ML042220267
| ML042220267 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 08/09/2004 |
| From: | Troy Pruett NRC Region 4 |
| To: | Overbeck G Arizona Public Service Co |
| References | |
| IR-04-003 | |
| Download: ML042220267 (65) | |
See also: IR 05000528/2004003
Text
August 9, 2004
Gregg R. Overbeck, Senior Vice
President, Nuclear
Arizona Public Service Company
P. O. Box 52034
Phoenix, Arizona 85072-2034
SUBJECT: PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED
INSPECTION REPORT 05000528/2004003, 05000529/2004003,
Dear Mr. Overbeck:
On June 30, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility. The enclosed
integrated report documents the inspection findings, which were discussed on July 8, 2004,
with you and other members of your staff.
The inspection examined activities conducted under your licenses as they relate to safety and
compliance with the Commission's rules and regulations and with the conditions of your
licenses. The inspectors reviewed selected procedures and records, observed activities, and
interviewed personnel.
This report documents eleven NRC identified and self-revealing findings of very low safety
significance (Green). Ten of these findings were determined to involve violations of NRC
requirements; however, because of the very low safety significance and because they were
entered into your corrective action program, the NRC is treating these findings as noncited
violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. Additionally,
three licensee-identified violations, which were determined to be of very low safety
significance, are listed in Section 4OA7 of this report. If you contest the noncited violations,
you should provide a response within 30 days of the date of this inspection report, with the
basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN.: Document Control
Desk, Washington DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear
Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington,
Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,
Washington DC 20555-0001; and the NRC Resident Inspector at Palo Verde Nuclear
Generating Station, Units 1, 2, and 3, facility.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, it's
enclosure, and your response (if any) will be made available electronically for public inspection
Arizona Public Service Company
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in the NRC Public Document Room or from the Publicly Available Records (PARS) component
of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Troy W. Pruett, Chief
Project Branch D
Division of Reactor Projects
Dockets: 50-528
50-529
50-530
Licenses: NPF-41
Enclosure:
NRC Inspection Report 05000528/2004003,
05000529/2004003, and 05000530/2004003
w/Attachment: Supplement Information
cc w/enclosure:
Steve Olea
Arizona Corporation Commission
1200 W. Washington Street
Phoenix, AZ 85007
Douglas K. Porter, Senior Counsel
Southern California Edison Company
Law Department, Generation Resources
P.O. Box 800
Rosemead, CA 91770
Chairman
Maricopa County Board of Supervisors
301 W. Jefferson, 10th Floor
Phoenix, AZ 85003
Aubrey V. Godwin, Director
Arizona Radiation Regulatory Agency
4814 South 40 Street
Phoenix, AZ 85040
Arizona Public Service Company
-3-
M. Dwayne Carnes, Director
Regulatory Affairs/Nuclear Assurance
Palo Verde Nuclear Generating Station
Mail Station 7636
P.O. Box 52034
Phoenix, AZ 85072-2034
Hector R. Puente
Vice President, Power Generation
El Paso Electric Company
310 E. Palm Lane, Suite 310
Phoenix, AZ 85004
Jeffrey T. Weikert
Assistant General Counsel
El Paso Electric Company
Mail Location 167
123 W. Mills
El Paso, TX 79901
John W. Schumann
Los Angeles Department of Water & Power
Southern California Public Power Authority
P.O. Box 51111, Room 1255-C
Los Angeles, CA 90051-0100
John Taylor
Public Service Company of New Mexico
2401 Aztec NE, MS Z110
Albuquerque, NM 87107-4224
Cheryl Adams
Southern California Edison Company
5000 Pacific Coast Hwy. Bldg. DIN
San Clemente, CA 92672
Robert Henry
Salt River Project
6504 East Thomas Road
Scottsdale, AZ 85251
Brian Almon
Public Utility Commission
William B. Travis Building
P.O. Box 13326
1701 North Congress Avenue
Austin, TX 78701-3326
Arizona Public Service Company
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Chief, Technological Services Branch
FEMA Region IX
1111 Broadway, Suite 1200
Oakland, CA 94607-4052
Arizona Public Service Company
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Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (NLS)
Branch Chief, DRP/D (TWP)
Senior Project Engineer, DRP/D (CJP)
Staff Chief, DRP/TSS (PHH)
RITS Coordinator (KEG)
OEDO RIV Coordinator (JLD)
PV Site Secretary (vacant)
Dale Thatcher (DFT)
ANO Site Secretary (VLH)
W. A. Maier, RSLO (WAM)
ADAMS: /Yes
G No Initials: __TWP__
/ Publicly Available G Non-Publicly Available
G Sensitive / Non-Sensitive
R:\\_PV2004\\PV2004-03RP-NLS.wpd
RIV:RI:DRP/D
RI:DRP/D
SRI:DRP/D
SRI:DRP/D
PE:DRP/D
SPE:DRP/D
GGWarnick
JFMelfi
TAMcConnell
NLSalgado
DEDumbacher CJPaulk
E -
E -
E -
E -
/RA/
/RA/
7/29/04
7/29/04
7/29/04
7/29/04
8/6/04
8/9/04
C:DRS/PSB
C:DRS/EB
C:DRS/OB
C:DRS/PEB
C:DRP/D
MPShannon
JAClark
ATGody
LJSmith
TWPruett
/RA/
/RA/
/RA/
RLNease
/RA/
8/6/04
8/6/04
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8/6/04
8/9/04
Enclosure
OFFICIAL RECORD COPY
T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets:
50-528, 50-529, 50-530
Licenses:
Report No:
05000528/2004003, 05000529/2004003, and 05000530368/2004003
Licensee:
Arizona Public Service Company
Facility:
Palo Verde Nuclear Generating Station, Units 1, 2, and 3
Location:
5951 S. Wintersburg
Tonopah, Arizona
Dates:
April 1 through June 30, 2004
Inspectors:
D. Carter, Health Physicist
E. Crowe, Resident Inspector, Arkansas Nuclear One
C. Johnson, Senior Reactor Inspector
B. Henderson, Reactor Inspector
J. Mateychick, Reactor Inspector
T. McConnell, Reactor Inspector
J. Melfi, Resident Inspector
N. Salgado, Senior Resident Inspector
G. Replogle, Senior Resident Inspector, Columbia Generating Station
J. Tapia, Senior Reactor Inspector
G. Warnick, Resident Inspector
R. Azua, Project Engineer
Approved By:
Troy W. Pruett, Chief, Project Branch D
Division of Reactor Projects
Enclosure
CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R04
Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1R05
Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1R07
Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R08
Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R11
Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R12
Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R13
Maintenance Risk Assessments and Emergent Work Evaluation . . . . . . . . . . . 7
1R14
Operator Performance During Nonroutine Plant Evolutions
. . . . . . . . . . . . . . . 8
1R15
Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R17
Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
1R19
Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
1R20
Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1R22
Surveillance Testing
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
1R23
Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
1EP6 Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
2OS1 Access Control to Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 20
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
4OA4 Cross Cutting Aspects of Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
40A7
Licensee-identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-11
Enclosure
SUMMARY OF FINDINGS
IR 05000528/2004003, 05000529/2004003; 05000530/2004003; 04/01/04 - 06/30/04; Palo
Verde Units 1, 2, and 3; Integrated Resident and Regional Report; Nonrout. Evol., Op. Evals.,
Post-Maint. Test., Refuel. Out., Surv. Test., Prob. Ident., Event Followup, and Other Activities.
