ML043340269

IR 05000271-04-008; 08/09/2004-09/03/2004; Vermont Yankee Nuclear Generating Station; Functional Review of Low Margin/Risk Significant Components and Human Actions

ML043340269
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	12/02/2004
From:	Lanning W Division of Nuclear Materials Safety I
To:	Thayer J Entergy Nuclear Operations
References
IR-04-008
Download: ML043340269 (70)

See also: IR 05000271/2004008

Text

December 2, 2004

Mr. Jay K. Thayer

Site Vice President

Entergy Nuclear Operations, Inc.

Vermont Yankee Nuclear Power Station

P.O. Box 0500

185 Old Ferry Road

Brattleboro, VT 05302-0500

SUBJECT:

VERMONT YANKEE NUCLEAR POWER STATION

NRC INSPECTION REPORT 05000271/2004008

Dear Mr. Thayer:

On September 3, 2004, the US Nuclear Regulatory Commission (NRC) completed an

inspection at the Vermont Yankee Nuclear Power Station. The enclosed inspection report

documents the inspection findings, which were discussed with members of your staff on

September 3, October 27, and November 23, 2004.

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

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

In conducting the inspection, the team examined the adequacy of selected components and

operator actions to mitigate postulated design basis accidents, both under current licensing and

planned power uprated conditions. The inspection also reviewed Entergys response to

selected operating experience issues, and assessed the adequacy of Vermont Yankees design

and engineering processes.

The team concluded that the components and systems reviewed would be capable of

performing their intended safety functions. The team also concluded that sufficient design

controls had been implemented for design and engineering work, including that related to

Entergys extended power uprate. The team did identify several deficiencies related to design

control at Vermont Yankee; however, sample based extent-of-condition reviews indicated the

original problems were not widespread or programmatic in nature. In addition, some of the

specific findings included topics that were within the scope of the NRCs power uprate review,

and thus, will require the submittal of additional information to the NRCs technical staff to

support that review.

The enclosed report documents eight findings of very low safety significance (Green), all of

which were determined to involve a violation of NRC requirements. Because of their very low

safety significance and because the findings were entered into your corrective action program,

the NRC is treating them as non-cited violations (NCVs), consistent with Section VI.A of the

NRCs Enforcement Policy. If you contest these non-cited violations, you should provide a

response within 30 days of the date of this inspection report, with the basis for your denial, to

the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-

0001; with copies to the Regional Administrator Region I; the Director, Office of Enforcement,

Mr. J. K. Thayer

2

United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC

Resident Inspector at the Vermont Yankee Nuclear Power Station.

In accordance with 10 CFR 2.390 of the NRCs "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 Publicly Available Records (PARS) component of

NRCs document system (ADAMS). ADAMS is temporarily unavailable due to an ongoing

security review; therefore, this document will also be posted on the NRC Web site at

http:\\\\www.nrc.gov\\reactors\\plant-specific-items\\vermont-yankee-issues.html.

Sincerely,

/RA/

Wayne D. Lanning, Director

Division of Reactor Safety

Docket No. 50-271

License No. DPR-28

Enclosure: Inspection Report 05000271/2004008 w/Attachments

Mr. J. K. Thayer

3

cc w/encl:

M. R. Kansler, President, Entergy Nuclear Operations, Inc.

G. J. Taylor, Chief Executive Officer, Entergy Operations

J. T. Herron, Senior Vice President and Chief Operating Officer

D. L. Pace, Vice President, Engineering

B. OGrady, Vice President, Operations Support

J. M. DeVincentis, Manager, Licensing, Vermont Yankee Nuclear Power Station

Operating Experience Coordinator - Vermont Yankee Nuclear Power Station

J. F. McCann, Director, Nuclear Safety Assurance

M. J. Colomb, Director of Oversight, Entergy Nuclear Operations, Inc.

J. M. Fulton, Assistant General Counsel, Entergy Nuclear Operations, Inc.

S. Lousteau, Treasury Department, Entergy Services, Inc.

Administrator, Bureau of Radiological Health, State of New Hampshire

Chief, Safety Unit, Office of the Attorney General, Commonwealth of Mass.

D. R. Lewis, Esquire, Shaw, Pittman, Potts & Trowbridge

G. D. Bisbee, Esquire, Deputy Attorney General, Environmental Protection Bureau

J. Block, Esquire

J. P. Matteau, Executive Director, Windham Regional Commission

M. Daley, New England Coalition on Nuclear Pollution, Inc. (NECNP)

D. Katz, Citizens Awareness Network (CAN)

R. Shadis, New England Coalition Staff

G. Sachs, President/Staff Person, c/o Stopthesale

J. Sniezek, PWR SRC Consultant

R. Toole, PWR SRC Consultant

Commonwealth of Massachusetts, SLO Designee

State of New Hampshire, SLO Designee

State of Vermont, SLO Designee

Mr. J. K. Thayer

4

Distribution w/encl:

(via E-mail)

S. Collins, RA

J. Wiggins, DRA

W. Lanning, DRS

R. Crlenjak, DRS

L. Doerflein, DRS

C. Anderson, DRP

D. Florek, DRP

J. Jolicoeur, RI OEDO

J. Clifford, NRR

R. Ennis, PM, NRR

V. Nerses, Backup PM, NRR

D. Pelton, DRP, Senior Resident Inspector

A. Rancourt, DRP, Resident OA

Region I Docket Room (with concurrences)

ADAMS ML043340269

SISP Review Complete: WDL

DOCUMENT NAME: E:\\Filenet\\ML043340269.wpd

After declaring this document An Official Agency Record it will be released to the Public.

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

OFFICE

RI/DRS

RI/DRS

NAME

CBaron/JJ for

GSkinner/JJ for

SSpiegelman/JJ for

GBowman/GTB

SDennis/SXD

DATE

12/2/04

12/2/04

12/2/04

12/2/04

12/2/04

OFFICE

RI/DRS

RI/DRP

NRR/PIPB

RI/DRS

RI/DRS

NAME

FBower/LTD for by telecon

MSnell/MPS

JJacobson/JJ

WSchmidt/WLS

LDoerflein/LTD

DATE

12/1/04

12/2/04

12/2/04

12/2/04

12/ 1/04

OFFICE

RI/DRS

NAME

WLanning/WDL

DATE

12/ 2/04

Mr. J. K. Thayer

5

OFFICIAL RECORD COPY

Enclosure

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No.

50-271

License No.

DPR-28

Report No.

05000271/2004008

Licensee:

Entergy Nuclear Vermont Yankee, LLC

Facility:

Vermont Yankee Nuclear Power Station

Location:

320 Governor Hunt Road

Vernon, Vermont

05354-9766

Dates:

August 9 - 20 and August 30 - September 3, 2004

Inspectors:

J. Jacobson, Team Leader, Inspection Program Branch, NRR

F. Bower, Senior Reactor Inspector, DRS, Region I

G. Bowman, Reactor Inspector, DRS, Region I

S. Dennis, Senior Operations Engineer, DRS, Region I

M. Snell, Reactor Engineer, DRP, Region I

C. Baron, NRC Contractor

S. Spiegelman, NRC Contractor

G. Skinner, NRC Contractor

Observer:

W. Sherman, Vermont State Nuclear Engineer

Approved by:

Wayne D. Lanning, Director

Division of Reactor Safety

Region I

Enclosure

CONTENTS

EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii

REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

4OA2 Problem Identification and Resolution (PI&R) . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1. Annual Sample Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2. Cross Reference to PI&R Findings Documented Elsewhere . . . . . . . . . . . . 1

4OA5 Other Activities - Temporary Instruction 2515/158 . . . . . . . . . . . . . . . . . . . . . . . 1

1. Inspection Sample Selection Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2. Results of Detailed Reviews . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

2.1

Detailed Component and System Reviews . . . . . . . . . . . . . . . . . 2

2.1.1

Electrical Power Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

2.1.2

Reactor Core Isolation Cooling (RCIC) System . . . . . . . . . . . . . 8

2.1.3 Residual Heat Removal System (RHR) . . . . . . . . . . . . . . . . . . 13

2.1.4

Safety Relief Valves and Code Safety Valves . . . . . . . . . . . . . 13

2.1.5

Reactor Feedwater and Condensate Components . . . . . . . . . 13

2.1.6

Reactor Building-to-Torus Vacuum Breaker System

. . . . . . . . 14

2.1.7

Review of Transient Analysis Inputs . . . . . . . . . . . . . . . . . . . . . 15

2.2

Review of Operator Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2.3

Review of Operating Experience and Generic Issues

. . . . . . . 20

4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

ATTACHMENT A: SUMMARY OF ITEMS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

ATTACHMENT B: SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . B-2

LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-3

LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-8

Enclosure

i

EXECUTIVE SUMMARY

During the period from August 9 through September 3, 2004, the US Nuclear Regulatory

Commission (NRC) conducted a team inspection in accordance with Temporary Instruction

2515/158, Functional Review of Low Margin/Risk Significant Components and Human

Actions, at the Vermont Yankee Nuclear Power Station. The team was comprised of eight

inspectors, including a team leader from the NRCs Office of Nuclear Reactor Regulation, four

inspectors from the NRCs Region I Office, and three contractors. All of the inspectors and

contractors met strict independence criteria developed for this inspection. Specifically, the NRC

inspectors had not performed engineering inspections at Vermont Yankee within the last two

years and had not been assigned as resident inspectors at Vermont Yankee. The contractors

had never been directly employed by Entergy or Vermont Yankee, had not performed contract

work for Entergy or Vermont Yankee in the past two years, and had not performed inspections

for the NRC at Vermont Yankee within the past two years. The inspection was the first of four

planned pilot inspections to be conducted throughout the country to assist the NRC in

determining whether changes should be made to its Reactor Oversight Process (ROP) to

improve the effectiveness of its inspections and oversight in the design/engineering area.

In selecting samples for review, the team focused on those components and operator actions

that contribute the greatest risk to an accident that could involve damage to the reactor core.

Additional consideration was given to those components and operator actions impacted by the

licensees request for a 20 percent extended power uprate (EPU) license amendment. The

team focused its reviews on those components and operator actions contained in the reactor

core isolation cooling (RCIC), main feedwater, safety relief valve, onsite electrical power, and

off-site electrical power systems. In addition, inspection samples were added based upon

operational experience and issues previously identified by the NRCs technical staff during the

course of their reviews associated with the licensees request for an EPU. A complete listing of

all components, operator actions, and operating experience issues reviewed by the inspection

team is contained in Attachment A to this report.

For each sample selected, the team reviewed design calculations, corrective action reports,

maintenance and modification histories, associated operating procedures, and performed

walkdowns of material conditions (as practical). The team concluded that the components and

systems reviewed would be capable of performing their intended safety functions. The team

also concluded that sufficient design controls had been implemented for engineering work,

including that related to Entergys EPU. The overall material condition of the plant and of the

specific components reviewed was also noted as being good. The team identified eight findings

of very low safety significance, one unresolved item, and one minor finding. The eight findings

are listed in the Summary of Findings section of this report.

The team assessed the safety significance of each of the findings using the NRCs Significance

Determination Process (SDP). Using this process, each of the findings was determined to be of

very low safety significance. Also, for each of the findings where current operability was in

question, the licensee provided a basis for operability and entered the issue into their corrective

action program, as necessary to complete a more comprehensive assessment of the issue,

including any programmatic oversight weaknesses that might have prevented self-identification.

In addition, for the findings associated with a design vulnerability of an RCIC pressure control

valve, the control of the condensate storage tank (CST) temperature to the limits of transient

Enclosure

ii

analysis assumptions, and the updating of the Safe Shutdown Capability Analysis, the team

performed sample-based extent-of-condition reviews during the inspection to determine the

breadth of the issues identified. No additional findings were identified during these reviews,

indicating the original problems identified were not widespread, and were likely not

programmatic in nature. Additional licensee extent-of-condition reviews of the issues were

ongoing at the conclusion of the inspection.

Some of the findings also concern topics that are within the scope of the NRCs power uprate

review and therefore will require the submittal of additional information to the NRCs technical

staff.

Enclosure

iii

SUMMARY OF FINDINGS

IR 05000271/2004008; 08/09/2004-09/03/2004; Vermont Yankee Nuclear Generating Station;

Functional Review of Low Margin/Risk Significant Components and Human Actions.

This inspection was conducted by five inspectors and three NRC contractors. Eight Green non-

cited violations, one unresolved item, and one minor finding were identified. The significance of

most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual

Chapter (IMC) 0609, Significance Determination Process. Findings for which the SDP does

not apply may be Green or be assigned a severity level after NRC management review. The

NRCs program for overseeing the safe operation of commercial nuclear power reactors is

described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

A.

NRC-Identified Findings

Cornerstone: Mitigating Systems

!

Green. The team identified a non-cited violation of 10 CFR Part 50.63, Loss of

All Alternating Current Power, because the licensee had not completed a coping

analysis for the period of time the alternate alternating current (AC) source (the

Vernon Hydro-Electric Station) would be unavailable and had not demonstrated

by test the time required to make the alternate source available for a station

blackout involving a grid collapse. This issue was more than minor because it

was associated with the Mitigating Systems Cornerstone attribute of Equipment

Performance and affected the cornerstone objective of ensuring availability,

reliability, and capability of systems needed to respond to a station blackout.

The issue screened as very low safety significance in Phase I of the SDP

because it was a design deficiency that was not found to result in a loss of

function. Specifically, the team found that the licensees preliminary coping

analysis, performed during the inspection, demonstrated a four-hour coping time

which should be sufficient to envelope the time required to start and align the

Vernon Station. (Section 4OA5.2.1.1)

!

Green. The team identified a non-cited violation of Technical Specifications

6.4.C, Procedures, because the licensee failed to establish adequate

procedures for determining the operability of the 115 kilovolt (kV) Keene line,

which is designated as an alternate immediate access power source if the

345/115 kV auto transformer is lost. This issue was more than minor because it

was associated with the Mitigating Systems Cornerstone attribute of Procedural

Quality and affected the cornerstone objective of ensuring availability, reliability,

and capability of systems needed to respond to a loss of off-site power. The

issue screened as very low safety significance in Phase I of the SDP because it

was a design deficiency that was not found to result in a loss of function.

Specifically, the team did not identify any instances where the lack of procedural

guidance had resulted in an inadequate assessment of off-site power operability

or the inoperability of the electrical system or any components.

(Section 4OA5.2.1.1)

Enclosure

iv

!

Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, because the licensee used incorrect and non-

conservative voltage values in calculations performed to assure that electrical

equipment would remain operable under degraded voltage conditions. This

issue was more than minor because it was associated with the Mitigating

Systems Cornerstone attribute of Equipment Performance and affected the

cornerstone objective of ensuring availability, reliability, and capability of systems

needed to respond to a design basis accident. The issue screened as very low

safety significance in Phase I of the SDP because it was a design deficiency that

was not found to result in a loss of function. Specifically, the team did not

identify any instances where using the Technical Specification degraded voltage

allowable setpoint values would have resulted in inoperable equipment.

(Section 4OA5.2.1.1)

!

Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, because the licensee did not implement measures

to ensure that the design basis for the cooling water supply to the lube oil cooler

of RCIC was correctly translated into the specifications, drawings, procedures, or

instructions. Specifically, the installed pressure control valve in the lube oil

cooler water supply line was not independent of air systems, and the installed

piping between the pressure control valve and lube oil cooler did not contain a

restricting orifice. This issue was more than minor because it was associated

with the Mitigating Systems Cornerstone attribute of Equipment Performance

and affected the cornerstone objective of ensuring the reliability of the RCIC

system. The issue screened as very low safety significance in Phase I of the

SDP because it was a design deficiency that was not found to result in a loss of

function. This deficiency would not have resulted in the RCIC system becoming

inoperable due to a loss of air to the lube oil cooler pressure control valve.

(Section 4OA5.2.1.2).

A contributing cause of this finding is related to the cross cutting area of Problem

Identification and Resolution. The licensee had previously reviewed the failure

positions of air-operated equipment and issued a report, Compressed Air

Systems, dated July 16, 1989. During this review, the licensee did not identify

that the pressure control valve was not independent of the instrument air system.

!

Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Action, because the licensee failed to correct a

longstanding non-conformance in the operation of pressure control valve PCV-

13-23. The team determined through interviews with Vermont Yankee staff that

during initial start-up testing, problems were identified with the automatic

operation of this valve which affected its ability to properly supply cooling flow to

the RCIC lube oil cooler. This issue was more than minor because it was

associated with the Mitigating Systems attribute of Equipment Performance and

affected the cornerstone objective of ensuring the reliability of the RCIC system.

The issue screened as very low safety significance in Phase I of the SDP

because it was a design deficiency that was not found to result in a loss of

function. The licensee had implemented manual actions as a compensatory

Enclosure

v

measure for the operation of PCV-13-23 through the addition of procedural

steps. (Section 4OA5.2.1.2)

!

Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, because the licensee had neither established the

correct condensate storage tank (CST) temperature limit for use in the plant

transient analyses nor translated the CST temperature limit into plant

procedures. This issue was more than minor because it was associated with the

Mitigating Systems Cornerstone attribute of Equipment Performance and

affected the cornerstone objective of ensuring the reliability of the core spray

system. The issue screened as very low safety significance in Phase I of the

SDP because it was a design deficiency that was not found to result in a loss of

function. Although available net positive suction head (NPSH) margin for the

core spray pumps was lowered, adequate margin remained due to the

conservatism that existed in other aspects of the licensees NPSH analysis.

(Section 4OA5.2.1.7)

A contributing cause of this finding is also related to the cross-cutting area of

Problem Identification and Resolution. The licensee identified this issue in

December 2002, but concluded that the non-conservative CST temperature had

little to no effect on the transient analyses.

!

Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, because between June 2001 to September 2004,

the licensee did not adequately coordinate between the operations department

and the engineering organization regarding procedure revisions that increased

the length of time required to place the reactor core isolation cooling system in

service from the alternate shutdown panels. This issue was more than minor

because it was associated with the Mitigating Systems Cornerstone attribute of

Human Performance and affected the cornerstone objective of ensuring the

availability of the RCIC system. Furthermore, this finding resulted in the use of

the December 1999 value of time to place RCIC in service from the alternate

shutdown panel in documents submitted to the NRC as part of the Vermont

Yankee Power Uprate Safety Analysis Report. The issue screened as very low

safety significance in Phase I of the SDP because it was a design deficiency that

was not found to result in a loss of function. Although the available time margin

was lowered, sufficient margin remained to allow operator action to manually

start the RCIC system prior to reactor level reaching the top of active fuel.

(Section 4OA5.2.2)

!

Green. The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion XI, Test Control, because the licensee had conducted motor-operated

valve (MOV) diagnostic tests using procedures that did not include acceptance

limits, which were correlated to and based on applicable (stem thrust and torque)

design documents. Additionally, MOV diagnostic testing had been conducted

solely from the motor control centers using test instrumentation that had not

been validated to ensure its adequacy. The finding was more than minor

because it affected the Mitigating Systems Cornerstone attribute of Equipment

Performance and affected the cornerstone objective of ensuring the availability,

Enclosure

vi

reliability, and capability of systems and components that respond to initiating

events. Specifically, the unvalidated test method had the potential to affect the

reliability of safety-related motor-operated valves. The issue screened as very

low safety significance in Phase I of the SDP because it was a qualification

deficiency that was not found to result in a loss of function. The team did not

identify any examples of degraded or inoperable valves during the inspection

and noted that the design basis calculations for the MOVs reviewed had

available thrust margin of greater than 60 percent. (Section 4OA5.2.3)

B.

Licensee Identified Violations

None.

Enclosure

REPORT DETAILS

4OA2 Problem Identification and Resolution (PI&R)

2.

Annual Sample Review

Not applicable.

3.

Cross Reference to PI&R Findings Documented Elsewhere

Section 2.1.2 (b) 1 of this report describes a finding associated with a design

vulnerability of the reactor core isolation cooling (RCIC) system lube oil cooling pressure

control valve in that the valve design was not independent of station service air as

described in the Updated Final Safety Analysis Report. The licensee had previously

reviewed the failure positions of air-operated equipment and issued a report,

Compressed Air Systems, dated July 16, 1989. This longstanding deficiency was not

identified by this review or by other station service air reviews.

Section 2.1.7 (b) of this report describes a finding associated with maintaining the

condensate storage tank temperature within limits assumed in the facilitys transient

analysis. The licensee had identified conditions where the tank temperature had

exceeded the transient analysis assumptions but had not taken sufficient corrective

actions.

4OA5 Other Activities - Temporary Instruction 2515/158

1.

Inspection Sample Selection Process

In selecting samples for review, the team focused on the most risk-significant

components and operator actions. The team selected these components and operator

actions by using the risk information contained in the licensees Probabilistic Risk

Assessment (PRA) and the US Nuclear Regulatory Commissions (NRCs) Simplified

Plant Analysis Risk (SPAR) models. An initial sample was chosen from those

components and operator actions that had a risk achievement worth factor greater than

two. These components and operator actions are important to safety since their

assumed failure would result in at least doubling the risk of an accident that could result

in core damage. Consideration was also given to those components and operator

actions most impacted by the licensees request for a 20 percent extended power uprate

(EPU) license amendment.

Many of the samples selected were located within the reactor core isolation cooling,

main feedwater, safety relief valve, onsite electrical power, and off-site electrical power

systems. In addition, inspection samples were added based upon operational

experience reviews. The team was also briefed by the NRCs technical staff conducting

the EPU licensing review on issues that had arisen during their reviews, indicating areas

that might warrant additional inspection. A complete listing of all components, operator

actions and operating experience issues reviewed by the inspection team is contained in

Attachment A to this report. A total of 91 samples were chosen for the teams initial

review.

2

Enclosure

A preliminary review was performed on the 91 samples to determine whether any low-

margin concerns existed. For the purpose of this inspection, margin concerns included

original design issues, margin reductions due to the proposed EPU or margin reductions

identified as a result of material condition issues. Consideration was also given to the

uniqueness and complexity of the design, operating experience, and the available

defense-in-depth margins. Based upon the above considerations, 45 of the original 91

samples were selected for a more detailed review. An overall summary of the reviews

performed and the specific inspection findings identified is included in the following

sections of the report.

2.

Results of Detailed Reviews

The team performed detailed reviews on the 45 components, operator actions and

operating experience issues. For components, the team reviewed the adequacy of the

original design, modifications to the original design, maintenance and corrective action

program histories, and associated operating and surveillance procedures. As practical,

the team also performed walkdowns of the selected components. For operator actions,

the team reviewed the adequacy of operating procedures and compared design basis

time requirements against actual demonstrated timelines. For the operating experience

issues chosen for detailed review, the team assessed the issues applicability to

Vermont Yankee and the licensees disposition of the issue. The following sections of

the report provide a summary of the detailed reviews, including any findings identified by

the inspection team.

2.1

Detailed Component and System Reviews

2.1.1

Electrical Power Sources

a.

Inspection Scope

The team reviewed the adequacy of the onsite and off-site electrical power

sources that supply power to the safety-related components chosen for detailed

review. Particular focus was paid to the off-site power sources and grid stability,

to the extent they would be impacted by an EPU. The teams review

encompassed the licensees plans to limit the initial power increase to

15 percent, as a capacitor bank necessary to provide reactive power to the grid

to ensure stability had yet to be installed. Other attributes of the electrical

systems reviewed during the inspection were operating procedures, setpoints for

degraded voltage relays, battery capacity, circuit breaker coordination, fast and

slow transfer schemes, Technical Specifications (TS) and other related

calculations.

The team conducted a walkdown of the safety-related switchgear rooms and the

electrical controls in the main control room with station engineering personnel.

The review was conducted to identify any alignment discrepancies or visible

signs of significant deficient material conditions.

3

Enclosure

The team also performed a detailed, focused review of the ability of the Vernon

Hydro-Electric Station to supply emergency power to Vermont Yankee in the

event of a station blackout (SBO) caused by a grid disturbance, as required by

10 CFR Part 50.63, Loss of all Alternating Current Power, and as clarified by

Regulatory Guide 1.155, Station Blackout, and NUMARC 87-00, Revision 1. The

team reviewed procedures associated with the operator actions necessary to tie

in the Vernon Station, procedures associated with the operation and

maintenance of the Vernon Station, and regional grid operator system

restoration procedures. The team also visited the remote control location for the

Vernon Station, and interviewed station personnel. Lastly, the team conducted a

conference call with the regional grid operator responsible for controlling the

operation of circuit breakers and switches in the Vernon switchyard.

b.

Findings

(1)

Availability of Power from Vernon Station

Introduction. The team identified a Green non-cited violation of 10 CFR Part

50.63, Loss of All Alternating Current Power, because the licensee had not

completed a coping analysis and had not demonstrated, by test, the time

required to make the alternate alternating current (AC) source available for an

electrical grid collapse resulting in a station blackout.

Description. 10 CFR Part 50.63 requires that licensees be able to recover from

an SBO that results from a loss of all AC electrical power (both the normal off-

site power sources and the on-site emergency diesel generators). In Section

C.2, Offsite Power, Regulatory Guide 1.155 defines the minimum potential

causes to be considered for a loss of off-site power that results in an SBO. One

listed cause is grid undervoltage and collapse. For SBO scenarios where the

licensee cannot demonstrate by test that an alternate AC source would be

available within 10 minutes, 10 CFR Part 50.63 requires the licensee to complete

a coping analysis for the period of time it would take for power to be restored.

At Vermont Yankee, the licensee credits the Vernon Hydro-Electric Station as its

alternate AC source to respond to a station blackout within 10 minutes. If a grid

collapse occurs, the Vernon Station would trip offline and have to be restarted.

The Vernon Station is considered a black start facility by the regional grid

operator. As such, the Vernon Station is required to certify it can be ready to

supply power within 90 minutes after tripping off line. However, in order to

supply power to Vermont Yankee under such conditions, the Vernon switchyard

would have to be configured to isolate the Vernon Station from the rest of the

grid. The operation of the circuit breakers necessary to complete such actions is

not controlled by either the licensee or the Vernon Station, but is controlled by

the regional grid operator. The team held a conference call with the grid

operators. During the call, the team learned that no specific procedures or

communication protocols had been set up to deal with a station blackout at

Vermont Yankee. The only reference to Vermont Yankee was a general

4

Enclosure

statement in a procedure that said that nuclear generators should receive critical

priority. During the call, the team also learned that the grid operator did not

differentiate between situations where normal off-site power was lost to a nuclear

unit but emergency diesels remain available, and those situations where the

emergency diesel generators failed to start and the station was in a true blackout

condition. The team learned that no specific training, testing, or simulations had

been conducted to simulate the actions that would have to be taken to respond

to an SBO at Vermont Yankee caused by a grid collapse.

As a result of the teams concerns, the licensee issued condition reports (CRs)

CR-VTY-2004-2677 and 2004-2738. The licensee also created a preliminary

timeline which estimated the time to restore power under such conditions as

being between 20 minutes and 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The licensee also performed an

operability evaluation in accordance with Generic Letter 91-18, which included a

preliminary four-hour coping analysis. The licensee provided the team a copy of

the preliminary coping analysis and copies of the original NRC Safety Evaluation

Report (SER) for the station blackout rule dated September 1, 1992. The team

reviewed the preliminary coping analysis and found the methodology used to be

reasonable. Review of the NRC SER indicated that questions were asked by the

NRC staff regarding a regional grid disturbance during the original station

blackout review, and that the licensees response was that power would be

restored within one hour. Based upon the above facts, the team determined that

the one hour time stated in the SER could no longer be ensured. Furthermore,

contrary to 10 CFR Part 50.63, the licensee had not completed a coping analysis

for the period of time it would take to restore the alternate source.

Analysis. The team determined that this issue was a performance deficiency

since the licensee had not demonstrated by test that the Vernon Station could

supply power to Vermont Yankee within one hour after the onset of a station

blackout and had not completed a coping analysis for the period of time the

Vernon Station would be unavailable, as required by 10 CFR Part 50.63. Also,

the licensee did not remain cognizant of how design changes, made by the

operator of the Vernon Station, affected the ability of the Vernon Station to

supply emergency power to Vermont Yankee in a timely manner. This issue was

more than minor because it was associated with the Mitigating Systems

Cornerstone attribute of Equipment Performance and affected the cornerstone

objective of ensuring availability, reliability, and capability of systems needed to

respond to a station blackout resulting from a grid collapse. The issue screened

as very low safety significance (Green) in Phase I of the SDP because it was a

design deficiency that was not found to result in a loss of function. Specifically,

the team found that the licensees preliminary coping analysis, performed during

the inspection, demonstrated a four-hour coping time that should be sufficient to

envelope the time required to start and align the Vernon Station.

Enforcement. 10 CFR Part 50.63(c)(2), requires that a coping analysis be

performed if the designated alternate AC source cannot be made available within

10 minutes. It also requires that the time required to make the alternate AC

5

Enclosure

source available be demonstrated by test. Contrary to the above, the licensee

had not completed a coping analysis for the period of time the alternate AC

source would be unavailable and had not demonstrated by test the time required

to make the alternate source available for a station blackout involving a grid

collapse. Because this finding is of very low safety significance and the licensee

entered this issue into its corrective action program (CR-VTY-2004-2677 and

2004-2738), it is considered a non-cited violation consistent with Section VI.A.1

of the NRCs Enforcement Policy. (NCV 05000271/2004008-01 Availability of

Power from Vernon Station)

(2)

Procedures for Assessing Off-site Power Operability

Introduction. The team identified a Green non-cited violation of Technical

Specifications 6.4, Procedures, because the licensee did not establish

adequate procedures for assessing the operability of the 115 kilovolt (kV) Keene

line.

Description. At Vermont Yankee, the immediate access off-site power source is

normally derived from the 345 kV switchyard through the 345/115 kV transformer

T-4-1A. The 115 kV Keene line may also be conditionally used as an alternate

immediate access source for satisfying TS requirements for off-site power

supplies, depending on grid and plant conditions. Specifically, Technical

Specification Bases 3.10.A, states that the availability of the Keene line is

dependent on its pre-loading which must be limited by the system dispatchers

prior to it being declared an immediate access source.

The team reviewed Procedure ON 3155, Loss of Auto Transformer, and noted

that Step 2b, instructs operators to contact ISO New England to determine the

115 kV Keene line load limit but does not provide explicit criteria for evaluating

the lines operability. The team also noted Note 5 on the load nomograph

included in procedure ON 3155, Reference D, Guidelines for Operating the

Vermont Yankee 115 kV System with the VTY4 Auto Transformer Out of

Service, stated the assumption that, All Vermont Yankee motor startups

performed sequentially, not simultaneously. During accident loading with off-

site power available, all safety loads are designed to block start simultaneously,

so this assumption would never be met.

