ML043340269
| ML043340269 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee  |
| 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
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
D. Pelton, DRP, Senior Resident Inspector
A. Rancourt, DRP, Resident OA
Region I Docket Room (with concurrences)
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.
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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
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
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
i Enclosure
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.
ii Enclosure
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)
iii Enclosure
! 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
iv Enclosure
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,
v Enclosure
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.
vi 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.
Enclosure
2
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.
Enclosure
3
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
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4
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
Enclosure
5
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.
Enclosure
6
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.
Enclosure
7
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
Enclosure
8
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
Enclosure
9
results, maintenance history, vendor manuals, drawings, design calculations and
applicable sections of the UFSAR and the TS.
Enclosure
10
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
Enclosure
11
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
Enclosure
12
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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13
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.
Enclosure
14
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
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
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15
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.
Enclosure
16
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.
Enclosure
17
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
Enclosure
18
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.
Enclosure
19
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
Enclosure
20
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
Enclosure
21
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.
Enclosure
22
Enclosure
23
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
Enclosure
24
(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
Enclosure
25
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
Enclosure
26
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.
Enclosure
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 No automatic actions required except fault clearing;
to supply power from the 345 kV switchyard safety busses would disconnect or be prevented
to the Startup Transformers. from connecting to circuit after a fault.
115 kV - K.1 Logic Relay RCIC logic relay K.1 fails to operate on The inspectors found no specific operator action for
demand. Rationale: Malfunction of RCIC this component and that a failure of the logic relay
turbine trip instrumentation could cause loss would result in control room alarms which would be
of RCIC System. 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 Detailed review completed.
125 VDC loads when the battery chargers
are not available.
24 Vdc - ES-24DC-2 Power Supply Converter: Supplies power to No low margin or other issues identified.
the 24 VDC ECCS Analog Trip System.
345 kV - Breaker 381-1 Northfield 345 kV line to 345 kV North Bus: Detailed review completed.
required to provide power from the Northfield
381 to the 345 kV switchyard.
4 Kv - Breaker 12 Bus 1 Feed Breaker from UAT: required to No low margin issues identified.
open on generator trip to enable access of
one safety train to the offsite source through
the SUT
Attachment
A-2
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
4 Kv - Breaker 13 Bus 1 Feed Breaker from SUT: required to Detailed review completed.
close on generator trip to enable access of
one safety train to the offsite source through
the SUT .
4 Kv - Breaker 22 Bus 2 Feed Breaker from UAT: required to The inspectors found that the only operator action
open on generator trip to enable access of for this component was breaker open/close
one safety train to the offsite source through operation. Additionally, the inspectors found that the
the SUT. 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 Detailed review completed.
close on generator trip to enable access of
one safety train to the offsite source through
the SUT.
4 Kv - Breaker 3V Vernon Supply Breaker to Bus 3: required to No specific issues identified with breaker. Other
supply power from the Alternate AC Power issues reviewed as part of overall Station Blackout
source to one 4160V safety bus. Capability.
4 Kv - Breaker 3V4 Vernon Tie Breaker: required to supply Detailed review completed.
power from the Alternate AC Power source
to either 4160V safety bus.
4 kV UV Relays 4160V Undervoltage Relays: required to Detailed review completed.
provide adequate voltage to safety-related
AC loads, reset setpoint must be optimized
to prevent spurious loss of offsite power.
Attachment
A-3
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
69 kV - Vernon Generator Vernon Hydroelectric generator station: Detailed review completed.
required to supply power from the Alternate
AC Power source to either 4160V safety bus.
69 kV to 4160 V Vernon Vernon Tie Transformer: required to supply Detailed review completed.
Transformer power from the Alternate AC Power source
to either 4160V safety bus.
125 VDC Distribution Supplies 125 VDC loads. Detailed review completed.
Panels
Alignment of RHRSW to Operator fails to align the RHRSW injection Aligning RHRSW injection to the RPV is one of the
the RPV to RPV. 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, Detailed review completed.
timing relays, and voltage relays required to
enable transfer of 4160V buses from the Unit
Aux Transformer to the Startup
Transformers.