This report covered a 3-month period of inspection by resident inspectors, five reactor
inspectors, a project engineer, and a health physicist. The inspection identified 11 Green
noncited violations and one finding. The significance of most findings is indicated by their
color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance
Determination Process." Findings for which the significance determination process does not
apply may be Green or be assigned a severity level after NRC management's 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 and Self-Revealing Findings
Cornerstone: Initiating Events
Green. A self-revealing noncited violation of Technical Specification 4.3.2 was
identified for the failure to properly maintain a check valve (siphon breaker)
between the vacuum drying skid and the spent fuel pool, such that the spent
fuel pool could not be inadvertently drained below 137 feet 6 inches. On May
14, 2004, the check valve failed to open and caused an inadvertent siphoning of
approximately 20 gallons from the Unit 3 spent fuel pool to the cask washdown
pit. Had the draindown continued, the spent fuel pool level could have
decreased below 137 feet 6 inches. This issue was entered into the corrective
action program as Condition Report/Disposition Request 2709518.
The finding is greater than minor because it affected the configuration control
attribute of the initiating events cornerstone. This finding cannot be evaluated
by the significance determination process because Manual Chapter 0609,
"Significance Determination Process," Appendix A, "Significance Determination
of Reactor Inspection Findings for At-Power Situations," and Appendix G,
"Shutdown Operations Significance Determination Process," do not apply to the
spent fuel pool. This finding is determined to be of very low safety significance
by management review because radiation shielding was provided by the spent
fuel pool water level, the spent fuel pool cooling and fuel building ventilation
systems were available, and there were multiple sources of makeup water
(Section 1R14).
Green. A self-revealing noncited violation of Technical Specification 5.4.1.d
was identified for the failure to ensure that hot work activities were not
performed in the presence of flammable compounds. Specifically, work
instructions did not require that maintenance personnel remove residual
isopropyl alcohol from the main feedwater pump Train A turbine casing prior to
commencing hot work activities. Consequently, a flash fire occurred when an
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Enclosure
oxygen-acetylene torch, used to preheat the metal for welding, ignited the
flammable material. The issue involved human performance crosscutting
aspects associated with inattention to detail by maintenance personnel. This
issue was entered into the corrective action program as Condition
Report/Disposition Request 2699943.
The finding is greater than minor because it could become a more significant
safety concern if left uncorrected, in that a fire could ignite in an area with risk
important equipment. This finding cannot be evaluated by the significance
determination process because Manual Chapter 0609, "Significance
Determination Process," Appendix F, "Determining Potential Risk Significance of
Fire Protection and Post-Fire Safe Shutdown Inspection Findings," does not
address the potential risk significance of shutdown fire protection findings.
Additionally, Manual Chapter 0609, Appendix G, "Shutdown Operations
Significance Determination Process," does not address fire protection findings.
However, the finding is determined to be of very low safety significance by
management review because the finding occurred while the unit was already in
a cold shutdown condition and the finding involved equipment not necessary to
maintain safe shutdown (Section 1R19).
Green. A self-revealing noncited violation of 10 CFR Part 50, Appendix B,
Criterion V, "Instructions, Procedures, and Drawings," was identified for the
failure of the licensee to have written instructions for testing a remotely
controlled submersible vehicle in the Unit 1 spent fuel pool. The vehicle
became entrained in the common suction line for the spent fuel pool cooling
system. At the time of the event, the unit was in refueling operations with 164 of
the 241 spent fuel assemblies unloaded into the spent fuel pool. The issue
involved human performance crosscutting aspects associated with poor
decision making and a lack of questioning attitude by radiation protection
personnel. This issue was entered into the corrective action program as
Condition Report/Disposition Request 2697384.
The finding is greater than minor because it affected the configuration control
and human performance attributes of the initiating events cornerstone objective.
This finding cannot be evaluated by the significance determination process
because Manual Chapter 0609, "Significance Determination Process,"
Appendix A, "Significance Determination of Reactor Inspection Findings for
At-Power Situations," and Appendix G, "Shutdown Operations Significance
Determination Process," do not apply to the spent fuel pool. This finding is
determined to be of very low safety significance by management review
because radiation shielding was provided by the spent fuel pool water level, the
spent fuel pool cooling and fuel building ventilation systems were available, and
there were multiple sources of makeup water (Section 4OA3).
Green. A self-revealing noncited violation of Technical Specification 5.4.1.a
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Enclosure
was identified when personnel failed to follow a maintenance procedure
preceding a 12- to 24-inch heavy load drop of a 7000 pound steam generator
snubber level plate inside the Unit 2 containment. The drop was due to a series
of errors between the engineering contractor and rigging crews. The snubber
plate was dropped in the vicinity of reactor coolant and shutdown cooling piping.
This issue was entered into the corrective action program as Condition
Report/Disposition Request 2639721.
The finding was greater than minor because it affects the equipment
performance and human performance attributes of the initiating events
cornerstone objective to limit the likelihood of events that challenge safety
functions during shutdown conditions. Using Manual Chapter 0609,
"Significance Determination Process," Appendix G, "Shutdown Operations
Significance Determination Process," the senior reactor analyst concluded that
this finding did not significantly increase the likelihood of losing the residual heat
removal function and did not significantly increase the likelihood that systems
that could mitigate a loss of residual heat removal function would be degraded.