The team noted the procedure also contained invalid criteria for assessing the

operability of the downstream safety buses. Step 11 allowed operation of bus 3

or 4 with voltages as low as 3600 volts (V) AC. This voltage was below the TS

allowable setting of 3660 VAC for the degraded voltage relays. Under non-

accident conditions, operation of the buses at this minimum voltage would result

in automatic actuation of the degraded voltage relays, separating the buses from

off-site power. Under post-accident conditions, the degraded voltage protection

relays are locked out and operation of the buses at 3600 VAC could result in

equipment mis-operation or damage.

6

Enclosure

Analysis. The team determined this to be a performance deficiency since the

operating procedures did not provide adequate guidance for determining

operability of the 115 kV Keene line. This issue was more than minor because it

was associated with the Mitigating Systems Cornerstone attribute of Procedure

Quality and affected the cornerstone objective of ensuring availability, reliability,

and capability of systems needed to respond to a loss of off-site power. The

issue screened as very low safety significance (Green) in Phase I of the SDP

because the failure to translate design requirements into operating procedures

was a design deficiency that was not found to result in a loss of function.

Specifically, the team did not identify any instances where the lack of procedural

guidance had resulted in an inadequate assessment of off-site power operability

or the inoperability of the electrical system or any components.

Enforcement. Technical Specifications 6.4.C, Procedures, requires that written

procedures be established, implemented, and maintained for actions to be taken

to correct specific and unforeseen potential malfunctions of systems or

components. Contrary to the above, the licensee did not establish adequate

procedures for assessing the operability of the 115 kV Keene line. Since this

finding is of very low safety significance and has been entered into the licensees

corrective action program (CR-VTY-2004-2803 and CR-VTY-2004-2804), it is

considered a non-cited violation, consistent with Section VI.A.1 of the NRC

Enforcement Policy. (NCV 05000271/2004008-02 Procedures for Assessing

Off-site Power Operability)

(3)

Degraded Voltage Relay Setpoint Calculations

Introduction. The team identified a Green non-cited violation of 10 CFR Part 50

Appendix B, Criterion III, Design Control, because the licensee did not use the

Technical Specification allowed voltage value in the calculations used to ensure

the degraded voltage relay dropout function would provide adequate voltage to

safety-related electrical equipment.

Description. As described in Section 8.5 of the Vermont Yankee Updated Final

Safety Analysis Report (UFSAR), the licensee has installed degraded voltage

relays, which are designed to protect the stations electrical equipment from

damage that could occur due to degraded voltage. The licensees Technical

Specifications (TS) allow a minimum degraded voltage relay setpoint of 3660

VAC; however, the licensees analysis of record, VYC-1088 Vermont Yankee

4160/480 Volt Short Circuit/ Voltage Study, did not evaluate the operability of

the connected electrical components at this minimum TS value. Instead, the

lowest voltage evaluated by VYC-1088 was based on the minimum expected

switchyard voltages, which were 3951 VAC for bus 3 and 3809 VAC for bus 4.

Consequently, motors were evaluated for voltage considerably above the

minimum voltage that could occur based on the TS value.

7

Enclosure

As a result, calculation VYC-1053 and VYC-1314, which determine worst-case

motor-operated valve (MOV) and motor control center (MCC) voltages, were also

non-conservative. In response to the teams concerns, the licensee initiated CR-

VTY-2004-2596. The operability determination (OD) for CR-VTY-2004-2596

identified two motors that did not meet calculation acceptance criteria and

provided justification for their operability. This OD also provided justification for

lower MCC control circuit voltages than previously analyzed. The licensee also

initiated CR-VTY-2004-2734 to address the effects of the postulated lower

voltage on MOV operation. The effect on the MOVs was not expected to be

significant due to the otherwise generally conservative approach used for MOV

calculations.

Analysis. The team determined this to be a performance deficiency because the

licensees calculations did not ensure the operability of electrical equipment at

the minimum TS value for the degraded voltage relay dropout setting. This issue

was more than minor because it was associated with the Mitigating Systems

Cornerstone attribute of Equipment Performance and affected the cornerstone

objective of ensuring availability, reliability, and capability of systems needed to

respond to a design basis accident. The issue screened as very low safety

significance (Green) in Phase I of the SDP because it was a design deficiency

that was not found to result in a loss of function. Specifically, the team did not

identify any instances where using the Technical Specification degraded voltage

allowable setpoint values would have resulted in inoperable equipment.

Enforcement. 10 CFR Part 50, Appendix B, Criterion III, Design Control,

requires that measures be established to assure that applicable regulatory

requirements and the design basis for structures, systems and components are

correctly translated into specifications, drawings, procedures and instructions.

Contrary to the above, the licensee used incorrect and non-conservative voltage

values in calculations performed to ensure that electrical equipment would

remain operable under degraded voltage conditions. Since this finding is of very

low safety significance and has been entered into the licensees corrective action

program (CR-VTY-2004-2596 and CR-VTY-2004-2734), it is considered a non-

cited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000271/2004008-03 - Degraded Voltage Relay Setpoint

Calculations)

(4)

Ungrounded 480 VAC Electrical System.

The team identified an unresolved item (URI) associated with the 480 VAC

circuit-breakers designed to detect and interrupt electrical malfunctions. An

unresolved item is an issue requiring further information to determine if it is

acceptable, if it is a finding or if it constitutes a deviation or violation of NRC

requirements. In this case, additional review will be required to determine if the

facility is in accordance with its design and/or licensing basis, since this was part

8

Enclosure

of the original design of the facility. Also, additional review will be required to

determine the safety significance of this issue.

The Vermont Yankee 480 VAC system consists of two 480 VAC load center

buses supplied through separate 4160/480 V transformers from the redundant

4160 VAC safety buses. The transformers are connected delta-delta and the

480 VAC system is ungrounded. Several non-safety related loads are supplied

from the safety-related load center buses and from safety-related MCCs. These

non-safety loads are not automatically disconnected during postulated accidents

but rather are shed manually depending on the specific accident scenario. The

load centers are equipped with 600 ampere circuit-breakers with long-time and

short-time, or long-time and instantaneous trip devices. The MCCs are equipped

with magnetic breakers with thermal overloads or thermal/magnetic breakers.

Each bus is provided with a ground detection system which consists of three

ground detection voltmeters and three potential transformers. The system only

provides local indication at the MCCs and does not annunciate in the control

room. The control room relies on the auxiliary operator round sheet voltage

recordings of the ground detection voltmeters to be informed of any ground fault

on the 480 V system. The ground detector does not actuate any protective

devices or indicate the location of the fault.

The team identified that since the 480 VAC electrical system at Vermont Yankee

is ungrounded, an arcing/intermittent ground fault could cause excessive

voltages to be impressed upon the system. Such a ground could begin on non-

safety related equipment that is unprotected from the effects of a postulated high

energy line break or seismic event. The installed electrical protective devices

designed to provide isolation between the safety and non-safety related loads

may not open during this scenario because the ungrounded system may not

provide a return current path until a second ground was formed. While such a

ground could possibly be detected with the installed ground detection

instrumentation, there would likely be insufficient time to detect and isolate the

ground before damage could occur to safety-related motors due to the possible

excessive voltages. (URI 05000271/2004008-04 - Ungrounded 480 VAC

Electrical System)

2.1.2

Reactor Core Isolation Cooling (RCIC) System

a.

Inspection Scope

During the inspection, the team reviewed selected RCIC system components to

ensure they would be capable of performing their required design functions for

both current licensing basis conditions and the proposed EPU conditions. The

team reviewed the RCIC pump and turbine, auxiliary equipment, various system

valves, and instrumentation and controls. The team conducted plant equipment

walkdowns, reviewed plant operating and test procedures, condition reports, test

9

Enclosure

results, maintenance history, vendor manuals, drawings, design calculations and

applicable sections of the UFSAR and the TS.

10

Enclosure

b.

Findings

(1)

Control Valve for RCIC Lube Oil Cooler

Introduction. The team identified a Green non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, because the cooling water supply to

the lube oil cooler of the RCIC system was not installed as described in the RCIC

system design basis. Specifically, the pressure control valve for the lube oil

cooler water supply was not independent of air systems, and the piping between

the pressure control valve and lube oil cooler did not contain a restricting orifice.

Description. During a review of drawing G-191174, Sheet 2, Flow Diagram -

Reactor Core Isolation Cooling, Revision 23, the team noted that a pressure

control valve, PCV-13-23, was shown as having a connection to station

instrument air. The team noted that USFAR Section 4.7.5 stated that all

components necessary for initiating operation of RCIC were completely

independent of auxiliary ac power and station service air. The station instrument

air and service air systems are interconnected and are supplied from four AC

powered air compressors connected in parallel. Both the station instrument air

and service air systems are classified as non-nuclear safety related. The team

questioned the effect of the loss of the air supply to this valve. PCV-13-23 was

installed in the 2-inch cooling water supply line to the RCIC pump lube oil cooler

to regulate the flow of the cooling water supply from the RCIC pump discharge.

A relief valve, SR-13-26, was installed between PCV-13-23 and the lube oil

cooler for overpressure protection.

In response to the teams questions, the licensees engineering personnel

investigated this condition and determined that PCV-13-23 would fail in the fully

open position upon a loss of air. The licensee performed a hydraulic analysis of

the affected portion of the RCIC system during the inspection. The analysis

determined that fully opening the pressure control valve would have resulted in a

flow of approximately 170 gpm through the valve, as opposed to the design flow

of 16 gpm. The analysis also determined that the lube oil cooler, which has a

design pressure of 150 pounds per square inch gauge (psig), would have been

exposed to a maximum pressure of approximately 1100 psig. Both relief valve

SR-13-26 and relief valve SR-13-27, installed on the RCIC pump barometric

condenser, would have opened to pass the expected flowrate. The licensees

investigation determined that this condition has existed since the original

operation of the RCIC system.

The licensee documented this issue in condition report CR-VTY-2004-2535 and

performed an operability determination, which the team reviewed. The

operability determination stated that a loss of air was considered unlikely during

any of the events where the RCIC system was credited. It also concluded that, if

the air supply was lost, the lube oil cooler and associated piping components

would not rupture when exposed to the expected pressures. This was based, in

part, on vendor testing which showed that there was significant margin above

11

Enclosure

1100 psig before these components would rupture. With regard to the potential

loss of RCIC system capacity, the determination concluded that the RCIC pump

would have sufficient capacity to provide the required flow to the reactor vessel

even with the expected flow diversion. The licensee also initiated condition report

CR-VTY-2004-2536 because the RCIC design basis document identified PCV-

13-23 as a self-contained pressure control valve.

The licensee performed a limited extent-of-condition review during the inspection

to verify that a similar condition did not exist for other air-operated components.

No additional concerns were identified by the licensee during this review. The

team also performed an independent sampled-based review and did not identify

any additional issues. The licensee stated that a full extent-of-condition review

would be performed as part of the resolution of CR-VTY-2004-2535. At the time

of the inspection, the licensee was developing a plan to correct this design

deficiency.

The team also noted that the piping between the pressure control valve and lube

oil cooler did not contain a restricting orifice as described in the UFSAR. UFSAR

Figure 4.7-3 indicated that a flow-restricting orifice was installed downstream of

valve PCV-13-23. No such orifice exists in the system. The licensee initiated

condition report CR-VTY-2004-2537 to document this concern.

Analysis. The team determined this issue was a performance deficiency since

the licensee had not instituted measures to ensure that the RCIC system was

installed consistent with its design and licensing basis. This issue was more

than minor because it was associated with the Mitigating Systems Cornerstone

attribute of Equipment Performance and affected the objective of ensuring the

reliability of the RCIC system. The issue screened as very low safety

significance in Phase I of the SDP, because it was a design deficiency that was

not found to result in a loss of function. This deficiency would not have resulted

in the RCIC system becoming inoperable due to a loss of air to the lube oil cooler

pressure control valve.

A contributing cause of this finding is related to the cross cutting area of Problem

Identification and Resolution. The licensee had previously reviewed the failure

positions of air-operated equipment and issued a report, Compressed Air

Systems, dated July 16, 1989. During this review, the licensee did not identify

that the pressure control valve was not independent of the instrument air system.

In addition, the licensee did not fully assess all aspects of the issue associated

with the pressure control valve being supplied by instrument air rather than being

self contained in its initial operability determination associated with CR-VTY-

2004-2535. The licensee had to complete two additional supplemental

operability determinations to resolve the teams concerns.

Enforcement. 10 CFR Part 50 Appendix B, Criterion III, Design Control,

requires, in part, that design control measures be established and implemented

to assure that applicable regulatory requirements and the design basis for

12

Enclosure

structures, systems, and components are correctly translated into specifications,

drawings, procedures, and instructions. Contrary to the above, the licensee did

not implement measures to ensure that the design basis for the cooling water

supply to the lube oil cooler of RCIC was correctly translated into the

specifications, drawings, procedures, or instructions. Specifically, the installed

pressure control valve in the lube oil cooler water supply line was not

independent of air systems, and the installed piping between the pressure

control valve and lube oil cooler did not contain a restricting orifice. Because this

violation is of very low safety significance and has been entered into the

licensee's corrective action program (CR-VTY-2004-2535), this violation is being

treated as a non-cited violation consistent with Section VI.A of the NRC

Enforcement Policy. (NCV 05000271/2004008-05 Cooling Water Supply

Portion of RCIC Not Installed per Design Basis)

(2)

Failure To Correct Non-Conforming RCIC Pressure Control Valve

Introduction. The team identified a Green non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, because the licensee failed to

correct a longstanding non-conformance associated with PCV-13-23, the control

valve that supplies cooling water to the RCIC lube oil cooler.

Description. During review of Operating Procedure (OP) 2121, Reactor Core

Isolation Cooling System, and OP 4121, Reactor Core Isolation Cooling

System Surveillance, the team identified that these procedures contained steps

to manually operate PCV-13-23 during RCIC operation. The team questioned

the reason for these steps, given that the RCIC system is designed to function

automatically as described in UFSAR Section 4.7.4.

The team determined that during initial start-up testing, problems were identified

with the automatic operation of this valve. These problems affected its ability to

properly regulate the supply of cooling flow to the lube oil cooler. During the

inspection, the licensee could not provide the team with an open condition report

identifying this problem. Additionally, the licensee did not have an analysis to

show that setting PCV-13-23 as described in the procedure would ensure an

adequate flow of cooling water to the lube oil cooler. Rather, the licensee used

the fact that RCIC bearing temperatures have been acceptable during

surveillance testing to justify that lube oil cooling was sufficient. However, the

team noted that the conditions that exist during surveillance testing may be

different from those existing under design conditions (for example, use of a

higher temperature suppression pool as a suction source and operation with

maximum expected RCIC room temperature). These conditions would result in

higher bearing temperatures when RCIC is operating under design conditions.

The team reviewed alarm response procedures for the RCIC bearing

temperature alarms and determined that they were adequate to prevent damage

to major RCIC components if the cooling flow was inadequate. However, the

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Enclosure

manual operation of PCV-13-23 represents a longstanding operator work-around

that creates an additional operator burden and could challenge equipment

reliability if called upon to operate during an event.