Attachment
A-4
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Closure of Vernon Tie Operator fails to close the Vernon tie One of the primary AC power recovery actions in the
Breakers breakers. 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.
Attachment
A-5
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Condensate Pump Review condensate operation before and No low margin or other issues identified.
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%.
Containment Pressure During a loss of coolant event or an ATWS Detailed review completed.
the containment pressure will be elevated
and the suppression pool level will increase.
CST Transient Analysis Transient analysis Condensate Storage Tank Detailed review completed.
Temperature Temperature non-conservative compared to
Non-conservative actual maximum operating temperatures.
This issue stems from a similar event at
Point Beach.
Attachment
A-6
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
CST Level Instrumentation Rationale: Important for maintaining required Detailed review completed.
CST inventory for RCICS and controlling
automatic transfer of RCICS suction to the
suppression pool.
CV-109 Failure of check valve CV-109 (valve Detailed review completed.
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.
CV-19 RCIC check valve CV-19 (RCIC suction A detailed review was not performed for this check
check valve from the CST) fails to open on valve because no performance problems were
demand. This valve must open to provide indicated from the maintenance history.
flow from CST to RCIC pump suction, and
close to prevent flow from torus to CST
during RCIC pump suction transfer.
Attachment
A-7
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
CV-2-1A, 1B, 1C RFP discharge check valves. They are risk A detailed review was not performed for these check
significant because if they fail to close valves because no performance problems were
following an RFP trip they could make other indicated from the maintenance history.
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.
CV-22 RCIC check valve CV-22 (RCIC injection Detailed review completed.
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.
Attachment
A-8
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
CV-2-27B This valve is the feedwater isolation valve A detailed review was not performed for this check
upstream of the RCIC injection path. The risk valve because no performance problems were
significant function of the component is to indicated from the maintenance history.
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.
CV-2-28B Feedwater check valve CV-28B ('B' A detailed review was not performed for this check
feedwater line check valve inside valve because no performance problems were
containment) fails to open on demand. This indicated from the maintenance history.
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.
CV-2-96A Feedwater check valve V96A fails to open on A detailed review was not performed for this check
demand. Failure of this valve will prevent flow valve because no performance problems were
from either the RCIC or the FW system. indicated from the maintenance history.
EPU uprate will increase the flow through this
check valve by approximately 20%, however
the function of the valve is not altered.
Attachment
A-9
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
CV-40 RCIC check valve CV-40 (RCIC suction A detailed review was not performed for this check
check valve from the suppression pool) fails valve because no performance problems were
to open on demand. This valve must open to indicated from the maintenance history or walkdown.
provide a flow path from the torus to the
RCIC pump suction.
CV-6/7 RCIC check valves CV- 6/7 (RCIC turbine Detailed review completed.
exhaust check valves to torus) fails to open
on demand.
CV-72-109 Failure of check valve CV-109 (N2 bottle Detailed review completed.
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.
Digital Feedwater Following the modification that installed the Detailed review completed.
Control/Single Element digital feedwater control system, the licensee
Control 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.
Attachment
A-10
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
DPIS-83/84 Spurious high steam flow signal. This steam These instruments are not included because there is
flow instrument isolates RCIC steam in the significant margin in the setpoint to detect a steam
event of a line rupture (indicated by high line rupture, as well as margin between the normal
flow). Spurious isolation would result in the operating point and the setpoint.
loss of RCIC flow.
EOP/NPSH Fidelity Verify fidelity between Emergency Operation Detailed review completed.
Procedures and NPSH calculations and
Containment Spray operation.
FCV-2-4 FCV.4 (condensate pump minimum flow Detailed review completed.
valve) fails to open on demand.
FCV-2-4 Instrumentation Failure of FCV.4 (condensate pump Detailed review completed.
minimum flow valve) control instrumentation.
Feed/Condensate Control Operator fails to initiate and/or control Detailed review completed.
feedwater/condensate.
FT-58/FE-56 RCIC pump discharge flow instrument. This Detailed review completed.
instrument is associated with the RCIC
turbine control logic.
GE SIL 351 GE SIL 351 - HPCI and RCIC Turbine Vermont Yankee implemented SIL 351R.2 and
Control System Calibration. 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.