Therefore, this finding is of very low safety significance (Section 4OA5).
Green. A noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI,
"Corrective Action," was identified for the failure to identify the root cause of
spent fuel pool inventory loss events and implement corrective actions to
preclude recurrence. Specifically, the improper positioning of a fuel pool
cleanup suction valve and inadequate level monitoring resulted in three losses
of spent fuel pool inventory events. This finding involves problem identification
and resolution crosscutting aspects associated with the failure to identify root
causes and implement corrective actions. The issue also involved human
performance crosscutting aspects associated with mispositioned valves and
awareness of plant conditions by operations personnel. This issue was entered
into the corrective action program as Condition Report/Disposition Request
2599869.
The finding is greater than minor because it affected the configuration control
and human performance attributes of the initiating events cornerstone objective.
This finding cannot be evaluated by the significance determination process
because Manual Chapter 0609, "Significance Determination Process,"
Appendix A, "Significance Determination of reactor Inspection Findings for At-
Power Situations," and Appendix G, "Shutdown Operations Significance
Determination Process," do not apply to the spent fuel pool. This finding is
determined to be of very low safety significance by management review
because radiation shielding was provided by the spent fuel pool water level, the
spent fuel pool cooling and fuel building ventilation systems were available, and
there were multiple sources of makeup water (Section 4OA5).
Cornerstone: Mitigating Systems
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Enclosure
SLIV. A Severity Level IV noncited violation of Technical Specification 3.3.11
was identified for the failure to include the resistance temperature detectors in
the channel calibration for the shutdown cooling heat exchanger temperature
instruments. Specifically, prior to the implementation of Improved Technical
Specifications, the licensee did not perform testing of the resistance
temperature detectors. Following the implementation of Improved Technical
Specifications, the licensee did not perform an in-place qualitative assessment
of the resistance temperature detectors' behavior. This issue was entered into
the corrective action program as Condition Report/Disposition Request 280178.
The failure to perform a complete shutdown cooling heat exchanger
temperature loop channel calibration is determined to have greater than minor
significance because the licensee's failure to report the condition impacted the
NRC's ability to perform it's regulatory function. Therefore, this finding was
considered applicable to traditional enforcement. Although the significance
determination process is not designed to assess the significance of violations
that potentially impact or impede the regulatory process, the finding can be
assessed using the significance determination process. Using the Phase 1
worksheet in Manual Chapter 0609, "Significance Determination Process," this
finding is determined to be of very low safety significance because it only
affected the mitigating system cornerstone and the resistance temperature
detectors were found to be within calibration (Section 4OA2).
Green. The inspectors identified a noncited violation of Technical Specification 5.2.2.d for the failure of authorized individuals to review monthly
overtime reports to ensure that excessive hours have not been assigned.
Specifically, following the implementation of an electronic reporting system in
2001, the licensee did not ensure that all managers continued to receive and
approve the Excess Hours Report.
The finding is greater than minor because if left uncorrected it could become a
more significant safety concern, in that exceeding the NRC Generic Letter 82-02, "Nuclear Power Plant Staff Working Hours," guidelines for
overtime limits is a contributor to worker fatigue. Using the Phase 1 worksheet
in Manual Chapter 0609, "Significance Determination Process," this finding is
determined to be of very low safety significance because there were no known
actual adverse plant or equipment conditions that could be attributed to worker
fatigue (Section 4OA2).
Cornerstone: Barrier Integrity
SLIV. A Severity Level IV noncited violation of 10 CFR Part 50, Appendix B,
Criterion XVI, "Corrective Action," was identified for the failure to correct a
nonconforming condition in a timely manner. Specifically, since June 2001, the
licensee discontinued implementation of required Technical Specification
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Enclosure
surveillance testing for the containment purge valves by declaring the valves
inoperable and installing blind flanges. This issue was entered into the
corrective action program as Condition Report/Disposition Request 2711167.
The finding is greater than minor because the licensee's failure to submit a
license amendment to correct the nonconforming condition impacted the NRC's
ability to perform its regulatory function. Therefore, this finding was considered
applicable to traditional enforcement. Although the significance determination
process is not designed to assess the significance of violations that potentially
impact or impede the regulatory process, the finding can be assessed using the
significance determination process. Using the Phase 1 worksheet in Manual
Chapter 0609, "Significance Determination Process," the finding is determined
to have very low safety significance because it only affected the barrier integrity
cornerstone and the installation of blind flanges adequately maintained
containment integrity (Section 1R15).
Green. A noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI,
"Corrective Action," was identified for the failure to correct a degraded refueling
machine equipment condition that could have impacted the ability to safely
handle fuel. Specifically, refueling personnel continued to move spent fuel even
though they had determined that the refueling machine sprag brake had failed.
The issue involved human performance crosscutting aspects associated with
poor decision making and a lack of questioning attitude by refueling personnel.
This issue was entered into the corrective action program as Condition
Report/Disposition Request 2704331.
The finding is greater than minor since it could become a more significant safety
concern if left uncorrected in that continuing core alterations using degraded
equipment impacts the ability to safely handle spent fuel and increases the
likelihood of a fuel handling accident. Using the Phase 1 worksheets in Manual
Chapter 0609, "Significance Determination Process," this finding is determined
to have very low safety significance because it only affects the barrier integrity
cornerstone and was a deficiency that did not result in the actual degradation of
spent fuel (Section 1R20).
Green. A self-revealing finding was identified when a pressurizer level transient
above Technical Specification limits occurred. Specifically, simultaneous testing
of the atmospheric dump valve and boron injection systems resulted in a loss of
letdown event on high regenerative heat exchanger temperature. The letdown
event occurred because operations personnel were using a single charging
pump for the boron injection test and using excess letdown to accommodate a
plant heatup following atmospheric dump valve testing. The combination of
activities resulted in pressurizer level exceeding the Technical Specification limit
of 56 percent. The issue involved human performance crosscutting aspects
associated with operator decision making, questioning attitude, awareness of
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Enclosure
plant conditions, and communications between personnel performing concurrent
evolutions. This issue was entered into the corrective action program as
Condition Report/Disposition Request 2707290.