Analysis. The team determined that the licensees failure to correct a

longstanding non-conformance with PCV-13-23 was a performance deficiency.

Specifically, operation of this valve in a mode other than automatic may have

challenged system operation if needed for an actual event. This issue was more

than minor because it was associated with the Mitigating Systems attribute of

Equipment Performance and affected the cornerstone objective of ensuring the

reliability of the RCIC system. The issue screened as very low safety

significance (Green) in Phase I of the SDP, because it was a design deficiency

that was not found to result in a loss of function. While PCV-13-23 did not

function automatically as designed, the licensee had implemented manual

actions as a compensatory measure for the operation of this valve.

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

requires that measures be established to assure that conditions adverse to

quality, such as failures, malfunctions, deficiencies, deviations, defective material

and equipment, and non-conformances are promptly identified and corrected.

Contrary to the above, the licensee failed to correct a longstanding non-

conformance associated with PCV-13-23, the control valve that supplies cooling

water to the RCIC lube oil cooler. Because this issue is of very low safety

significance and has been entered into the licensees corrective action program

(CR-VY-2004-2535), this issue is being treated as a non-cited violation,

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

(NCV 05000271/2004008-06 Failure To Correct Non-Conforming RCIC

Pressure Control Valve)

(3)

Potential Preconditioning of RCIC MOVs

The team identified a minor finding related to Vermont Yankees method of

testing RCIC system MOVs. The team determined that a procedural

requirement to conduct the quarterly RCIC system pump operability test prior to

system MOV surveillance testing resulted in the operation of several RCIC

system valves immediately before their required stroke-time testing. This

practice could have affected the results of the stroke-time testing by

preconditioning the valves and this potential impact was not evaluated by the

licensee. This issue was evaluated using Inspection Manual Chapter 0612 and

determined to be minor because it applied to a limited number of valves, most of

the valves would not have affected system operability, a review of these valves

performance history indicated that there was significant margin to stroke-time

limits, and no operability issues were noted during past testing.

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Enclosure

2.1.3 Residual Heat Removal System (RHR)

a.

Inspection Scope

During the inspection, the team reviewed selected components of the RHR

system to ensure the system and components would be capable of performing

their required design functions, for both current conditions and those conditions

that would exist under the proposed EPU. In its power uprate submittal to the

NRC, the licensee stated that it would need to take credit for the containment

overpressure that would exist under postulated accident conditions in order to

ensure adequate net positive suction head (NPSH) was available to the RHR

pumps. The team did not assess the appropriateness of allowing credit for

containment overpressure. The team did, however, perform specific reviews of

the licensees calculations to ensure that the RHR pumps would have adequate

NPSH assuming such credit is given. The teams review included pressure

losses associated with the RHR suction strainers, potential bubble ingestion and

the potential for torus vortexing.

b.

Findings

No findings of significance were identified.

2.1.4

Safety Relief Valves and Code Safety Valves

a.

Inspection Scope

Due to the increased steam flow that would result from the licensees proposed

EPU, the team conducted a detailed review of General Electric (GE) Topical

Report T0900, which evaluated the adequacy of the safety relief valves (SRVs)

for EPU conditions. The team reviewed the GE analysis and licensee

modification package associated with the installation of a third American Society

of Mechanical Engineers (ASME) Code safety valve with increased relief

capacity for EPU conditions. The team also reviewed the out-of-service and

calibration history for the existing SRVs. Lastly, the team reviewed the back-up

nitrogen bottle system, which was added to ensure an adequate supply of

nitrogen to the SRVs.

b.

Findings

No findings of significance were identified.

2.1.5

Reactor Feedwater and Condensate Components

a.

Inspection Scope

Due to the increased feedwater flow that would be required under the licensees

proposed EPU, the team assessed the adequacy of modifications to the reactor

15

Enclosure

feedwater system. Because of the increased feedwater flow requirements, the

licensee would need to run all three reactor feedwater pumps under EPU

conditions, reducing the capability to mitigate feedwater transients. Included

within the teams review was a recent seal replacement on a feedwater pump

and modifications to the reactor feedwater pump low-suction pressure trip and

reactor recirculation system runback. The team also reviewed flow control valve

FCV-102-4 and its associated controls, since failure of this valve to open could

disable low flow capability for the condensate pumps, resulting in a loss of

feedwater flow during low-flow demands.

The team reviewed aspects of the licensees Flow Assisted Corrosion (FAC)

Program and reviewed the adequacy of the thermal sleeves located at

connections between the RCIC and feedwater systems and the reactor vessel.

The team conducted a walkdown of the main feedwater and condensate pumps

and adjacent piping with Vermont Yankee engineering personnel. Lastly, the

team inspected the feed and condensate panels in the main control room. The

reviews were conducted to identify any alignment discrepancies or visible signs

of deficient material conditions.

b.

Findings

No findings of significance were identified.

2.1.6

Reactor Building-to-Torus Vacuum Breaker System

a.

Inspection Scope

The team reviewed the components associated with the reactor building-to-torus

vacuum breaker system. This system includes two redundant air-operated

vacuum breaker valves, each in series with a check valve. This system functions

to relieve pressure from the reactor building to the torus to protect the structural

integrity of the torus. Additionally, the system must remain leak-tight from the

torus to the reactor building to maintain primary containment isolation. In

reviewing these components, the team assessed condition reports, operating

procedures, test results, maintenance and modification history, drawings and

applicable sections of the UFSAR and TS. The teams review included

verification that these components would be capable of performing their required

design functions for both current licensing basis conditions and the proposed

EPU conditions.

The team also completed a walkdown of the reactor building-to-torus vacuum

breakers and their air-operators, check valves and associated piping.

Additionally, the team reviewed operator burden and work-around lists to identify

any deficiencies that could affect operation of these components.

16

Enclosure

b.

Findings

No findings of significance were identified.

2.1.7

Review of Transient Analysis Inputs

a.

Inspection Scope

During the inspection, the team reviewed selected plant parameters used by the

licensee as inputs into its transient analyses. Included in this review were

analyses performed solely to support the proposed EPU. In conjunction with this

review, the team conducted plant equipment walkdowns, reviewed plant

procedures and calculations, and discussed calculations and parameters with

plant design engineers.

b.

Findings

Introduction. The team identified a finding of very low safety significance

involving a non-cited violation of 10 CFR Part 50, Appendix B, Criterion III,

Design Control, because the licensee had neither established the correct

condensate storage tank (CST) temperature limit for use in the plant transient

analyses nor translated this CST temperature into plant procedures.

Description. During the inspection, the team noted that although the CST

temperature was monitored on operator logs, the licensee had not established a

maximum temperature limit for the CST. A CST temperature limit of 90 degrees

Fahrenheit (EF) was used as an input to several plant transient analyses,

including Transient Analysis VYC-1825, Analysis of Suppression Pool

Temperature for Relief Valve Discharge Transients, Revision 0. The CST

temperature used for this analysis was based on the maximum ambient summer

temperature of approximately 90EF and did not take into account the recirculated

hotwell water that has on occasion raised the CST temperature to approximately

120EF.

In addition, the team noted that in December 2002, the licensee had also

identified that there was no maximum CST temperature limit and that CST

temperature had previously exceeded the temperature assumed in the high

pressure coolant injection (HPCI) and RCIC design basis documents for

calculating pump NPSH. The licensee documented this condition in CR-VTY-

2002-2942. At that time, the licensee performed a limited evaluation and

determined that the non-conservative CST temperature had little to no effect on

the transient analyses. The team reviewed this evaluation and determined that

transient analysis VYC-1825, which assessed the adequacy of the NPSH of the

pumps supplied from the CST or the suppression pool, would be affected by the

increased CST temperature.

17

Enclosure

In response to the teams concerns, the licensee reviewed the transient analyses

and identified that the relief valve discharge transient was the most limiting. The

licensee determined that using the higher CST temperature of 120EF led to an

increase in suppression pool temperature, which reduced the net positive suction

head margin for the most limiting component, the core spray pumps, from 0.5

feet to 0.0 feet. The team reviewed the input parameters to the NPSH

calculation for the core spray pumps and determined that because of

conservatism in other aspects of the calculation, the core spray pumps would still

have adequate NPSH to remain operable.

The team determined that in the licensees EPU submittal to the NRC, the

licensee had not taken into account the higher CST temperature for all transient

scenarios. As a result of this issue, the licensee began an extent-of-condition

review of all calculations, drawings, and inputs to transient analyses where a

non-conservative maximum CST temperature was used, both for current plant

conditions (CR-VTY-2004-2600) and for analyses associated with the planned

EPU (CR-VTY-2004-2799). The licensee also instituted a tentative maximum

temperature limit of 120EF for the CST.

Analysis. The team determined this issue was a performance deficiency since

the licensee had not used the correct CST temperature in the plant transient

analysis and had not translated the CST temperature limit into the station

procedures. Specifically, using the correct CST temperature in the relief valve

discharge transient analysis resulted in a higher suppression pool temperature

and lowered the available net positive suction head to the core spray pumps.

This issue was more than minor because it was associated with the Mitigating

Systems Cornerstone attribute of Equipment Performance and affected the

cornerstone objective of ensuring the reliability of the core spray system. The

issue screened as very low safety significance (Green) in Phase I of the SDP,

because it was a design deficiency that was not found to result in a loss of

function. Although available NPSH margin was lowered, adequate NPSH for the

core spray pumps remained due to the conservatism that existed in other

aspects of the licensees NPSH analysis.

A contributing cause of this finding is also related to the cross-cutting area of

Problem Identification and Resolution. The licensee identified this issue in

December 2002, but concluded that the non-conservative CST temperature had

little to no effect on the transient analyses.

Enforcement. 10 CFR Part 50 Appendix B, Criterion III, Design Control,

requires, in part, that design control measures be established and implemented

to assure that applicable regulatory requirements and the design basis for

structures, systems, and components are correctly translated into specifications,

drawings, procedures, and instructions. Contrary to the above, the licensee had

neither established the correct condensate storage tank (CST) temperature limit

for use in the plant transient analyses nor translated the CST temperature limit

into plant procedures. Because this finding is of very low safety significance and

18

Enclosure

has been entered into the licensee's corrective action program (CR-VTY-2004-

2600, CR-VTY-2004-2793, and CR-VTY-2004-2799), this finding is being treated

as a non-cited violation consistent with Section VI.A of the NRC Enforcement

Policy. (NCV 05000271/2004008-07 Failure to Implement Adequate Design

Control for Condensate Storage Tank Temperature)

2.2

Review of Operator Actions

a.

Inspection Scope

During the inspection, the team reviewed risk-significant, time-critical operator

actions that had little margin between the time required and time available to

complete the action. The team determined the review scope and performed the

detailed review of critical operator actions using risk information contained in the

licensees PRA, Operator Task Validation Studies, Emergency Operating

Procedures (EOPs), Power Uprate Safety Analysis Report (PUSAR), Appendix R

Analyses, Off-Normal and Operating Procedures, and the licensees CR

database. The team performed a detailed review of the following time-critical

and low-margin operator actions:

Monitoring of the Vernon tie line to ensure availability as a station

blackout source.

Manual initiation of the RCIC system using alternate shutdown panels.

Initiation of the standby liquid control (SLC) system with the main

condenser failed.

Manual initiation or control of feedwater and condensate flow under

normal and transient conditions, in single element or three element

control.

Manual initiation of RCIC system from the control room.

For all the above operator action scenarios, the team verified that operating

procedures were consistent with operator actions for a given event or accident

condition and that the operators had been adequately trained and evaluated for

each action. The team also reviewed the fidelity between EOPs, pump NPSH

calculations and containment spray operation to ensure proper EOP

implementation. Control room instrumentation and alarms were also reviewed by

the team to verify their functionality and to verify alarm response procedures

were accurate to reflect the current plant configuration. Additionally, the team

performed a walkdown of accessible field portions of the reviewed systems to

assess material condition and to verify that field actions could be performed by

the operators as described in plant procedures.

19

Enclosure

The team also reviewed each operator action to assess the impact the proposed

EPU could have on further reducing the margin available for task completion and

to verify that the associated EPU plant modifications would be reviewed by the

licensee for their effect on the operators ability to complete the critical actions

within the required time parameters.

b.

Findings

Introduction. The team identified a Green non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, because the licensee did not

adequately coordinate between the operations department and the engineering

organization procedure revisions that increased the length of time required to

place the reactor core isolation cooling system in service from the alternate

shutdown panels. As a consequence, the licensee did not revise its Vermont

Yankee Safe Shutdown Capability Analysis (SSCA).

Description. The Vermont Yankee SSCA relies on the reactor core isolation

cooling (RCIC) system to be placed in service from the alternate shutdown

panels prior to reactor water level reaching the top of active fuel following a loss

of feedwater flow. In December 1999, the Vermont Yankee SSCA documented

that, for the present day 100 percent power level, it would take 25.3 minutes for

reactor water level to reach the top of active fuel following a loss of feedwater

and that it would take approximately 15 minutes to place the RCIC system in

service from the alternate shutdown panels. The Vermont Yankee SSCA

concluded adequate margin (approximately 10 minutes) existed to ensure that

the RCIC is placed in service prior to reactor water level reaching the top of

active fuel.

In June 2001 the Operations Department conducted an additional review of the

time it would take to place RCIC in service from the alternate shutdown panels.

The Operations Department determined that, using the version of the procedure

in effect in June 2001, it would take 19.3 minutes to place RCIC in service from

the alternate shutdown panels .

During the inspection, using the version of the procedure in effect during the

inspection period, the team performed a field walkdown with licensed operators

to validate that RCIC could be placed into service from the alternate shutdown

panels within 19.3 minutes. The team noted that since June 2001, the licensee

had added steps in the procedure to comply with Electrical Safety Standards.

Based on the teams validation, the total time to place RCIC in service from the

alternate shutdown panels was determined to be approximately 21 minutes. The

team concluded that this time was still within the 25.3 minute limit stated in the

Vermont Yankee SSCA.

Additionally, the team found that the licensee had not revised the December

1999 Vermont Yankee SSCA to reflect the June 2001 time estimate or present

day version of the procedure to place RCIC in service from the alternate

20

Enclosure

shutdown panels. The team also determined that the licensees engineering

organization was unaware that the time to complete the task had increased from

approximately 15 to 21 minutes and had effectively reduced the time margin

available for event mitigation from about 10 minutes to 4 minutes at the current

full power level. As a consequence, the engineering organization had not

revised the Vermont Yankee SSCA.

The team reviewed the impact the licensees proposed EPU would have on this

issue. Based on an EPU power level, the licensee calculated it would take 21.3

minutes for reactor water level to reach the top of active fuel following a loss of

feedwater. Therefore, the team concluded that for the proposed EPU, the ability

to place the RCIC in service from the alternate shutdown panels (21 minutes)

prior to reactor water level reaching the top of active fuel (21.3 minutes) is

questionable. Additionally, the team found that the December 1999 value of the

time to place RCIC in service from the alternate shutdown panel was used in

licensee Technical Evaluation (TE) 2003-065, Appendix R PUSAR Input. The

TE was then used as an input to the Vermont Yankee Power Uprate Safety

Analysis Report (PUSAR) and submitted to the NRC as part of the power uprate

application. The licensee initiated CR-VTY-2004-2552 and 2004-2614 in

response to these issues.