Attachment
A-11
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
GE SIL 377 GE SIL 377 RCIC Startup Transient GE SIL 377 recommended a bypass for the steam
Improvement with Steam Bypass (June 24, supply line to the turbine for improved startup
1982). 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 GE SIL 467 and IEN 86-110 - Bistable The first occurrence of bistable vortexing at Vermont
Vortexing) vortexing is still a phenomenon that occurs Yankee was following beginning of cycle 12 when
periodically at VY. 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 GL 96-05 - Implementation of program for Detailed review completed.
Verification MOV Periodic Verification (As applicable to
the selected sample of valves RCIC-MOV-
15, 16, 131 and 132)
Attachment
A-12
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
IN 2001-13 (SLC Relief Information Notice 2001-13 (8/10/01) - Detailed review completed.
Valve Margin) 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.
LER 3871995009 LER 1995-009-00 (7/3/95) - Condition Feedflow used in the analysis for power uprate is
(LCO 3.0.3 Entry) Prohibited by the Plant's Technical consistent with current feedflow indications.
Specifications (Susquehanna, Unit 1) - Non-
conservative plant input into reactor core flow
calculation.
LER 3251997005 LER 1997-005-01 (8/8/97) - Feedwater Flow Vermont Yankee does not have and is not required
(FW Indication Error) Indication Discrepancy (Brunswick Steam to have chemical tracer mass flow rate tests. This is
Electric Plant, Unit 1). 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 LER 1998-001-00 (4/1/1998) - Computer Vermont Yankee does use the GOTHIC computer
(LOCA Sensor Problem) Modeling Indicates Sensors May Not Detect code to analyze high energy pipe breaks; however,
All Possible Break Locations (Browns Ferry, this is a low risk issue and presented no significant
Unit 3). safety issue at Browns Ferry.
Attachment
A-13
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
LER 2601999009 LER 1999-009-00 (10/14/99) - Manual The EHC leak was on a very specific 3/8 inch
(Scram Due to EHC Leak) Reactor Scram Due to EHC Leak (Browns nominal outer diameter tubing connection which
Ferry Nuclear Power Station, Unit 2). 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 Vermont Yankee responded to GE SIL 423, in 1998,
Due to Increased First Stage Turbine by implementing corrective actions.
Pressure (Dresden, Unit 2).
LER 4612002002 LER 2002-002-00 (7/11/02) - Inadequate This operating experience does not apply since
(Inadequate PM on FW Preventive Maintenance Program for the Vermont Yankee does not have turbine driven
System) Feedwater System Results in Lockup of a feedwater pumps, and this issue does not apply to
Turbine-Driven Reactor Feed Pump and other turbine driven pumps in the plant.
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.
Attachment
A-14
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
LER 3412002005 LER 2002-05 (1/16/03) - Discovery of This OE does not apply to Vermont Yankee since
(Non-Conservative Non-Conservative Setpoint for the power oscillations are monitored using approved
Setpoint) Thermal-Hydraulic Stability Option III BWROG Option 1D not Option III. Vermont Yankee
Oscillation Power Range Monitor (OPRM) does not have Oscillation Power Range Monitors,
Period Based Algorithm, Tmin Period Based Detection Algorithms, and Tmin
(Fermi, Unit 2). 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 LER 2003-003-00 (9/29/03) - Licensed Detailed review completed.
(Maximum Power Maximum Power Level Exceeded Due to
Exceeded) Inaccuracies in Feedwater Ultrasonic Flow
Measurements Caused by Signal Noise
Contamination (Byron).
LER 3411992009 LER-92-009-00 (11/20/92) - Safety Relief VY has had no issues with setpoint drift on the SRVs
Valves Set Pressure Outside Technical or RVs in containment. Setpoint drift considered in
Specifications (Fermi, Unit 2). 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.
Attachment
A-15
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
LSHH-4A Level switch LSHH 4A contacts fail/short. Operator can take manual action to overcome this
failure. The consequence of the failure of the switch
High Water Make up - Condenser level is not significant because the operator can take
Control Switch Fails high - auto make manual control.
malfunctions to the CST - Operator Action is
required.
No EPU impact.