The finding is greater than minor because it is associated with the equipment
performance attribute of the barrier integrity cornerstone and affects the
cornerstone objective of protecting the reactor coolant system barrier from
radionuclide releases caused by accidents or events. Using the Phase 1
worksheet in Manual Chapter 0609, "Significance Determination Process," the
finding is determined to have very low safety significance because it only affects
the barrier integrity cornerstone and was a deficiency that did not result in the
actual degradation of the reactor coolant system barrier (Section 1R22).
Green. A self-revealing noncited violation of 10 CFR Part 50, Appendix B,
Criterion V, was identified for the failure to secure a main steam line pipe whip
restraint inside the Unit 2 containment in accordance with design drawings.
Specifically, the pipe whip restraint was missing four 1/2-inch diameter nuts from
the embedded anchor bolts. This issue was entered into the corrective action
program as Condition Report/Disposition Request 2643347.
The finding is greater than minor since it is associated with the equipment
performance attribute of the barrier integrity cornerstone and affects the
cornerstone objective of protecting the containment barrier from radionuclide
releases caused by accidents or events. Using the Phase 1 worksheet in
Manual Chapter 0609, "Significance Determination Process," this finding is
determined to have very low safety significance because it did not represent an
actual open pathway in the physical integrity of the reactor containment and did
not represent an actual reduction of the atmospheric pressure control function
of the reactor containment (Section 4OA5).
B.
Licensee-Identified Violations
Violations of very low safety significance which were identified by the licensee have
been reviewed by the inspectors. Corrective actions taken or planned by the licensee
have been entered into the licensee's corrective action program (Section 4OA7).
Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at essentially full power until April 3, 2004, when the unit was shut down for
Refueling Outage 1R11. Following reactor startup on May 8, 2004, the reactor was manually
tripped from Mode 2 following slipping of a control element assembly (CEA) approximately
6 inches into the core. Repairs were completed and the unit returned to essentially full power
on May 14, 2004. On June 14, 2004, Unit 1 experienced a reactor trip after a loss of offsite
power (LOOP). Following the evaluation of the event and impacted systems, a reactor startup
was completed and the unit was returned to essentially full power on June 20, 2004. On
June 21, 2004, Unit 1 experienced a reactor power cutback to 55 percent power due to the
loss of main feedwater (MFW) pump Train B on low suction pressure. Repairs were completed
and the unit was returned to essentially full power on June 23, 2004, and remained there for
the duration of the inspection period.
Unit 2 operated at full power until June 14, 2004, when the unit experienced a reactor trip after
a LOOP. Following the evaluation of the event and impacted systems, a reactor startup was
completed, and the unit was returned to essentially full power on June 20, 2004, where it
remained for the duration of the inspection period.
Unit 3 operated at full power operation until May 11, 2004, when a leak developed on the
Condenser C vent line, requiring a reduction in power to approximately 40 percent. Repairs
were completed and the unit was returned to essentially full power on May 15, 2004. On
June 7, 2004, a reactor power cutback followed by an automatic reactor scram occurred when
an electrohydraulic control cabinet electrical malfunction resulted in the closure and
subsequent reopening of three combined intercept valves. Reactor startup was completed on
June 9, 2004, and Mode 1 entered on June 10. At approximately 12 percent reactor thermal
power, the main turbine was manually tripped following unexpected combined intercept valve
movement. On June 11, 2004, Mode 2 was re-entered and the reactor was downpowered to
approximately 3 percent reactor thermal power while additional troubleshooting was
performed. The licensee determined that a backup speed probe had an intermittent failure.
Once repairs were completed, a reactor startup was initiated and the unit was returned to
essentially full power on June 13, 2004. On June 14, 2004, Unit 3 experienced a reactor trip
after a LOOP. Following the evaluation of the event and impacted systems, a reactor startup
was completed and the unit was returned to essentially full power on June 21, 2004, where it
remained for the duration of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
1R04
Equipment Alignment (71111.04)
a.
Inspection Scope
The inspectors completed a partial walkdown of the three systems listed below to verify
proper equipment alignment. This inspection included a review of the applicable plant
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procedures, plant drawings, outstanding modifications, work orders (WOs), and
condition report/disposition requests (CRDRs). The inspectors verified the following:
all valves were properly aligned; there was no leakage that could affect operability;
electrical power was available as required; major system components were properly
labeled, lubricated, and cooled; and hangers and supports were correctly installed and
functional.
April 6, 2004, shutdown cooling (SDC) Train B during midloop operations
(Unit 1)
April 9, 2004, emergency diesel generator Train B (Unit 1)
April 28, 2004, emergency diesel generator Train A (Unit 1)
b.
Findings
No findings of significance were identified.
1R05
Fire Protection (71111.05Q)
a.
Inspection Scope
The inspectors conducted tours of the five areas listed below that are important to
reactor safety and referenced in the Pre-fire Strategies Manual to evaluate conditions
related to licensee control of transient combustibles and ignition sources; the material
condition, operational status, and operational lineup of fire protection systems,
equipment and features; and the fire barriers used to prevent damage from propagation
of potential fires.
April 8, 2004, containment building all accessible areas (Unit 1)
April 20, 2004, fire pump house (Units 1, 2, and 3)
June 2, 2004, fuel building all elevations (Unit 1)
June 3, 2004, fuel building all elevations (Unit 2)
June 4, 2004, fuel building all elevations (Unit 3)
b.
Findings
No findings of significance were identified.
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1R07
Heat Sink Performance (71111.07)
a.
Inspection Scope
During the Unit 1 outage, licensee personnel conducted an inspection of the Train A
essential cooling water heat exchanger. The inspectors reviewed test and analysis
results for the Train A essential cooling water heat exchanger. Using
Procedure 70TI-9EW01, "Thermal Performance Testing of Essential Cooling Water
Heat Exchangers," Revision 4, heat exchanger data was collected on April 3, 2004.
Additional data was collected on May 5, 2004, after the licensee cleaned the heat
exchanger. The data was analyzed using Procedure 73DP-9ZZ10, "Guidelines for
Heat Exchanger Thermal Performance Analysis," Revision 4. The inspectors' review
was conducted to determine if the test acceptance criteria and results appropriately
considered the differences between testing and design conditions and if the results
were appropriately measured against pre-established acceptance criteria.
b.
Findings
No findings of significance were identified.
1R08
Inservice Inspection Activities (71111.08)
a.