Analysis. The team considered this finding to be a performance deficiency since

the licensee did not coordinate between the operations department and

engineering department regarding procedure revisions which increased the time

required to place the RCIC in service from the alternate shutdown panels. This

issue was more than minor because it was associated with the Mitigating

Systems Cornerstone attribute of Human Performance and affected the

cornerstone objective of ensuring the availability of the RCIC system.

Furthermore, this finding resulted in the use of the December 1999 value of time

to place RCIC in service from the alternate shutdown panel in documents

submitted to the NRC as part of the Vermont Yankee PUSAR. The issue

screened as very low safety significance (Green) in Phase I of the SDP because

it was a design deficiency that was not found to result in a loss of function. At

the present 100 percent power level, RCIC could be placed in service from the

alternate shutdown panels prior to reactor level reaching the top of active fuel.

Enforcement. 10 Part CFR 50, Appendix B, Criterion III, Design Control,

requires, in part, that revision of documents shall be coordinated among

participating organizations. Contrary to above, between June 2001 to

September 2004, the licensee did not adequately coordinate between the

operations department and the engineering organization regarding procedure

revisions that increased the length of time required to place the reactor core

isolation cooling system in service from the alternate shutdown panels. Because

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

licensees corrective action program, it is being treated as a non-cited violation,

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

21

Enclosure

05000271/2004008-08 Failure to Coordinate Information Related to Safe

Shutdown Capability Analysis Report)

2.3

Review of Operating Experience and Generic Issues

a.

Inspection Scope

During the inspection, the team reviewed selected operating experience issues

that had been identified at other facilities for their possible applicability to

Vermont Yankee. Several issues that appeared to be applicable to Vermont

Yankee were selected for a more in-depth review. Additional consideration was

given to those issues that might be impacted by the licensees planned EPU.

The issues that received a detailed review by the team included:

An NRC inspection finding at the Point Beach Nuclear Power Station,

documented in IR 50-266/2004-004, concerning the use of a non-

conservative CST temperature in accident and transient analyses.

Licensee Event Report (LER) 2003-003-00, issued on September 29,

2003, from the Byron Station where the licensee had exceeded its

licensed maximum power level due to inaccuracies in feedwater

ultrasonic flow measurements caused by signal noise contamination.

An NRC inspection finding from the Peach Bottom Station, documented

in IR 50-277/2002-011, concerning inadequate Emergency Operating

Procedures to return the suction of the High Pressure Coolant Injection

(HPCI) system from the suppression pool to the CST in order to ensure

self-cooled HPCI lube oil temperatures remained within analyzed limits.

Information Notice 2001-13, Inadequate Standby Liquid Control Relief

Valve Margin, issued on August 10, 2001, concerning a problem

identified at the Susquehanna Station involving inadequate SLC system

relief valve margin after a power uprate increased the relief valve setpoint

pressure, thereby increasing SLC discharge pressure. This was

complicated by using a non-conservative maximum reactor vessel

pressure in accident analysis.

NRC Generic Letter (GL) 96-05, Periodic Verification of Design-Basis

Capability of Safety-Related Power-Operated Valves, pertaining to the

periodic testing of motor-operated valves. With regard to this GL, the

team reviewed the NRC safety evaluation report that documented the

NRC staffs understanding of the licensees commitments and plans for

establishing a periodic verification program. The team also reviewed

procedures, test and maintenance records, corrective action documents,

and correspondence relative to four RCIC system MOVs.

22

Enclosure

23

Enclosure

b.1

Findings

Introduction. The team identified a Green non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XI, Test Control, because the licensee conducted

periodic testing of MOVs using test instrumentation that had not been validated

to be adequate for its intended function. Additionally, the test procedures did not

incorporate requirements and acceptance limits contained in applicable design

documents.

Description. In its SER dated December 14, 2000, the NRC provided its basis

for accepting Vermont Yankees response to NRC GL 96-05, Periodic

Verification of Design-Basis Capability of Safety-Related Power-Operated

Valves. The SER documented the licensees intentions to use motor current

data acquired from the MCCs as a way of detecting actuator and valve

degradation. The SER also documented Vermont Yankees intention to verify

this testing methodology by comparing the data with direct torque and thrust

measurements at the valve over extended intervals. In addition, the SER stated

the licensee would have to determine MCC test instrumentation accuracies and

sensitivities to MOV degradation, as well as evaluate changes in MCC data and

MOV thrust and torque performance.

During the inspection, the team concluded that Vermont Yankee had not

validated the adequacy of the MCC diagnostic test instrumentation with respect

to its ability to provide detect actuator torque and stem thrust degradation that

would indicate actuator or valve degradation. A cooperative effort with

Crane-MOVATS to perform the required validation was terminated in March

2004, when the parties determined that a statistically meaningful and valid

correlation of MCC to direct diagnostic test data that would allow setting switches

could not be completed. As a result of the teams concerns, the licensee entered

this issue into the corrective action program on CR-VTY-2004-2802.

The team also identified that separate procedures (OP 5217 and OP 5287) had

been established to obtain and evaluate MCC diagnostic test data; however,

neither of these procedures included specific acceptance criteria tied to stem

thrust or available design margin. The SER stated that an acceptance

procedure for MCC testing was under development to specify parameters to be

monitored for trending, including specific acceptance criteria. The team

observed that the lack of acceptance criteria could lead to the inconsistent

evaluation of the data between different reviewers. Also, the documentation of

problem identification and resolution of issues identified through test data review

was missing or unclear. An inspector-identified example of entering improper

test data into the MOV test package was entered into the corrective action

program on CR-VTY-2004-2623.

The team also identified that no administrative or procedural prohibition had

been implemented against using MCC testing to set MOV switches, and that the

procedures specifically allowed establishing a baseline with MCC testing

24

Enclosure

(OP 5287). The MOV program had been revised in 2002 to eliminate any

periodicity requirements for at-the-valve diagnostic testing that can measure

torque and thrust to known accuracies. The team identified and the licensee

confirmed that the MCC test equipment had been used in at least one instance

to set MOV switches on one of the four RCIC valves reviewed. Also, the team

identified several cases where diagnostic testing following replacement of the

valve packing was limited to MCC testing. The team noted that packing

replacement affects stem friction and consequently changes in stem thrust.

Since the MCC testing instrumentation had not been validated, the team

concluded that the change in stem friction from initial set-up was indeterminate

for these valves.

Analysis. The performance deficiency was the failure to validate motor-operated

valve test instrumentation to ensure its adequacy and to establish test

procedures with adequate acceptance criteria tied to stem thrust or available

design margin. Specifically, there was no analysis demonstrating that testing

conducted at the MCC ensured the development of proper operating thrust at the

valve to ensure the MOV would perform satisfactorily under design basis

conditions. This issue was more than minor because it was associated with the

Mitigating Systems Cornerstone attribute of Equipment Performance and

affected the cornerstone objective of ensuring the availability, reliability, and

capability of systems and components that respond to initiating events.

Specifically, the unvalidated test method had the potential to affect the reliability

of safety-related motor-operated valves. The issue screened as very low safety

significance (Green) in Phase I of the SDP, because it was a qualification

deficiency that was not found to result in a loss of function. The team did not

identify any examples of degraded or inoperable valves during the inspection

and noted that the design basis calculations for the MOVs reviewed had

available thrust margin of greater than 60 percent.

The inspectors also identified that a contributing cause of the finding was related

to the human performance cross-cutting area, in that, the licensee did not

manage NRC commitments and conditions documented in the SER for the

GL 96-05 MOV periodic verification program.

Enforcement. 10 CFR Part 50, Appendix B, Criterion XI, Test Control, requires

that a test program be established to ensure that all testing required to

demonstrate that systems and components will perform satisfactorily in service is

performed in accordance with written test procedures which incorporate the

requirements and acceptance limits contained in applicable design documents.

The test procedures shall include provisions for ensuring that adequate test

instrumentation is available and used. Contrary to the above, Vermont Yankee

had conducted MOV diagnostic tests using procedures that did not include

acceptance limits which were correlated to and based on applicable (stem thrust

and torque) design documents. Additionally, MOV diagnostic testing had been

conducted solely from the motor control centers using test instrumentation that

had not been validated to ensure its adequacy. Because this finding is of very

25

Enclosure

low safety significance and has been into Vermont Yankees corrective action

program (CR-VTY-2004-2802 and CR-VTY-2004-2644), it is being treated as a

non-cited violation, consistent with Section VI.A of the NRCs Enforcement

Policy. (NCV 05000271/2004008-09 Failure To Establish Adequate MOV

Periodic Test Program)

b.2

Observations

The team also had other observations regarding the licensees NOV program.

The team concluded these observations did not impact valve operability due to

existing value capability margins.

The team identified that Vermont Yankee had not maintained current the risk

ranking of MOVs. At the time that the SER was issued, the licensees risk

ranking of the MOVs was considered acceptable. During a review of program

documents during this inspection, the team noted that low- and medium-risk

MOVs were specified for test at every other refueling outage, whereas, high-risk

MOVs were specified for testing every refueling outage. For the RCIC system

MOVs reviewed, the team noted that several valves had the same risk

achievement worth (RAW), but they were assigned different risk rankings in the

MOV program documents and consequently were not tested at the same

periodicity. Discussions with Vermont Yankees risk analyst indicated that the

licensees PRA had been updated in 2000 and May 2004; however, the updated

PRA data were not reflected back into the MOV risk ranking. This issue was

entered into the corrective action program on CR-VTY-2004-2798.

The team also concluded that Vermont Yankees trending methods to identify

degradation from design basis conditions were informal. The SER documented

the existence of established procedures to review and trend MOV failure and

diagnostic test data every two years. Primary MOV parameters identified for

trending were various thrust values, stem friction coefficient, load sensitive

behavior and dynamic margin. The SER noted that Vermont Yankee would

perform quantitative and qualitative assessments looking for overall changes in

MOV performance, including the use of diagnostic trace overlays and analysis.

The team found that the procedure referenced in the SER (DP 0210) had been

canceled. The trending of alternating current MOVs was moved to the

procedure for evaluating MCC test data; however, a procedure for trending direct

current MOVs had not been established. Currently, Vermont Yankees trending

program consists of reviewing the data from a diagnostic test to the results of the

previous test, which may not identify degradation from the established baseline

or identify slow but continual degradation. This issue was entered into the

corrective action program on CR-VTY-2004-2644.

4OA6 Meetings, Including Exit

26

Enclosure

The team presented the issues identified during the inspection to Mr. Dreyfuss and other

members of the licensees staff at a team debrief on September 3, 2004.

On October 27, 2004, the inspection team leader provided the preliminary results of the

inspection, including risk significance and enforcement, to Mr. Bronson, Mr. Dreyfuss,

and other members of licensees staff in a teleconference call.

The preliminary results of the inspection were also included in a letter to Vermont

Yankee Nuclear Power Station dated November 5, 2004, which was originally issued in

preparation for a planned public exit meeting.

A final closeout discussion on the inspection was held with Mr. Thayer, Mr. Bronson and

other members of the licensees staff via teleconference on November 23, 2004. The

Vermont State Nuclear Engineer was invited to the closeout discussion, but was not

available to attend.

Attachment

ATTACHMENT A

Summary of Items Reviewed

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

115 kV - Breaker K1

Transformer T-4 feed to 115 kV bus: required

to supply power from the 345 kV switchyard

to the Startup Transformers.

No automatic actions required except fault clearing;

safety busses would disconnect or be prevented

from connecting to circuit after a fault.

115 kV - K.1 Logic Relay

RCIC logic relay K.1 fails to operate on

demand. Rationale: Malfunction of RCIC

turbine trip instrumentation could cause loss

of RCIC System.

The inspectors found no specific operator action for

this component and that a failure of the logic relay

would result in control room alarms which would be

responded to by the operators. The inspectors found

that related control room alarms were functioning

properly, and that the associated alarm response

procedures were current.

125 V Battery B-1 and A-1

Station Battery: Supplies power to the station

125 VDC loads when the battery chargers

are not available.

Detailed review completed.

24 Vdc - ES-24DC-2

Power Supply Converter: Supplies power to

the 24 VDC ECCS Analog Trip System.

No low margin or other issues identified.

345 kV - Breaker 381-1

Northfield 345 kV line to 345 kV North Bus:

required to provide power from the Northfield

381 to the 345 kV switchyard.

Detailed review completed.

4 Kv - Breaker 12

Bus 1 Feed Breaker from UAT: required to

open on generator trip to enable access of

one safety train to the offsite source through

the SUT

No low margin issues identified.

A-2

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

4 Kv - Breaker 13

Bus 1 Feed Breaker from SUT: required to

close on generator trip to enable access of

one safety train to the offsite source through

the SUT .

Detailed review completed.

4 Kv - Breaker 22

Bus 2 Feed Breaker from UAT: required to

open on generator trip to enable access of

one safety train to the offsite source through

the SUT.

The inspectors found that the only operator action

for this component was breaker open/close

operation. Additionally, the inspectors found that the

related control room alarms were functioning

properly and that the associated alarm response

procedures were current. The inspectors found no

issues with this component related to operator

actions.

4 Kv - Breaker 23

Bus 2 Feed Breaker from SUT: required to

close on generator trip to enable access of

one safety train to the offsite source through

the SUT.

Detailed review completed.

4 Kv - Breaker 3V

Vernon Supply Breaker to Bus 3: required to

supply power from the Alternate AC Power

source to one 4160V safety bus.

No specific issues identified with breaker. Other

issues reviewed as part of overall Station Blackout

Capability.

4 Kv - Breaker 3V4

Vernon Tie Breaker: required to supply

power from the Alternate AC Power source

to either 4160V safety bus.

Detailed review completed.

4 kV UV Relays

4160V Undervoltage Relays: required to

provide adequate voltage to safety-related

AC loads, reset setpoint must be optimized

to prevent spurious loss of offsite power.

Detailed review completed.

A-3

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

69 kV - Vernon Generator

Vernon Hydroelectric generator station:

required to supply power from the Alternate

AC Power source to either 4160V safety bus.

Detailed review completed.

69 kV to 4160 V Vernon

Transformer

Vernon Tie Transformer: required to supply

power from the Alternate AC Power source

to either 4160V safety bus.

Detailed review completed.

125 VDC Distribution

Panels

Supplies 125 VDC loads.

Detailed review completed.

Alignment of RHRSW to

the RPV

Operator fails to align the RHRSW injection

to RPV.

Aligning RHRSW injection to the RPV is one of the

methods which can be used for RPV injection to

prevent core damage in accordance with EOPs

given an ATWS scenario. The validated time

through simulator observation was 1 minute to

complete the actions for alignment. Additionally,

prior to using RHR SW for RPV injection, other

systems such as condensate/feedwater , CRD, and

RHR will be used to attempt to fill the RPV. The

operators are regularly trained and evaluated in this

event scenario further reducing the likelihood of the

task not being completed within the required time.

Bus Transfer Scheme

Circuit breakers, synchronism check relays,

timing relays, and voltage relays required to

enable transfer of 4160V buses from the Unit

Aux Transformer to the Startup

Transformers.

Detailed review completed.

A-4

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Closure of Vernon Tie

Breakers

Operator fails to close the Vernon tie

breakers.