Manual Initiation of Operator fails to manually initiate HPCI and Detailed review completed.
HPCI/RCIC RCIC systems.
Manual Operation of Operator fails to manually open the SRVs for Emergency Operating Procedures (EOP) require
SRVs (Medium LOCA) a medium LOCA. 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.
Attachment
A-16
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Manual Operation of SRVs Operator fails to manually open the SRVs for Emergency Operating Procedures (EOP) require
(Small LOCA/Transient) transient/small LOCA. 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 Analysis - Detailed review completed.
Appendix R Safe Operator fails to manually initiate RCIC
Shutdown 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).
MOV-131 RCIC MOV 131 (RCIC turbine steam supply Not included because valve has adequate design
valve) fails to open on demand. This valve is margin to open when required.
required to open to provide steam to the
RCIC turbine for operation.
Attachment
A-17
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
MOV-132 RCIC MOV 132 (cooling water valve to the Not included because valve has adequate design
RCIC lube oil cooler) fails to open on margin to open when required.
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.
MOV-15/16 RCIC MOV 15/16 (steam supply to RCIC Detailed review completed.
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.
MOV-18 RCIC MOV 18 (RCIC pump suction valve Not included because valve has adequate design
from the CST) transfers closed during its margin to close when required.
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.
MOV-21/20 RCIC MOV 21 (inboard discharge valve to Detailed review completed.
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.
Attachment
A-18
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
MOV-27 This is the RCIC minimum flow valve. This Detailed review completed.
valve is required to open at low RCIC flow to
protect the pump.
MOV-39 RCIC MOV 39 (RCIC suction valve from the Detailed review completed.
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.
MOV-41 RCIC MOV 41 (RCIC suction valve from the Not included because valve has adequate design
suppression pool) fails to open on demand. margin to open when required.
This valve is required to open when the RCIC
pump suction is transferred from the CST to
the torus.
MOV-64-31 MOV 64-31 (manual makeup valve from the Failure of this valve will prevent make-up from the
CST to hotwell) fails to open on hot-well to the CST. The loss of this valve would not
demand. be safety significant and there are no indications that
there is low margin on for this valve
Offsite Transmission Offsite Transmission System: preferred Detailed review completed.
System source of power to the 4160V safety buses;
must remain stable and available following
the trip of the VY generator.
Attachment
A-19
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Operator Bypasses the Operator Bypasses MSIV Isolation The allowable action time to bypass the MSIV
MSIV Isolation Interlocks Interlocks. The justification is the decrease in low-low level isolation interlocks is based upon the
the Allowable Action Time for the operators time it would take to reach the RPV low-low level
at the EPU level (CPPU). It is based on input setpoint for an ATWS with no injection. Validation
from the Human Performance technical staff, studies by the licensee have shown that the task
Appendix A of NUREG 1764 (Generic would be accomplished for transient and LOCA
Human Actions that are Risk Important), and events within the required time. The margin to
GE document NEDC-330090P, Table 10-5 accomplish the task is adequate, for current and
(Assessment of Key Operator Action). 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 The operator action to inhibit ADS is one of the first
justification is the decrease in the Allowable actions taken by the operators under certain
Action Time for the operators at the EPU transient conditions in the EOPs. The allowable
level (CPPU). It is based on input from the action time is based on the time to reach the vessel
Human Performance technical staff, level low-low set point for ATWS without injection
Appendix A of NUREG 1764 (Generic plus two minutes for the ADS timer. Validation
Human Actions that are Risk Important), and studies and operator observation in the control room
GE document NEDC-330090P, Table 10-5 have demonstrated that the action would be
(Assessment of Key Operator Action). 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.
Attachment
A-20
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Passive Failure of Review effect of increased feedwater flow on Detailed review completed.
Feedwater Piping flow-accelerated corrosion rates following the
PB IR 2002-011 (HPCI Peach Bottom Finding for IR 50-277/2002- Detailed review completed.
Functional Issue) 011 (8/5/02) - Finding Related to High
Pressure Coolant Injection Function (may
PCV-23 RCIC PCV 23 (RCIC air operated lube oil Detailed review completed.
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.