Inspection Scope
1.
Performance of Nondestructive Examination Activities Other than Steam Generator
Tube Inspections
Procedure 71111.08 requires the review of a minimum sample of five nondestructive
examination activities of at least three different types. The inspector witnessed the
performance of five volumetric examinations, nine surface examinations, and one
visual examination. This sample of 15 nondestructive examination activities of three
types is listed in the enclosed attachment.
For each of the nondestructive examination activities reviewed, the inspector verified
that the examinations were performed in accordance with American Society of
Mechanical Engineers (ASME) Code requirements.
During the review of each examination, the inspector verified that appropriate
nondestructive examination procedures were used, that examinations and conditions
were as specified in the procedure, and that test instrumentation or equipment was
properly calibrated and within the allowable calibration period. The inspector also
reviewed documentation to verify that indications revealed by the examinations were
dispositioned in accordance with the ASME Code specified acceptance standards.
The inspector verified the certifications of approximately five nondestructive
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examination personnel (Lambert-MacGill-Thomas, Inc.) observed performing
examinations or identified during review of completed examination packages.
The inspection procedure requires review of one or two examinations from the previous
outage with recordable indications that were accepted for continued service to ensure
that the disposition was done in accordance with the ASME Code. The inspector
selected several recordable indications that required evaluation during the last outage.
The licensee evaluated the indications in accordance with the ASME Code
requirements. These indications did not exceed any code requirements. Corrective
actions reviewed by the inspector were appropriate.
If the licensee completed welding on the pressure boundary for Class 1 or 2 systems
since the beginning of the previous outage, the procedure requires verification that
acceptance and preservice examinations were done in accordance with the ASME
Code for one to three welds. The inspector reviewed the welding activity associated
with the replacement of Class 2 piping on the containment spray system discharge
during the current outage (WO 2590635).
The procedure also requires verification that one or two ASME Code Section XI repairs
or replacements meet code requirements. The inspector reviewed and observed one
ASME Code,Section XI, replacement activity associated with the replacement of
Class 2 piping on the containment spray system discharge line. The inspector verified
that the repair or replacement activities were in accordance with Section XI
requirements.
b.
Findings
No findings of significance were identified.
2.
Steam Generator Tube Inspection Activities
a.
Inspection Scope
The inspection procedure specified performance of an assessment of in-situ screening
criteria to assure consistency between assumed nondestructive examination flaw sizing
accuracy and data from the Electric Power Research Institute examination technique
specification sheets. It further specified assessment of appropriateness of tubes
selected for in-situ pressure testing, observation of in-situ pressure testing, and review
of in-situ pressure test results. The inspector observed the performance of a pressure
test performed on Steam Generator Tube 148-87. The test was performed in
accordance with the Westinghouse in-situ test procedure. Procedures reviewed were
appropriate for the test required.
The inspection procedure specified comparing the estimated size and number of tube
flaws detected during the current outage against the previous outage operational
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assessment predictions to assess the licensees prediction capability. The inspector
verified that the licensees prediction of flaws detected this outage were consistent with
the actual flaws identified through their flaw predication program.
The inspection procedure specified confirmation that the steam generator tube eddy
current test scope and expansion criteria meet Technical Specification requirements,
Electric Power Research Institute guidelines, and commitments made to the NRC. The
inspector reviewed the steam generator tube eddy current test scope and expansion
criteria and found no deficiencies.
The inspection procedure required confirmation that the licensee inspected all areas of
potential degradation, especially areas which were known to represent potential eddy
current test challenges (e.g., top-of-tube sheet, tube support plates, batwing area, and
U-bends). The inspector confirmed whether all known areas of potential degradation,
including eddy current test challenged areas, were included in the scope of inspection
and were being inspected.
The inspection procedure also required confirmation of adherence to the Technical
Specification plugging limit. The inspection procedure required determination of
whether depth sizing repair criteria were being applied for indications other than wear
or axial primary water stress corrosion cracking in dented tube support plate
intersections. The inspector confirmed that the licensee was adhering to these
specifications.
If steam generator leakage greater that 3 gallons per day was identified during
operations or during postshutdown visual inspections of the tube sheet face, the
inspection procedure required verification that the licensee had identified a reasonable
cause and corrective actions for the leakage based on inspection results. The
inspector determined that leakage greater than 3 gallons per day did not exist.
The inspection procedure required confirmation that the eddy current test probes and
equipment were qualified for the expected types of tube degradation and assessment
of the site-specific qualification of one or more techniques. The inspector observed
portions of all eddy current tests performed. During these examinations, the inspector
verified that: (1) the probes appropriate for identifying the expected types of indications
were being used, (2) probe position location verification was performed, (3) calibration
requirements were adhered to, and (4) probe travel speed was in accordance with
procedural requirements.
The inspection procedure requires confirmation of the licensees corrective action if
loose parts or foreign material on the secondary side is identified. The inspector
reviewed the licensees foreign object search and retrieval summary report for the
Refueling Outage 1R11 steam generator secondary side. This report indicates that the
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licensee is aggressively tracking and identifying any loose parts within the steam
generators' secondary side and implementing appropriate corrective actions when
needed.
Finally, the inspection procedure specified review of one to five samples of eddy
current test data if questions arose regarding the adequacy of eddy current test data
analyses. The inspector did not identify any results where eddy current test data
analyses adequacy was questionable.
b.
Findings
No findings of significance were identified.
3.
Identification and Resolution of Problems
a.
Inspection Scope
The inspector reviewed approximately seven inservice inspection related CRDRs
issued during the current and past refueling outages. The review served to verify that
the licensees corrective action process was being correctly utilized to identify
conditions adverse to quality and that those conditions were being adequately
evaluated, corrected, and trended. The inspector also concluded that corrective
actions were being appropriately addressed.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification (71111.11Q)
a.
Inspection Scope
On May 20, 2003, the inspectors observed operations crew performance during
evaluated simulator Scenario SES-10-A-00, "Steam Generator Tube Leak." The
inspectors evaluated the simulator scenario, the crew performance, and the evaluator
critique sessions conducted following the completion of the simulator scenario.
Additionally, the inspectors compared simulator board configurations with actual control
room board configuration for consistency.
b.
Findings
No findings of significance were identified.
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1R12
Maintenance Effectiveness (71111.12Q)
a.