One of the primary AC power recovery actions in the

event of a loss of normal power is to use the

dedicated tie line from the Vernon hydro Station to

power either 4260VAC Bus 3 or 4 (vital power). The

action is performed by the operators in the main

control room by manipulating switches for 2 DC

powered breakers. Validation studies and operator

observation in the simulator have shown that the

task can be accomplished in less than 4 minutes.

Adequate margin exists currently and for the CPPU

to accomplish the action. Additionally, operator

response to loss of power events is trained regularly

in the simulator and classroom. While no issues

identified with VY operator actions, a finding was

identified with the licensee's overall station blackout

response.

A-5

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Condensate Pump

Review condensate operation before and

after the power uprate (including recirc pump

runback modification).

The Condensate and Feedwater system

does not directly perform any safety-related

function. Portions of the Feedwater system

and check valves provide Reactor Coolant

Pressure Boundary and Containment

Isolation functions. The condensate pumps

1) supply water to the Feedwater pumps and

2) provide sufficient NPSH for operation of

the FW pumps. The loss of a condensate

pump could be a contributing factor to a

transient initiation.

The condensate pumps are directly impacted

by the EPU due to the need to increase the

flow volume by approximately 20%.

No low margin or other issues identified.

Containment Pressure

During a loss of coolant event or an ATWS

the containment pressure will be elevated

and the suppression pool level will increase.

Detailed review completed.

CST Transient Analysis

Temperature

Non-conservative

Transient analysis Condensate Storage Tank

Temperature non-conservative compared to

actual maximum operating temperatures.

This issue stems from a similar event at

Point Beach.

Detailed review completed.

A-6

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

CST Level Instrumentation

Rationale: Important for maintaining required

CST inventory for RCICS and controlling

automatic transfer of RCICS suction to the

suppression pool.

Detailed review completed.

CV-109

Failure of check valve CV-109 (valve

between the N2 bottle and the SRV) to open.

Failure of this check valve to open will

prevent N2 supply to the Main Steam Safety

Relief Valves.

Detailed review completed.

CV-19

RCIC check valve CV-19 (RCIC suction

check valve from the CST) fails to open on

demand. This valve must open to provide

flow from CST to RCIC pump suction, and

close to prevent flow from torus to CST

during RCIC pump suction transfer.

A detailed review was not performed for this check

valve because no performance problems were

indicated from the maintenance history.

A-7

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

CV-2-1A, 1B, 1C

RFP discharge check valves. They are risk

significant because if they fail to close

following an RFP trip they could make other

RFPs inoperable.

Prior to EPU two pumps are operational.

After EPU three pumps will be operational.

When two pumps are operational, one of the

MOVs, 4A, 4B or 4C will be closed for the

non-operational pump as such, this is not a

current potential event. However, after EPU

the third valve will not be closed thus this is a

potential failure scenario.

A detailed review was not performed for these check

valves because no performance problems were

indicated from the maintenance history.

CV-22

RCIC check valve CV-22 (RCIC injection

path discharge check valve) fails to open on

demand. This valve must open for RCIC

injection flow. The valve must also fully close

when the pump is not in operation to prevent

back-leakage and a possible waterhammer.

Detailed review completed.

A-8

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

CV-2-27B

This valve is the feedwater isolation valve

upstream of the RCIC injection path. The risk

significant function of the component is to

close to prevent RCIC from flowing back into

the feedwater system.

EPU uprate will increase the flow through this

check valve by approximately 20%, however

the function of the valve is not altered.

A detailed review was not performed for this check

valve because no performance problems were

indicated from the maintenance history.

CV-2-28B

Feedwater check valve CV-28B ('B'

feedwater line check valve inside

containment) fails to open on demand. This

valve is located on drawing G-191167, H-5.

Failure to open will prevent flow from either

the RCIC or the Feedwater system.

EPU uprate will increase the flow through this

check valve by approximately 20%, however

the function of the valve is not altered.

A detailed review was not performed for this check

valve because no performance problems were

indicated from the maintenance history.

CV-2-96A

Feedwater check valve V96A fails to open on

demand. Failure of this valve will prevent flow

from either the RCIC or the FW system.

EPU uprate will increase the flow through this

check valve by approximately 20%, however

the function of the valve is not altered.

A detailed review was not performed for this check

valve because no performance problems were

indicated from the maintenance history.

A-9

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

CV-40

RCIC check valve CV-40 (RCIC suction

check valve from the suppression pool) fails

to open on demand. This valve must open to

provide a flow path from the torus to the

RCIC pump suction.

A detailed review was not performed for this check

valve because no performance problems were

indicated from the maintenance history or walkdown.

CV-6/7

RCIC check valves CV- 6/7 (RCIC turbine

exhaust check valves to torus) fails to open

on demand.

Detailed review completed.

CV-72-109

Failure of check valve CV-109 (N2 bottle

supply check valve to the plant N2 system) to

close. The component is risk significant

because if the check valve failed to close, the

N2 bottle could bleed down to the plant N2

system.

Detailed review completed.

Digital Feedwater

Control/Single Element

Control

Following the modification that installed the

digital feedwater control system, the licensee

had problems with loss of inputs to the

three-element controller (steam flow). This

resulted in a reactor level transient. Since the

event the plant had been operating in

single-element control. Evaluate the

modification and the acceptability of

operating in single-element. Also determine if

operation in single-element control would

challenge the licensee's assumption that the

plant would not scram following a single

reactor feed pump trip, post-uprate.

Detailed review completed.

A-10

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

DPIS-83/84

Spurious high steam flow signal. This steam

flow instrument isolates RCIC steam in the

event of a line rupture (indicated by high

flow). Spurious isolation would result in the

loss of RCIC flow.

These instruments are not included because there is

significant margin in the setpoint to detect a steam

line rupture, as well as margin between the normal

operating point and the setpoint.

EOP/NPSH Fidelity

Verify fidelity between Emergency Operation

Procedures and NPSH calculations and

Containment Spray operation.

Detailed review completed.

FCV-2-4

FCV.4 (condensate pump minimum flow

valve) fails to open on demand.

Detailed review completed.

FCV-2-4 Instrumentation

Failure of FCV.4 (condensate pump

minimum flow valve) control instrumentation.

Detailed review completed.

Feed/Condensate Control

Operator fails to initiate and/or control

feedwater/condensate.

Detailed review completed.

FT-58/FE-56

RCIC pump discharge flow instrument. This

instrument is associated with the RCIC

turbine control logic.

Detailed review completed.

GE SIL 351

GE SIL 351 - HPCI and RCIC Turbine

Control System Calibration.

Vermont Yankee implemented SIL 351R.2 and

provided the procedural changes recommended in

the SIL for the HPCI system (OP 5337 Rev. 7). SIL

351 does not apply to RCIC since RCIC does not

use a ramp generator (RGSC). This SIL is primarily

procedural change recommendations and is not a

high risk/low margin system.

A-11

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

GE SIL 377

GE SIL 377 RCIC Startup Transient

Improvement with Steam Bypass (June 24,

1982).

GE SIL 377 recommended a bypass for the steam

supply line to the turbine for improved startup

performance during a transient where RCIC is

needed. This does not apply to Vermont Yankee

since the SIL was a recommendation for plants who

have issues with cold startup of the RCIC system.

Upon talking to the system engineer, these issues

have not existed for at least 20 years at VY.

GE SIL 467 (Bistable

Vortexing)

GE SIL 467 and IEN 86-110 - Bistable

vortexing is still a phenomenon that occurs

periodically at VY.

The first occurrence of bistable vortexing at Vermont

Yankee was following beginning of cycle 12 when

recirculation system piping was replaced; however,

this is a low risk event and thus does not meet the

high risk / low margin criteria for this inspection.

Vermont Yankee has had problems with bistable

vortexing in the past and responded in depth to this

SIL. The licensee responded to the SIL, added

discussion on bistable vortexing at VY and action

items for operators when bistable vortexing occurs.

A review of Vermont Yankee's response to SIL 467,

showed VY satisfied GE's recommended actions

and placed guidance in OP 2110, Recirculation

Procedure to aid the operators in identifying bistable

vortexing.

GL 96-05, MOV Periodic

Verification

GL 96-05 - Implementation of program for

MOV Periodic Verification (As applicable to

the selected sample of valves RCIC-MOV-

15, 16, 131 and 132)

Detailed review completed.

A-12

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

IN 2001-13 (SLC Relief

Valve Margin)

Information Notice 2001-13 (8/10/01) -

Inadequate Standby Liquid Control System

Relief Valve Margin (Susquehanna, Units 1

and 2) Susquehanna's power uprate

increased SRV setpoint pressure thus

increasing SLC discharge pressure.

However, the maximum SLC pump

discharge pressure used a non-conservative

maximum reactor vessel pressure in accident

analysis.

Detailed review completed.

LER 3871995009

(LCO 3.0.3 Entry)

LER 1995-009-00 (7/3/95) - Condition

Prohibited by the Plant's Technical

Specifications (Susquehanna, Unit 1) - Non-

conservative plant input into reactor core flow

calculation.

Feedflow used in the analysis for power uprate is

consistent with current feedflow indications.

LER 3251997005

(FW Indication Error)

LER 1997-005-01 (8/8/97) - Feedwater Flow

Indication Discrepancy (Brunswick Steam

Electric Plant, Unit 1).

Vermont Yankee does not have and is not required

to have chemical tracer mass flow rate tests. This is

more conservative then having the tracers since the

chemical tracer mass flow rate tests are

controversial and have had past issues. VY is

waiting for industry or regulatory guidance on this

issue before adding this test.

LER 2961998001

(LOCA Sensor Problem)

LER 1998-001-00 (4/1/1998) - Computer

Modeling Indicates Sensors May Not Detect

All Possible Break Locations (Browns Ferry,

Unit 3).

Vermont Yankee does use the GOTHIC computer

code to analyze high energy pipe breaks; however,

this is a low risk issue and presented no significant

safety issue at Browns Ferry.

A-13

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

LER 2601999009

(Scram Due to EHC Leak)

LER 1999-009-00 (10/14/99) - Manual

Reactor Scram Due to EHC Leak (Browns

Ferry Nuclear Power Station, Unit 2).

The EHC leak was on a very specific 3/8 inch

nominal outer diameter tubing connection which

consisted of socket weld glands and standard nuts

to connect the accumulator to a pressure

transmitter. The leak was due to poor fabrication and

poor work practices specific to Browns Ferry.

LER 2372001005 (1/7/02)

LER 2001-005-00 (1/7/02) - Unit 2 Scram

Due to Increased First Stage Turbine

Pressure (Dresden, Unit 2).

Vermont Yankee responded to GE SIL 423, in 1998,

by implementing corrective actions.

LER 4612002002

(Inadequate PM on FW

System)

LER 2002-002-00 (7/11/02) - Inadequate

Preventive Maintenance Program for the

Feedwater System Results in Lockup of a

Turbine-Driven Reactor Feed Pump and

Scram on High Reactor Pressure Vessel

Water Level During Extended Power Uprate

Testing (Clinton Power Station). Feedwater

increased due to the power uprate; however,

the feedwater limit switch did not increase to

accommodate this increase in flow.

This operating experience does not apply since

Vermont Yankee does not have turbine driven

feedwater pumps, and this issue does not apply to

other turbine driven pumps in the plant.

A-14

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

LER 3412002005

(Non-Conservative

Setpoint)

LER 2002-05 (1/16/03) - Discovery of

Non-Conservative Setpoint for the

Thermal-Hydraulic Stability Option III

Oscillation Power Range Monitor (OPRM)

Period Based Algorithm, Tmin

(Fermi, Unit 2).

This OE does not apply to Vermont Yankee since

power oscillations are monitored using approved

BWROG Option 1D not Option III. Vermont Yankee

does not have Oscillation Power Range Monitors,

Period Based Detection Algorithms, and Tmin

values. Option III is used for larger BWRs that have

local power oscillations. Since Vermont Yankee has

a small BWR core, only core-wide oscillations occur

(not local oscillations).

The inspector met with an individual from power

uprate (and used to work in reactor engineering) and

discussed, in detail, core monitoring using Option 1D

for the new ARTS/MELLA core design and the

power uprate core design.

LER 4542003003

(Maximum Power

Exceeded)

LER 2003-003-00 (9/29/03) - Licensed

Maximum Power Level Exceeded Due to

Inaccuracies in Feedwater Ultrasonic Flow

Measurements Caused by Signal Noise

Contamination (Byron).

Detailed review completed.

LER 3411992009

LER-92-009-00 (11/20/92) - Safety Relief

Valves Set Pressure Outside Technical

Specifications (Fermi, Unit 2).

VY has had no issues with setpoint drift on the SRVs

or RVs in containment. Setpoint drift considered in

this LER was an indication of disc-to-seat sticking

due to corrosion binding on the SRVs and RVs at

Fermi thus making these valves fail their set

pressures tests.

A-15

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

LSHH-4A

Level switch LSHH 4A contacts fail/short.

High Water Make up - Condenser level

Control Switch Fails high - auto make

malfunctions to the CST - Operator Action is

required.

No EPU impact.

Operator can take manual action to overcome this

failure. The consequence of the failure of the switch

is not significant because the operator can take

manual control.

Manual Initiation of

HPCI/RCIC

Operator fails to manually initiate HPCI and

RCIC systems.

Detailed review completed.

Manual Operation of

SRVs (Medium LOCA)

Operator fails to manually open the SRVs for

a medium LOCA.

Emergency Operating Procedures (EOP) require

operator action to manually open the SRVs to

depressurize the reactor under medium break LOCA

conditions. Validation studies and operator

observations in the simulator have shown that given

various factors that influence human performance

(stress, training, equipment failures, etc.), the task to

open the SRVs manually would be accomplished in

less than 7 minutes which is lower than the 33

minutes (or 24 minutes for CPPU) needed to assure

> 1/3 core coverage. Additionally, operator training

frequently focuses on this event making it unlikely

that the operator would fail to perform the task within

the required time.

A-16

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Manual Operation of SRVs

(Small LOCA/Transient)

Operator fails to manually open the SRVs for

transient/small LOCA.

Emergency Operating Procedures (EOP) require

operator action to manually open the SRVs to

depressurize the reactor under transient and small

break LOCA conditions. Validation studies and

operator observations in the simulator have shown

that given various factors that influence human

performance (stress, training, equipment failures,

etc.), the task to open the SRVs manually would be

accomplished in less than 5 minutes which is much

lower than the 66 minutes (or 48 minutes for CPPU)

needed to assure > 1/3 core coverage. Additionally,

operator training frequently focuses on this event

making it unlikely that the operator would fail to

perform the task within the required time.

Manual RCIC operation-

Appendix R Safe

Shutdown

Appendix R Safe Shutdown Analysis -

Operator fails to manually initiate RCIC

system using alternate shutdown panels

(Generic Human Actions that are Risk

Important), and GE document NEDC-

330090P, Table 10-5 (Assessment of Key

Operator Action).

Detailed review completed.

MOV-131

RCIC MOV 131 (RCIC turbine steam supply

valve) fails to open on demand. This valve is

required to open to provide steam to the

RCIC turbine for operation.

Not included because valve has adequate design

margin to open when required.

A-17

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

MOV-132

RCIC MOV 132 (cooling water valve to the

RCIC lube oil cooler) fails to open on

demand. This valve is required to open to

provide cooling water to the RCIC pump lube

oil cooler. Failure to cool the lube oil could

result in failure of the pump/turbine.