PS-67 Spurious RCIC low suction pressure trip Not included because there is significant margin in
signal. This instrument will cause the RCIC the setpoint to prevent a spurious trip.
pump to trip in the event of low pump suction
pressure. Spurious trips will result in a loss
of RCIC flow.
PSH-72A/B Spurious RCIC turbine exhaust high pressure Not included because there is significant margin in
trip. This instrument will trip the RCIC pump the setpoint to prevent a spurious trip.
in the event of high pressure in the exhaust
steam line. Spurious trips will result in a loss
of RCIC flow.
Attachment
A-21
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
PT-59/60 RCIC pump discharge pressure. This Not included because there is significant margin in
instrument is associated with the RCIC the setpoint.
turbine control logic.
PT-68 Spurious low steam line pressure signal. Not included because the pressure switch setpoint
This instrument will isolate steam flow to the has significant margin to prevent a spurious pump
RCIC turbine in the event of low steam trip.
supply pressure, indicating a steam line
break. Spurious isolation would result in a
loss of RCIC flow.
PT-70 Spurious RCIC trip on high turbine exhaust Not included because there is significant margin in
pressure signal. Component ID is PT-70. the setpoint and operating pressure to prevent a
Include exhaust rupture disks S3 and S4. spurious 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.
Attachment
A-22
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Manual operation of MOV Operator fails to manually open MOV 64-31 The operator action to manually open valve MOV
64-31 (used to manually transfer makeup from the 64-31, Hotwell Emergency Makeup Valve, is
CST to the condenser). 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 Reactor Building to Torus vacuum breakers. Detailed review completed.
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
RCIC Pump P-47-1A and RCIC pump P-47-1A fails to start on Detailed review completed.
Turbine TU-2-1-A demand. This sample includes the turbine
driven RCIC pump, the governor valve, and
trip throttle valve.
Attachment
A-23
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Reactor Feed Pump Failure of the feedwater pump will fail to Detailed review completed.
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.
RHR Pump Review RHR pump NPSH calculation, Detailed review completed.
associated suction strainers, bubble
ingestion, and torus vortexing issues.
Safety Valve (New) Addition of third main steam safety valve for Detailed review completed.
power uprate. Failure of SSV to open and
relieve pressure during transients or
small/medium break LOCA.
SLC Initiation with Operator fails to initiate SLC with the main Detailed review completed.
Condenser Failed 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).
Attachment
A-24
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Spurious High Steam Line Spurious RCIC trip on high steam line space Not included because there is significant margin
Space Temperature Trip temperature (instrument TS 79 through 82). between the setpoint and the operating temperature
These instruments would result in isolation of to prevent a spurious trip.
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.
Spurious High Steam Spurious RCIC trip on a high steam tunnel Not included because there is significant margin
Tunnel Temperature Trip temperature trip signal. These instruments between the setpoint and the operating temperature
would result in isolation of the steam flow to to prevent a spurious trip.
the RCIC turbine in the event of a steam line
break. A spurious trip would result in loss of
RCIC flow.
Spurious Reactor High Spurious high reactor water level signal (trip Excluded because HPCI and the RFP trip signals
Level Trip could affect both the RCIC pump or feed are provided by different instruments and the
water pump). These instruments would result probability of a simultaneous failure of these
in tripping the RCIC turbine in the event of instruments is extremely low.
high RPV level. A spurious trip would result
in loss of RCIC flow.
SR-26 SR-26 (RCIC supply to lube oil cooler relief Detailed review completed.
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).
SRVs Safety relief valves allow the reactor to be Detailed review completed.
depressurized.
Attachment
A-25
SSC/OA/OE Description Detailed Review Completed / Basis For Exclusion
Vernon Tie Line Operator monitoring of Vernon tie line to Detailed review completed.
ensure availability as a station blackout
source.
Attachment
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-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
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
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
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
ROP Reactor Oversight Process
SBO Station Blackout
SDP Significance Determination Process
SPAR Simplified Plant Analysis Risk
SRV Safety/Relief Valve
TE Technical Evaluation
TS Technical Specifications
UFSAR Updated Final Safety Analysis Report
V Volt
VY SSCA Vermont Yankee Safe Shutdown Capability Analysis