Inspection Scope
For the two failures listed below, the inspectors verified the licensee's appropriate
handling of structure, system, and component performance or condition problems;
reviewed the use of industry operating experience for establishing preventive
maintenance programs; and verified that licensee personnel properly implemented the
requirements of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of
Maintenance at Nuclear Power Plants":
Failure of high pressure safety injection Valve 3JSIAUV0627 to stroke closed on
demand, documented in CRDR 2682409, dated February 10, 2004, (Unit 3)
Low pressure indication for main steam isolation Valve MSIV-180 Train B
accumulator, documented in CRDR 2693900 (Unit 2)
b.
Findings
No findings of significance were identified.
1R13
Maintenance Risk Assessments and Emergent Work Evaluation (71111.13)
a.
Inspection Scope
Throughout this inspection period, the inspectors reviewed daily and weekly work
schedules to determine when risk significant activities were scheduled. The inspectors
reviewed risk evaluations and overall plant configuration control for four selected
activities to verify compliance with Procedure 30DP-9MT03, "Assessment and
Management of Risk When Performing Maintenance in Modes 1 - 4," Revision 8. The
inspectors discussed emergent work issues with work control personnel and reviewed
the potential risk impact of these activities to verify that the work was adequately
planned, controlled, and executed.
April 24, 2004, evaluated the licensee's assessment associated with moving the
upper guide structure lift rig to the core support stand for CEA 16 changeout
with fuel in the vessel. CEA Extension Shaft 16 was stuck into its respective
self- latching mechanism (Unit 1)
June 2, 2004; evaluated the licensee's assessment associated with Startup
Transformer AENANX03 being unable to be electrically isolated due to the
failure of the 525 kV crossover breaker between Startup Transformer X03 and
Devers MAN-PL-995 (Unit 3)
June 3, 2004; troubleshooting position indication loss for high pressure safety
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injection discharge Valve 2JSIAHV0698 per WO 2713742 (Unit 2)
June 18, 2004; evaluated the licensees controls for maintaining voltage limits
for offsite power when Unit 1 paralleled the main generator to the grid (Unit 1)
b.
Findings
No findings of significance were identified.
1R14
Operator Performance During Nonroutine Plant Evolutions (71111.14, 71153)
a.
Inspection Scope
The inspectors observed the following seven nonroutine evolutions to verify that they
were conducted in accordance with licensee procedures and Technical Specifications:
On April 19, 2004, an underground fire main ruptured, spilling approximately
278,000 gallons of water. The rupture occurred at the plant northeast corner of
the Unit 3 essential spray pond. The rupture was isolated in approximately
45 minutes by the fire department.
The inspectors evaluated that the actions taken by operations and the fire
department personnel were in accordance with licensee procedures and the
Technical Requirements Manual. The inspectors discussed the plant response
to the event with the control room operators, fire department personnel, and
plant management. This event was documented in CRDR 2700170.
On May 8, 2004, Unit 1 reactor operators manually tripped the reactor when
CEA 89 slipped approximately 6 inches while conducting low power physics
testing following Refueling Outage 11.
The inspectors responded to the control room to evaluate the plant conditions
and operator performance. The inspectors performed a control board walkdown
to verify all safety equipment responded as required. The inspectors discussed
the plant response to the event with the control room operators and plant
management. This Unit 1 event was documented in CRDR 2707423.
On May 11, 2004, Unit 3 developed a leak on the Condenser C vent line
(Circulating Water Line 3PCWNL031 near Valve CWNV081), requiring a
reduction in power to approximately 40 percent.
The inspectors responded to the control room to evaluate the plant conditions
and operator performance. The inspectors performed a control board walkdown
to verify all safety equipment responded as required. The inspectors discussed
the plant response to the event with the control room operators and plant
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management. This Unit 3 event was documented in CRDR 2707578.
On May 14, 2004, while performing vacuum drying on Canister 16 in the Unit 3
cask load pit, an unintended transfer of approximately 20 gallons of water
occurred from the spent fuel pool (SFP) to the cask load pit via the cask
drainage piping. The licensee entered abnormal operating
Procedure 40AO-9ZZ23, "Loss of SFP Level or Cooling," Revision 7, for this
event.
The inspectors responded to this event, walked down the area, and reviewed
drawings of the installation cask drainage piping. The inspectors discussed the
event with the control room operators and plant management. This event is
documented in CRDR 2709518.
On June 7, 2004, Unit 3 had a reactor power cutback and reactor trip due to a
problem with the electrohydraulic control system.
The inspectors responded to the control room to evaluate the plant conditions
and operator performance. The inspectors performed a control board walkdown
to verify all safety equipment responded as required. The inspectors discussed
the plant response to the event with the control room operators and plant
management. This Unit 3 event was documented in CRDR 2714544.
On June 14, 2004, the inspectors responded to the control rooms to evaluate
the plant conditions and operator performance following the LOOP and reactor
trips on Units 1, 2, and 3. Units 1 and 3 declared a notice of unusual event for
the LOOP, and Unit 2 declared an alert, due to emergency diesel generator
Train A not maintaining voltage. The inspectors responded to Unit 2 and the
technical support center. Visiting reactor inspectors responded to Units 1 and 3.
The inspectors discussed the plant response to the event with the control room
operators and plant management.
On June 14, 2004, an Augmented Inspection Team was chartered to evaluate
this event. The results will be documented in NRC Augmented Inspection
Report 05000528; 05000529; 05000530/2004012.
On June 21, 2004, Unit 1 had a reactor power cutback to approximately
55 percent power, due to a trip of Condensate Pump B.
The inspectors responded to the control room to evaluate the plant conditions
and operator performance. The inspectors performed a control board walkdown
to verify all equipment responded as required. The inspectors discussed the
plant response to the event with the control room operators and plant
management. This Unit 1 event was documented in CRDR 2717298.
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b.
Findings
Introduction. A Green self-revealing noncited violation of Technical Specification 4.3.2
was identified for the failure to maintain a check valve (siphon breaker) between the
vacuum drying skid and the SFP. On May 14, 2004, the check valve failed to open and
caused an inadvertent siphoning of approximately 20 gallons from the Unit 3 SFP to the
cask washdown pit.