Not included because valve has adequate design

margin to open when required.

MOV-15/16

RCIC MOV 15/16 (steam supply to RCIC

turbine) fails closed during its mission time.

These valves are required to close in the

event of a line break in the RCIC turbine

steam supply to isolate the HELB. These

valves are also required to remain open

when the RCIC pump is required to operate.

Detailed review completed.

MOV-18

RCIC MOV 18 (RCIC pump suction valve

from the CST) transfers closed during its

mission time. This valve is required to

automatically close when the RCIC pump

suction is transferred from the CST to the

torus. This valve must remain open while the

RCIC pump is operating from the CST.

Not included because valve has adequate design

margin to close when required.

MOV-21/20

RCIC MOV 21 (inboard discharge valve to

the reactor vessel) fails to open on demand.

Also look at MOV-20 (the normally open

outboard discharge isolation valve). These

valves must automatically open to provide

RCIC injection flow in response to an RCIC

initiation signal.

Detailed review completed.

A-18

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

MOV-27

This is the RCIC minimum flow valve. This

valve is required to open at low RCIC flow to

protect the pump.

Detailed review completed.

MOV-39

RCIC MOV 39 (RCIC suction valve from the

suppression pool) fails to open on demand.

This valve is required to open when the RCIC

pump suction is transferred from the CST to

the torus.

Detailed review completed.

MOV-41

RCIC MOV 41 (RCIC suction valve from the

suppression pool) fails to open on demand.

This valve is required to open when the RCIC

pump suction is transferred from the CST to

the torus.

Not included because valve has adequate design

margin to open when required.

MOV-64-31

MOV 64-31 (manual makeup valve from the

CST to hotwell) fails to open on

demand.

Failure of this valve will prevent make-up from the

hot-well to the CST. The loss of this valve would not

be safety significant and there are no indications that

there is low margin on for this valve

Offsite Transmission

System

Offsite Transmission System: preferred

source of power to the 4160V safety buses;

must remain stable and available following

the trip of the VY generator.

Detailed review completed.

A-19

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Operator Bypasses the

MSIV Isolation Interlocks

Operator Bypasses MSIV Isolation

Interlocks. The justification is the decrease in

the Allowable Action Time for the operators

at the EPU level (CPPU). It is based on input

from the Human Performance technical staff,

Appendix A of NUREG 1764 (Generic

Human Actions that are Risk Important), and

GE document NEDC-330090P, Table 10-5

(Assessment of Key Operator Action).

The allowable action time to bypass the MSIV

low-low level isolation interlocks is based upon the

time it would take to reach the RPV low-low level

setpoint for an ATWS with no injection. Validation

studies by the licensee have shown that the task

would be accomplished for transient and LOCA

events within the required time. The margin to

accomplish the task is adequate, for current and

CPPU conditions, given other operational factors

and steps in the EOPs which must be taken into

account (e.g., a high main steam line radiation

isolation signal maintaining the valves closed).

Operators train and are evaluated and tested on a

regular basis for this scenario further reducing the

likelihood that the task would not be completed in

the time required.

Operator Inhibits ADS

Operator action to inhibit ADS. The

justification is the decrease in the Allowable

Action Time for the operators at the EPU

level (CPPU). It is based on input from the

Human Performance technical staff,

Appendix A of NUREG 1764 (Generic

Human Actions that are Risk Important), and

GE document NEDC-330090P, Table 10-5

(Assessment of Key Operator Action).

The operator action to inhibit ADS is one of the first

actions taken by the operators under certain

transient conditions in the EOPs. The allowable

action time is based on the time to reach the vessel

level low-low set point for ATWS without injection

plus two minutes for the ADS timer. Validation

studies and operator observation in the control room

have demonstrated that the action would be

accomplished in less than 3 minutes. The margin to

complete the task is not significantly changed under

CPPU conditions. Additionally, operators are trained

and tested regularly in this EOP action step.

A-20

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Passive Failure of

Feedwater Piping

Review effect of increased feedwater flow on

flow-accelerated corrosion rates following the

power uprate.

Detailed review completed.

PB IR 2002-011 (HPCI

Functional Issue)

Peach Bottom Finding for IR 50-277/2002-

011 (8/5/02) - Finding Related to High

Pressure Coolant Injection Function (may

apply to RCIC system at VY).

Detailed review completed.

PCV-23

RCIC PCV 23 (RCIC air operated lube oil

temperature control valve) fails to open on

demand. This valve uses instrument air to

control its setpoint and fails fully open on a

loss of instrument air. This valve is required

to provide cooling water, at the correct

pressure, to the RCIC pump lube oil cooler

when the RCIC pump is operating.

Detailed review completed.

PS-67

Spurious RCIC low suction pressure trip

signal. This instrument will cause the RCIC

pump to trip in the event of low pump suction

pressure. Spurious trips will result in a loss

of RCIC flow.

Not included because there is significant margin in

the setpoint to prevent a spurious trip.

PSH-72A/B

Spurious RCIC turbine exhaust high pressure

trip. This instrument will trip the RCIC pump

in the event of high pressure in the exhaust

steam line. Spurious trips will result in a loss

of RCIC flow.

Not included because there is significant margin in

the setpoint to prevent a spurious trip.

A-21

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

PT-59/60

RCIC pump discharge pressure. This

instrument is associated with the RCIC

turbine control logic.

Not included because there is significant margin in

the setpoint.

PT-68

Spurious low steam line pressure signal.

This instrument will isolate steam flow to the

RCIC turbine in the event of low steam

supply pressure, indicating a steam line

break. Spurious isolation would result in a

loss of RCIC flow.

Not included because the pressure switch setpoint

has significant margin to prevent a spurious pump

trip.

PT-70

Spurious RCIC trip on high turbine exhaust

pressure signal. Component ID is PT-70.

Include exhaust rupture disks S3 and S4.

This instrument will trip the RCIC pump in the

event of high pressure in the exhaust steam

line. Spurious trips will result in a loss of

RCIC flow.

Not included because there is significant margin in

the setpoint and operating pressure to prevent a

spurious trip.

A-22

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Manual operation of MOV

64-31

Operator fails to manually open MOV 64-31

(used to manually transfer makeup from the

CST to the condenser).

The operator action to manually open valve MOV

64-31, Hotwell Emergency Makeup Valve, is

performed in the main control room. The action is

required when turbine bypass is not available

(during an MSIV closure event). In that case

automatic makeup to the hotwell from the

Condensate Storage Tank (CST) may not be

sufficient to keep up with reactor vessel makeup

requirements (feedwater pumps providing vessel

level makeup). Validation studies and operator

observations have estimated a 1 minute time to

manipulate the valve from the control room. If the

valve is required to be opened from the field the

estimates are less than 15 minutes, however, other

EOP mitigation strategies such as use of low

pressure ECCS pumps, would assure core coverage

if the valve could not be opened.

RB/Torus Vacuum

Breakers

Reactor Building to Torus vacuum breakers.

The vacuum breakers are required to open to

prevent a vacuum in the containment. These

also must remain closed to ensure

containment integrity and to prevent loss of

overpressure for ECCS NPSH.

Detailed review completed.

RCIC Pump P-47-1A and

Turbine TU-2-1-A

RCIC pump P-47-1A fails to start on

demand. This sample includes the turbine

driven RCIC pump, the governor valve, and

trip throttle valve.

Detailed review completed.

A-23

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Reactor Feed Pump

Failure of the feedwater pump will fail to

deliver flow required for normal operation or

to mitigate an accident.

Prior to EPU 2 of three feedwater pumps are

required to support the Feedwater system

requirements. As such there is a 50% spare

capability. For EPU three pumps are required

to operated due to the increase requirements

of feedwater flow.

Detailed review completed.

RHR Pump

Review RHR pump NPSH calculation,

associated suction strainers, bubble

ingestion, and torus vortexing issues.

Detailed review completed.

Safety Valve (New)

Addition of third main steam safety valve for

power uprate. Failure of SSV to open and

relieve pressure during transients or

small/medium break LOCA.

Detailed review completed.

SLC Initiation with

Condenser Failed

Operator fails to initiate SLC with the main

condenser failed. The justification is the

decrease in the Allowable Action Time for the

operators at the EPU level (CPPU). It is

based on input from the Human Performance

technical staff, Appendix A of NUREG 1764

(Generic Human Actions that are Risk

Important), and GE document

NEDC-330090P, Table 10-5 (Assessment of

Key Operator Action).

Detailed review completed.

A-24

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Spurious High Steam Line

Space Temperature Trip

Spurious RCIC trip on high steam line space

temperature (instrument TS 79 through 82).

These instruments would result in isolation of

the steam flow to the RCIC turbine in the

event of a steam line break. A spurious trip

would result in loss of RCIC flow.

Not included because there is significant margin

between the setpoint and the operating temperature

to prevent a spurious trip.

Spurious High Steam

Tunnel Temperature Trip

Spurious RCIC trip on a high steam tunnel

temperature trip signal. These instruments

would result in isolation of the steam flow to

the RCIC turbine in the event of a steam line

break. A spurious trip would result in loss of

RCIC flow.

Not included because there is significant margin

between the setpoint and the operating temperature

to prevent a spurious trip.

Spurious Reactor High

Level Trip

Spurious high reactor water level signal (trip

could affect both the RCIC pump or feed

water pump). These instruments would result

in tripping the RCIC turbine in the event of

high RPV level. A spurious trip would result

in loss of RCIC flow.

Excluded because HPCI and the RFP trip signals

are provided by different instruments and the

probability of a simultaneous failure of these

instruments is extremely low.

SR-26

SR-26 (RCIC supply to lube oil cooler relief

valve) fails open. This component is

designed to protect the RCIC lube oil cooler

and may be important on a loss of IA when

the flow control valve fully opens (based on

interview with RCIC System Manager).

Detailed review completed.

SRVs

Safety relief valves allow the reactor to be

depressurized.

Detailed review completed.

A-25

SSC/OA/OE

Description

Detailed Review Completed / Basis For Exclusion

Attachment

Vernon Tie Line

Operator monitoring of Vernon tie line to

ensure availability as a station blackout

source.

Detailed review completed.

ATTACHMENT B

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Amidon

EFIN Engineer

M. Arnett

Systems Engineer - Electrical

K. Bronson

General Manager

F. Burger

Corrective Action

J. Callaghan

Design Engineering Manager

M. Castronova

Design EFIN Supervisor

J. Devincentis

Licensing Manager

J. Dreyfuss

Director of Engineering

E. Duda

Power Uprate Engineer

N. Fales

Systems Engineer - FW and Condensate

K. Farabaugh

Systems Engineering Supervisor

J. Fitzpatrick

Design Mechanical/Structural Engineering - FAC

M. Flynn

Design Engineer - Electrical

D. Girroir

Systems Engineering Supervisor

S. Goodwin

Design Mechanical/Structural Engineering Supervisor

A. Graves

Design Admin Assistant

C. Hansen

Design Engineer - Components

A. Haumann

Design Engineer - Electrical

B. Hobbs

Power Uprate - Engineering Supervisor

M. Janus

Design Engineer - Electrical

P. Johnson

Design Engineer - Electrical

J. Kritzer

Operations/Reactor Engineer

M. Lefrancois

Systems Engineering Supervisor

P. Longo

Design Engineer - Components

L. Lukens

Systems Engineering Supervisor

M. McKenney

Maintenance Support Engineering

J. Melvin

Systems Engineer - SLC

M. Metell

Entergy-Vermont Yankee Response Team Leader

B. Naeck

Systems Engineer - RCIC

C. Nichols

Power Uprate Engineering Manager

T. O'Connor

Design Engineer - Mechanical/Structural

M. Palionis

PRA Engineer

P. Perez

Design Engineer - Fluid Systems

P. Rainey

Design Engineer - Fluid Systems

A. Robertshaw

Design Engineer - Fluid Systems

J. Rogers

Design Fluid Systems Engineering Supervisor

R. Rusin

Design Engineering Supervisor - Components

B. Slifer

Power Uprate Engineer

J. Stasolla

Systems Engineer - Electrical

B-2

J. Taylor

Corrective Action

J. Thayer

Site Vice President

G. Thomas

Power Uprate - Contractor Interface

J. Twarog

Operations Shift Engineering Supervisor

R. Vibert

Design Electrical Engineering Supervisor

C. Wamser

Operations Manager

R. Wanczyk

Director of Nuclear Safety

G. Wierzbowski

Systems Engineering Manager

A. Wonderlick

Systems Engineer - Electrical

Other

W. Farnsworth

Training Coordinator - REMVEC / National Grid

D. Goodwin

Operations Supervisor US-GEN

W. Houston

Manager of Transmission - REMVEC / National Grid

W. Sherman

Vermont State Nuclear Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000271/2004008-04

URI

Ungrounded 480 VAC Electrical System.

(Section 4OA5.2.1.1.b.3)

Opened and Closed

05000271/2004008-01

NCV

Availability of Power from the Vernon

Station. (Section 4AO5.2.1.1.(b).1)05000271/2004008-02

NCV

Procedures for Assessing Off-site Power

Operability. (Section 4AO5.2.1.1.(b).2)05000271/2004008-03

NCV

Degraded Relay Setpoint Calculations.

(Section 4AO5.2.1.1.(b).3)05000271/2004008-05

NCV

Cooling Water Supply Portion of RCIC Not

Installed per Design Basis.

