemental Response, Sequoyah Nuclear Plant Units 1 & 2, - NRC GL 2004-02,

Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis

Accidents at PWRs (Draft dated 12/15/06)

Calculation ALION-CAL-TVA-2740-05, SQN Units 1 & 2 Containment Sump Debris

Accumulation and Head Loss, dated 6/28/05

Calculation TDI-6009-02, SFS Surface Area Flow Volume - TVA/Sequoyah 1 & 2, dated

9/21/06

MDQ0072980034, "CCP, SIP, CSP, and RHR Pump NPSH Evaluation", Rev 1, 11/19/2006

DCN # D22023, "Modify Containment Sump Screens as Required by NEI Methodology", Rev A,

11/22/2006

Calculation TDI-6009-004, "Module Debris Weight - TVA/Sequoyah - 1/2", Rev 2, 10/13/2006

Calculation PCI-5465-S01, "Structural Evaluation of Advanced Design Containment Building

Sump Strainers", Rev 0, 10/20/2006

Routine Work Order 06-774811-000, "Containment RHR Sump 48N919", Rev 5

FME Accountability Log, SPP 6.5.1

Section 4OA5: Other Activities - TI 2515/169

Procedures, Manuals, and Guidance Documents

NEI 99-02, Mitigating System Performance Index (MSPI) Basis Document, Revision 1

Selected System Status Reports

0-SI-SXV-063-266.0, ASME Section XI Valve Testing

1,2-SI-SXV-000-201.0, Full Stroking of Category A and B Valves During Operation

0-SI-SXV-074-266.0, ASME Section XI Valve Testing

1,2-SI-OPS-074-128.0, RHR Discharge Piping Vent

1-SI-SXP-074-074-201.B, RHR Pump 1B-B Performance Test

2-SI-SXP-074-074-201.B, RHR Pump 1B-B Performance Test

0-SI-SXV-000-221.0, Full Stroking of the Common ERCW and CCS Category A and B

Valves During Operation

A-13

Attachment

0-SI-OPS-067-682.Q, ERCW Non-Safety Related Flow Balance Valve Position Verification

0-SI-SXP-067-202.B, ERCW Traveling Screen Wash Pump B-B Performance Test

2-SI-OPS-070-32.A, Component Cooling Water Valves Position Verification Train A

Records and Data

Selected Control Room Logs, January 2004 through December 2006

EDG NRC Performance Indicators, 2002 - 2005

AFW NRC Performance Indicators, 2002 - 2005

HPSI NRC Performance Indicators, 2002 - 2005

RHR NRC Performance Indicators, 2002 - 2005

Consolidated Data Entry MSPI Derivation Reports Generated November 2006

MSPI Equipment Functional Failure Data Sheets

Maintenance Rule Unavailability Data Sheets, 2002-2006

Maintenance Rule Unreliability Data Sheets, 2002-2006

Corrective Action Program Documents

Selected Corrective Action Reports, 2005-2006

Attachment

LIST OF ACRONYMS

AFW

auxiliary feedwater

ANSI

American National Standards Institute

AOP

abnormal operating procedures

ARC

alternate repair criteria

ASME

American Society of Mechanical Engineers

ATWS

anticipated transient without scram

AUO

auxiliary unit operator

BACC

boric acid corrosion control

BMV

bare metal visual

CCP

cooling charging pump

CCPIT

cooling charging pump injection tank

CFR

Code of Federal Regulations

CR

condition report

CRDM

control rod drive mechanism

CVCS

chemical volume control system

DCN

design change notice

ECCS

emergency core cooling system

ECT

eddy current testing

EDY

effective degradation years

ERCW

essential raw cooling water

ETSS

examination technique specifications sheet

FCV

flow control valve

FE

functional evaluation

FME

foreign material exclusion

FOSAR

foreign object search and recovery

HR

high radiation

HUT

holdup tank

INPO

Institute of Nuclear power Operations

ISFSI

independent spent fuel storage installation

ISI

inservice inspection

LHRA

locked high radiation area

MRP

materials reliability program

MSPI

mitigating systems performance index

NCV

non-cited violation

NDE

non-destructive examination

NRC

U.S. Nuclear Regulatory Commission

ODSCC

outer diameter stress corrosion cracking

OPDP

operations department procedure

PAR

publically available records

PER

problem evaluation report

PER

protective action recommendation

PORV

power-operated relief valve

PWSCC

primary water stress corrosion cracking

RCP

reactor coolant pump

RCS

reactor coolant system

RHR

residual heat removal

RP

radiation protection

A-15

Attachment

RPVH

reactor pressure vessel head

RTP

rated thermal power

RWP

radiation work permit

RWST

refueling water storage tank

SDP

significance determination process

SER

safety evaluation report

SG

steam generator

SI

safety injection

SI

surveillance instructions

SSC

structure, system, or component

TDAFP

turbine driven auxiliary feedwater pump

TI

temporary instruction

TS

technical specification

TVA

Tennessee Valley Authority

UFSAR

updated final safety analysis report

UHI

upper head injection

URI

unresolved item

UT

ultrasonic testing

WOs

work orders