Description. On May 14, 2004, the licensee performed vacuum drying on Canister 16
in the Unit 3 cask load pit. The vacuum drying process had been completed, and the
licensee was preparing to perform a rate-of-rise test on the cask to verify all water had
been removed. After manipulating valves and stopping the vacuum pump, licensee
personnel identified water leaking from a crack on the vacuum pump discharge muffler.
The licensee attempted to stop the leak by opening a drain valve on the discharge of
the pump. After approximately 30 seconds of draining this discharge line, the licensee
recognized that the leakage was water that was being siphoned from the SFP due to a
check valve that failed to open. The licensee took immediate actions to remove the
check valve in order to establish a vent path to terminate the water transfer from the
SFP.
Through interviews with the licensee the inspectors were informed that the check valve
had been installed in January 2004. The inspectors noted that the check valve was not
tested or in a preventive maintenance program.
Analysis. The inspectors identified a performance deficiency for the failure to perform
postinstallation testing that would demonstrate the operability of the check valve, thus
preventing the possibility of an inadvertent draining of the SFP. The finding is greater
than minor because it affected the configuration control attribute of the initiating events
cornerstone. This finding cannot be evaluated by the significance determination
process because Manual Chapter 0609, "Significance Determination Process,"
Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power
Situations," and Appendix G, "Shutdown Operations Significance Determination
Process," do not apply to the SFP. This finding is determined to be of very low safety
significance by management review because radiation shielding was provided by the
SFP water level, the SFP cooling system and fuel building ventilation systems were
available, and there were multiple sources of makeup water.
Enforcement. Technical Specification 4.3.2 required that the spent fuel storage pool be
designed and maintained to prevent inadvertent draining of the pool below 137 feet
6 inches. Contrary to the above, a check valve on a vacuum drying skid connected to
the SFP was not maintained to assure that it would prevent inadvertent draining of the
SFP. On May 14, 2004, this check valve failed to open and caused an inadvertent
draining of approximately 20 gallons of water from the Unit 3 SFP to the cask
washdown pit. Had operators not intervened, the failure of this check valve could have
potentially caused an inadvertent draining of the SFP to elevation 127 feet 3 inches
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(below elevation 137 feet 6 inches required by Technical Specifications). Because the
finding was of very low significance and has been entered into the licensees corrective
action program as CRDR 2709518, this finding is being treated as a noncited violation
consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000530/2004003-01, "Spent Fuel Pool Water Siphon due to Check Valve Failure."
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors evaluated the six operability determinations listed below for technical
adequacy and assessed the impact of the condition on continued plant operation.
Additionally, the inspectors reviewed Technical Specification entries, CRDRs, and
equipment issues to verify that operability of plant structures, systems, and components
was maintained or that Technical Specification actions were properly entered.
May 5, 2004; resolution of equipment failures following emergency diesel
generator Train A outage maintenance and associated operability justifications
documented in CRDRs 2703945 and 2705929 (Unit 1)
May 11, 2004; assessed the resolution of azimuthal tilt and increase of core
operating limits report limit documented in CRDR 2707812 (Unit 1)
April 15, 2004; operability evaluation for Snubber 2SI123H001 installed on the
containment spray/low pressure safety injection system discharge piping that
was identified as potentially locked-up on March 30, 2004, as documented in
CRDRs 2693663 and 2704218 (Unit 2)
Reviewed Technical Specification Component Condition Record 2375153,
"LCO 3.6.3 Containment Isolation Valves SR 3.6.3.6 Not Performed Adequately
for CP 2B and 3A," and the licensee's overall response to the degraded and
nonconforming condition (Units 1, 2, and 3)
April 27, 2004; assessed the impact of potential unqualified coatings being
identified in at least five areas at the 80-foot elevation of containment (Unit 1)
June 25, 2004; assessed available thrust for motor-operated
Valve 2JSGNHV1143 was less than minimum administrative limit as
documented in CRDR 2639681 (Unit 2)
b.
Findings
Introduction. A Severity Level IV noncited violation was identified for failure to correct a
nonconforming condition in a timely manner. The nonconformance involved long-term
actions taken to compensate for containment purge isolation valve design deficiencies.
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Description. In March 2001, the licensee determined that the 42-inch containment
purge isolation Valve CP-UV-2A/3B, had unreliable seals against containment pressure
and declared the valves inoperable. On June 15, 2001, the licensee developed an
interim strategy for containment purge Penetrations 56 and 57 due to the inability to
satisfy Technical Specification Surveillance Requirement 3.6.3.6. The interim strategy
involved declaring the inboard and outboard valves inoperable and installing blind
flanges to comply with the required actions of Technical Specification 3.6.3,
Condition D, in Modes 1-4. This strategy discontinued the performance of leak rate
testing of the valves and enable continued operations with the installation of blind
flanges on Units 1, 2, and 3. On June 18, 2002, the licensee approved a long-term
strategy to make the 42-inch containment purge penetration blind flanges part of the
permanent plant configuration.
Technical Specification Bases 3.0.2 states, in part, that intentional entry into ACTIONS
should not be made for operational convenience. The inspectors determined that the
interim strategy adopted by the licensee inappropriately used Technical Specification
actions. Further, the inspectors observed that the licensee planned to use the actions
required by Technical Specification 3.6.3, Condition D, to continue plant operations
until implementation of a permanent modification in 2005 and 2006. The inspectors
concluded that the licensee's schedule to correct the nonconforming condition through
permanent plant modification did not meet NRC guidelines. Generic Letter 91-18,
"Information to Licensees Regarding NRC Inspection Manual Section on Resolution of
Degraded and Nonconforming Conditions," states, in part, that the NRC expects time
frames longer that the next refueling outage to be explicitly justified by the licensee as
part of the deficiency tracking documentation. The inspectors concluded that a
permanent plant modification should have been implemented at the first available
opportunity following identification of the degraded and nonconforming condition. This
conclusion is based, in part, on the lack of justification for intentional entry into the
actions of Technical Specification 3.6.3, Condition D, during Modes 1-4. Timely
correction of the nonconforming condition would have identified the need for NRC
review of a license amendment through 10 CFR 50.59(c)(1).
Analysis. The failure to correct the nonconforming condition in a timely manner through
permanent plant modification is determined to have more than minor significance
because the licensee's failure to submit a license amendment impacted the NRC's
ability to perform its regulatory function. This finding is associated with the barrier
integrity cornerstone. This finding was considered applicable to traditional
enforcement. Although the significance determination process is not designed to
assess the significance of violations that potentially impact or impede the regulatory
process, the finding can be assessed using the significance determination process.