(Section 4AO5.2.1.2.(b).1)05000271/2004008-06

NCV

Failure to Correct Non-Conforming RCIC

Pressure Control Valve. (Section

4A05.2.1.2(b).2)

B-3

05000271/2004008-07

NCV

Failure to Implement Adequate Design

Control for Condensate Storage Tank

Temperature. (Section 4AO5.2.1.7.(b))05000271/2004008-08

NCV

Failure to Revise Safe Shutdown Capability

Analysis Report. (Section 4AO5.2.2.(b))05000271/2004008-09

NCV

Failure to Establish Adequate MOV Periodic

Test Program. (Section 4AO5.2.3.(b))

LIST OF DOCUMENTS REVIEWED

Procedures and Tests

Emergency Operating Procedures

EOP-1 - RPV Control, Rev. 2

EOP-2 - ATWS, Rev. 4

EOP-3 - Primary Containment Control, Rev. 3

EOP-5 - RPV-ED, Rev. 3

Operating Procedures

OP-0023, Installation and Testing of Cable and Conduit, Rev. 8

OP-2113, Main and Auxiliary Steam, Rev. 20

OP-2114, Operation of the Standby Liquid Control System, Rev. 22

OP-2115, Primary Containment, Rev. 44

OP-2116, Secondary Containment Integrity Control, Rev. 19

OP-2119, Nitrogen Supply System, Rev. 13

OP-2121, Reactor Core Isolation Cooling System (RCIC), Rev. 29

OP-2124, Residual Heat Removal System, Rev. 52

OP-2140, 345 KV Electrical System, Rev. 25

OP-2141, 115KV Switchyard, Rev. 17

OP-2142, 4KV Electrical System, Rev. 21

OP-2145, Normal 125 VDC Operation, Rev. 24

OP-2149, Normal 24 VDC Operation, Rev. 7

OP-2170, Condensate System, Rev. 23

OP-2172, Feedwater System, Rev. 23

OP-3126, Shutdown Using Alternative Methods, Rev. 16

OP-4255, Calibration of 4kV Bus Degraded Grid Undervoltage Relays, Rev. 11

OP 5217, MOV Motor Control Center (MC2) Testing, Rev. 2

OP 5287, Evaluation of MOV Motor Control Center (MC2) Testing, Rev. 2

OP 5219, Diagnostic Testing of Motor Operated Valves, Rev. 12

OP 5220, Limitorque Operator PM, Rev. 25

B-4

Operational Transient

OT-3113, Reactor Low Level, Rev. 13

OT-3114, Reactor High Level, Rev. 13

OT-3115, Rx Low Pressure, Rev. 8

OT-3116, Rx High Pressure, Rev. 8

OT-3121, Inadvertent Opening of a Relief Valve, Rev. 13

OT-3122, Loss of Normal Power, Rev. 20

Other

ENN-OP-104, Operability and Determination Procedure, Rev. 2

ENN-DC-325, Component Performance Monitoring, Rev. 0

ENN-DC-151, PSA Maintenance and Update, Rev. 0

AP 6038, Component Level Review of Vermont Yankee Motor-Operated Valves (MOVs), Rev.1

AP 6039, Electrical Design Basis Review of Vermont Yankee Motor-Operated Valves (MOVs),

Original Issue

AP 6037, System and Functional Design Basis Review of Vermont Yankee Motor-Operated

Valves (MOVs), Original Issue

AP 6040, Vermont Yankee Motor-Operated Valve Electrical Configuration, Original Issue

AP 6041, Vermont Yankee Engineering Evaluations of MOV Diagnostic Testing and Feedback

of Results into MOV Component Calculations, Rev. 1

PP 7004, Vermont Yankee Nuclear Power Station Motor Operated Valve Program, Rev. 1

PP 7005, Periodic Verification of Motor Operated Valves, Original Issue

CRP 9-8, Main Control Room Overhead Alarm Panel, Vernon BKR 3V4 Trip/Bus Voltage Low

ON 3155, Loss of Auto Transformer, Rev. 9

Calculations and Studies

Vendor Calculations

RCIC hydraulic calculations (VYE-1064 and VYE-1423)

Structural Integrity Inc. Report SIR-04-020 Rev 0, File VY-10Q-401, Updated Stress and

Fatigue Analysis for the Vermont Yankee Feedwater Nozzles, March 2004

Structural Integrity Inc. File VY10Q-302 Loads and Transient Definitions, Rev. 0

Structural Integrity Inc. Calculation Package VY-10Q-303, Uprated Feedwater Nozzle Stress

and Fatigue Analysis, Rev. 0

Structural Integrity Inc. Calculation VY-10Q-301 Feedwater Nozzle Finite Element Model and

Heat Transfer Coefficients, Rev. 0

Vendor Calculation DC-A34600-03, RHR and CS Suction Strainer Bubble Ingestion, Rev. 0

Vermont Yankee Calculations

VYC-415, Appendix R RCIC, HPCI, and ECCS Room Cooling, Rev. 0

VYC-462C, RCIC Steam Line Area High Temperature Setpoint, Rev. 0, and CCN 01

VYC-706, Condensate Storage Tank Level (RCIC) Monitoring, Rev. 1, CCN 01 and 02

B-5

VYC-709, RCIC System Flow Control and Indication Loop Accuracy, Rev. 1

VYC-715, Degraded Bus Voltage Monitoring loop Accuracy, Rev. 1

VYC-808, Core Spray and RHR Pump Net Positive Suction Head Margin Following a LOCA

with Fibrous Debris on the Intake Strainers, Rev. 0, and CCN 4, 5 and 6 and its

supporting references

VYC-830, Voltage Drop Calculations for VY Distribution Panels DC-1 and DC-2, Rev. 9

and CCN No. 5.

VYC-1005, Crack Growth Calculation for the Vermont Yankee FW Nozzles, Rev. 2

VYC-1053, Motor Operated Valve (MOV) Voltage Analysis, Rev. 8 and CCN 02

VYC-1088, Vermont Yankee 4160/480 Volt Short Circuit/ Voltage Study, Rev. 3

VYC-1293, System Level Review of Reactor Core Isolation Cooling MOVs for GL 89-10,

Rev. 3

VYC-1347, Main Steam Tunnel Heatup Calculation, Rev. 0

VYC-1349, 125V Direct Current DC Voltage Drop Study, Rev. 2 and CCN 05

VYC-1512, Station Blackout Voltage Drop and Short Circuit Study, Rev. 2

VYC-1700, 4.16kV Bus Protective Relay Settings Verification, Rev. 1

VYC-1726, Reactor Core Isolation Cooling Pump Test Acceptance Values, Rev. 1 and

CCN 01

VYC-1816, RCIC Pump Net Positive Suction Head (NPSH), Rev. 0 and CCN 01

VYC-1825, Analysis of Suppression Pool Temperature for Relief Valve Discharge Transients,

Rev. 0 and CCN 1

VYC-1844, HPCI and RCIC Vortex Height, Rev. 1

VYC-1857, Fast and Residual Voltage Bus Transfer Analysis, Rev. I

VYC-1920, RHR and CS Suction Strainer Vortex/Minimum Submergence, Rev. 0 (DE&S

Calculation DC-A34600-02 Rev. 0)

VYC-1924, Vermont Yankee ECCS Suction Strainer Head Loss Performance

Assessment, RHR and CS Debris Head Loss Calculations, Rev. 0 (DE&S Calc

DC-A32600-006 Rev. 0)

VYC-1950, Hydrodynamic Mass and Acceleration Drag Volume of Vermont Yankee ECCS

Strainers, Rev. 0

VYC-1959, Analysis of Tests for Investigation (of) the Effects of Coatings Debris on

ECCS Strainer Performance for Vermont Yankee, Rev. 1 (DE&S Report ITS/VY-

98-01, Rev.1)

VYC-2153, 125 VDC Battery A-1 Electrical System Calculation, Rev. 0 and CCN 03

VYC-2154, 125 VDC Battery B-1 Electrical System Calculation, Rev. 0

VYC-2314, Minimum Containment Overpressure for Non-Loca Events, Rev. 0 and

CCN 01 and 02

VYPC 98-010, Component Level Review of Reactor Core Isolation Cooling (RCIC) MOVs for

GL 89-10, Rev. 2

Studies and Evaluations

Franklin Institute Technical Report F-C2653-01 Design and Stress Analysis of the Vermont

Yankee NPS Clean-up / Feedwater Recombination Tee

General Electric (GE) Topical Report T0900

GE-NE-0000-0009-9951-01 Rev 1, Task 0302 Reactor Vessel Integrity Stress Analysis

(Excludes the radius of the forging)

B-6

GE-NEDC-330090P, Assessment of Key Operator Actions, Table 10-5

Strainer Head Loss Performance Assessment, RHR and CS Debris Head Loss, Rev 0.

VYNPS:EPU T0400: DBA-LOCA for Long Term NPSH Evaluation

Yankee Uprate System Impact Study, dated November 11, 2003

B-7

Condition Reports

CR-96-117

CR-00-1575

CR-02-1860

CR-04-448

CR-96-129

CR-00-1596

CR-02-2193

CR-04-815

CR-96-136

CR-01-880

CR-02-2194

CR-04-1234

CR-98-467

CR-01-889

CR-02-2716

CR-04-1484

CR-98-1171

CR-01-890

CR-02-2733

CR-04-1522

CR-98-2066

CR-01-1007

CR-02-2942

CR-04-2600

CR-99-175

CR-01-1232

CR-03-441

CR-04-2621

CR-99-618

CR-01-1340

CR-03-962

CR-04-2623

CR-00-94

CR-01-1834

CR-03-1491

CR-04-2644

CR-00-306

CR-01-2084

CR-03-1855

CR-04-2723

CR-00-468

CR-01-2186

CR-03-1910

CR-04-2798

CR-00-1509

CR-01-2214

CR-03-2810

CR-04-2799

CR-00-1567

CR-02-151

CR-04-433

CR-04-2802

Drawings

Drawing B-191301 Sh. 1150, Core Spray System B Aux. Relays Sh 1, Rev. 13

Drawing B-191301 Sh. 306, 4kV SWGR #3 Instr & Relaying, Rev. 16

Drawing B-191301 Sh. 317, 4kV SWGR Aux. Relay Ckt., Rev. 10

Drawing B-191301 Sh. 327, 4kV SWGR #3 Tie to 4kV SWGR #1 Bkr. #3T1, Rev. 8.

Drawing B-191301 Sh. 328A, 4Kv SWGR #3 Compt, 10 Diesel Generator DG1-1B Bkr & LNP

Ckt., Rev. 11

Drawing G-191157 Sheet 2 Location L-9, Flow Diagram Condensate, Feedwater and Air

Evacuation Systems, Rev. 5

Drawing G-191174, Sheet 2, Flow Diagram - Reactor Core Isolation Cooling, Rev. 23

Drawing B-191261, Sheet 26C, Impulse Piping to Rack RK-6, Rev. 6

Drawing G-191298 Sh.1, Main One Line Diagram, Rev. 32

Drawing G-191298 Sh.2, Main One Line Phasor Diagram, Rev. 8

DS801-2, Generator SN 180X383 Reactive Capability Curve, dated February 11, 2003

Drawing 6202-001, General Plan Pressure Suppression Containment Vessel C Residual Heat

Removal System - Bubble Ingestion from Safety Relief Valve and LOCA, Rev. 3

Operability Determinations

CR-VTY-1999-00990; Damaged Threads, Originated: 8/17/1999, Closed: 10/6/1999

CR-VTY-2001-00966; Leak Rate Test Results Exceeded the Acceptance Criteria, Originated:

5/04/2001, Closed: 6/29/2001

CR-VTY-2002-02258; IST Leak Rate Test Results Exceed the Acceptance Criteria,

Originated: 10/09/2002, Closed: 4/10/2004

CR-VTY-2004-01607; Breaker 381 Fails to Stay Closed (it trips free), Originated: 5/2/2004,

Closed 5/18/2004

CR-VTY-2004-2596; The Design Basis for Degraded Grid UV Relay not Adequately

Documented in Calculation, Originated: 8/16/2004, Closed: Still Open

B-8

B-9

Modifications and Work Orders

DBD Pending Change Numbers RCIC 2004-002 and HPCI 2004-003

EDCR 81-22 in accordance with NUREG-0737, Item II.K.3.22

EDCR 97-404, MOV Electrical and Pressure Locking Modifications, dated June 17, 1998

EDCR 94-406, MOV Improvements, dated July 13, 1995

Modification Package MM-2003-015, Reactor Feed Pump Suction Pressure Trip Changes for

EPU

Modification Package MM-2003-016, Reactor Recirculation System Run Back For Feedwater

and Condensate System Transients

Modification Package MM-2004-015, Improve SLC Relief Valve Tolerances to Meet New SLC

System Operating Pressure Requirements

Vermont Yankee Design Change VYDC 2003-013, Addition of 3rd Main Steam Safety Valve,

dated 7/9/2003

Vermont Yankee Design Change VYDC 2001-003, RCIC Turbine Exhaust Check Valve

Replacement, dated 10/28/2004

Correspondence

Memorandum, E. Betti to S. Miller, Feedwater Leakage Monitoring Data Analysis, dated

January 30, 1991

Memorandum, E. Betti to S. Miller, Monthly Feedwater Leakage Monitoring Data Report

Analysis, dated December 6, 1993

Letter FVY 82-105, VY to NRC, Feedwater Spargers - Response to NRCs Request for

Additional Information, dated September 21, 1982

Letter BVY 94-07, VY to NRC, Request for Relief from NUREG-0619 Inspection

Requirements, dated February 11, 1994

Letter NVY 95-142, VY to NRC, Feedwater Nozzle Inspection Relief Request - Vermont

Yankee Nuclear Power Station (TAC No. M92940), dated October 12, 1995

Calculation VYC1005, Revision 1, Crack Growth Calculation for the Vermont Yankee FW

Nozzles, Attachment 1, GE-NE-523-A71-0594 with NRC SER dated

March 10, 2000

Letter BVY 01-02, VY to NRC, Alternative Feedwater Nozzle Inspection, dated

January 22, 2001

Letter, NRC to VY, Vermont Yankee Nuclear Power Station Safety - Evaluation of Licensee

Response to Generic Letter 9605 (TAC NO. M97114), dated December 14, 2000

Letter BVY 96-143, VY to NRC, Vermont Yankee 60-day Response to Generic Letter 96-05,

dated November 15, 1996

Letter BVY 97-36, VY to NRC, Vermont Yankee 180-day Response to Generic Letter 96-05,

dated November 15, 1996

Summary of Changes in Leak Detection Data, Report Generated August 30, 2004

Summary of Changes in Leak Detection Data, Report Generated September 1, 2004

GE Letter VYNPS-AEP-346 Revisions 0, 1 and 2

B-10

Event Reports

Event Report 20030340, Root Cause Analysis, The Outboard Seal on RFP C Failed

Other Documents

Generic Letter (GL) 89-10, Safety-Related Motor-Operated Valve Testing and Surveillance,

dated June 28, 1989

Generic Letter (GL) 96-05, Periodic Verification of Design-Basis Capability of Safety-Related

Power Operated Valves, dated September 18, 1996

Information Notice (IN) 2001-13, Inadequate Standby Liquid Control System Relief Valve

Margin, dated August 10, 2001.

Operational Decision-Making Issue (ODMI) Action Plan 2003-1812

NRC SER, Degraded Grid Voltage Protection for Class 1E Power Systems, dated

March 31, 1986

Regulatory Guide 1.82, Water Sources for Long-Term Recirculation Cooling following a Loss-

of-Coolant Accident, Revision 3, dated November 2003

Vermont Yankee Updated Final Safety Analysis Report (UFSAR), Revision 18

Vermont Yankee Individual Plant Examination (IPE) Document

Vermont Yankee Appendix R Safe Shutdown Capability Analysis (SSCA), dated December 23,

1999

Vermont Yankee Technical Specifications, through Amendment No. 219

LIST OF ACRONYMS

AC

Alternating Current

ASME

American Society of Mechanical Engineers

CR

Condition Report

CST

Condensate Storage Tank

EPU

Extended Power Uprate

EOP

Emergency Operating Procedure

FAC

Flow Assisted Corrosion

GE

General Electric

GL

Generic Letter

HPCI

High Pressure Coolant Injection

kV

Kilovolt

LER

Licensee Event Report

MCC

Motor Control Center

MOV

Motor-Operated Valve

NCV

Non-Cited Violation

NPSH

Net Positive Suction Head

NRC

US Nuclear Regulatory Commission

OD

Operability Determination

psig

Pounds Per Square Inch Gauge

PRA

Probabilistic Risk Assessment

B-11

PUSAR

Power Uprate Safety Analysis Report

RAW

Risk Achievement Worth

RCIC

Reactor Core Isolation Cooling

RHR

Residual Heat Removal

ROP

Reactor Oversight Process

SBO

Station Blackout

SDP

Significance Determination Process

SLC

Standby Liquid Control

SPAR

Simplified Plant Analysis Risk

SRV

Safety/Relief Valve

TE

Technical Evaluation

TS

Technical Specifications

UFSAR

Updated Final Safety Analysis Report

V

Volt

VY

Vermont Yankee

VY SSCA

Vermont Yankee Safe Shutdown Capability Analysis