Using the Phase 1 worksheet in Manual Chapter 0609, "Significance Determination
Process," the finding is determined to have very low safety significance because it only
affected the barrier integrity cornerstone and the installation of blind flanges adequately
maintained containment integrity.
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Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires
in part, that conditions adverse to quality be promptly identified and corrected. Contrary
to the above, the licensee did not correct a condition adverse to quality in a timely
manner. Specifically, the licensee failed to correct the 42-inch containment purge
penetration nonconforming condition at the first available opportunity. In place of
promptly correcting the condition, the licensee elected to implement the actions of
Technical Specification 3.6.3, Condition D, in Modes 1-4 instead of restoring the purge
valves to an operable condition. This Severity Level IV violation is being treated as a
noncited violation, consistent with Section VI.A of the NRC Enforcement Policy. This
violation is in the licensees corrective action program as CRDR 2711167.
NCV 05000528; 05000529;05000530/2004003-02, "Containment Purge Penetration
NonConformance."
1R17
Permanent Plant Modifications (71111.17A)
Fillet Weld Buildup on Small Drain Lines on the Safety Injection Suction Line Train B
a.
Inspection Scope
The inspectors reviewed the modifications to the welds on Unit 1 safety injection
suction line Train B via Design Master WO 2692447 and Design Implementation
WO 2695338 to verify that it was being performed in accordance with regulatory
requirements and plant procedures. The inspectors interviewed the licensee personnel
installing the modification as to their understanding of the modification package and
observed work in progress. The inspectors also observed portions of modification work
to verify that: (1) the work package was at the work site, (2) transient combustible
material was appropriately controlled, (3) construction material was appropriately
staged, and (4) construction debris was kept to a minimum.
b.
Findings
No findings of significance were identified.
1R19
Postmaintenance Testing (71111.19)
a.
Inspection Scope
The inspectors observed or evaluated the results from the following eight
postmaintenance tests to determine whether the test adequately confirmed equipment
operability. The inspectors also verified that postmaintenance tests satisfied the
requirements of Procedure 30DP-9WP04, "Postmaintenance Testing Development,"
Revision 13.
April 7, 2004; cleaning of the emergency diesel generator Train B fuel oil
storage tank via WO 2439603 (Unit 1)
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Enclosure
April 14, 2004; removal of an electrical boot installed on Valve 1-SIB-UV-0626
identified during the performance of Preventive Maintenance Task 2612939
(Unit 1)
April 17, 2004; welding repairs on the MFW pump Train A turbine casing drains
per WOs 2609675 and 2699452 (Unit 1)
April 19, 2004; troubleshooting and resolution of low pressure safety injection
Pump B abnormal noise identified during performance of
Procedure 40OP-9CH12, "Refueling Water Tank Operations," Section 8,
Revision 18 (Unit 2)
May 7, 2004; troubleshooting of sticky latching mechanism for the upper gripper
coil on CEA 89 per WO 2706748 (Unit 1)
June 3, 2004; high pressure safety injection flow verification using
Procedure 73ST-9SI10, "HPSI A Inservice Test," Revision 29, per WO 2592003
(Unit 2)
June 8, 2004; troubleshooting of indication of a low lube oil pressure trip on
emergency diesel generator Train A per WO 2714674 (Unit 3)
June 15-16; troubleshooting of the failure of emergency diesel generator Train
A to maintain voltage per WO 2715735 (Unit 2)
b.
Findings
1.
MFW Pump Fire Flash
Introduction. The inspectors identified a Green noncited violation of Technical Specification 5.4.1.d for the failure to remove residual alcohol from the MFW pump
Train A turbine casing prior to commencing hot work activities. Consequently, a flash
fire occurred when a oxy-acetylene torch was used to preheat the metal for welding.
Description. On April 17, 2004, while performing planned corrective maintenance (weld
buildup) on the drains on the MFW pump Train A turbine casing, an unexpected flash
fire occurred. Isopropyl alcohol was used during the final cleaning process for the
turbine casing. However, as part of the maintenance activity, maintenance personnel
did not adequately remove the residual alcohol prior to the commencement of the hot
work. The flash fire occurred while preheating the turbine casing metal with an
oxy-acetylene torch and resulted in two mechanics receiving burns to their exposed
facial areas.
The licensee conducted a site-wide standdown on the event and performed an
investigation documented in CRDR 2699943. The licensee determined that the
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maintenance personnel had not been adequately informed of personnel safety
hazards, as required by Procedure 30DP-9WP02, "Work Document Development and
Control," Revision 34. Also, the controlling WOs 2609675 and 2699452 did not
adequately identify appropriate cleaning instructions to ensure that residual alcohol
from the MFW pump turbine casing was removed prior to preheating the metal.
Analysis. The finding is greater than minor because it could become a more significant
safety concern if left uncorrected, in that a fire could ignite in an area with risk important
equipment. This finding is associated with the initiating events cornerstone. This
finding cannot be evaluated by the significance determination process. Manual
Chapter 0609, "Significance Determination Process," Appendix F, "Determining
Potential Risk Significance of Fire Protection and Post-Fire Safe Shutdown Inspection
Findings," does not address the potential risk significance of shutdown fire protection
findings. Additionally, Manual Chapter 0609, Appendix G, "Shutdown Operations
Significance Determination Process," does not address fire protection findings.
However, the finding is determined to be of very low safety significance by
management review because the finding occurred while the unit was already in a cold
shutdown condition and the finding involved equipment not necessary to maintain safe
shutdown.
Enforcement. Technical Specification 5.4.1.d requires, in part, that written procedures
be established, implemented, and maintained for fire protection program
implementation. Fire protection program Procedure 14DP-0FP36, "Hot Work Permit,
Revision 9, step 3.1.1.2, required, in part, that hot work not be performed in areas
where the presence of other flammable compounds creates a hazard. Contrary to this
requirement, isopropyl alcohol, a flammable compound, was not adequately cleaned
from the surfaces of the MFW pump Train A turbine casing. Consequently, a fire
occurred when an oxy-cetylene torch was used to preheat the metal for welding.
Because the finding is of very low safety significance and has been entered into the
corrective action program as CRDR 2699943, this violation is being treated as a
noncited violation, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000528/2004003-03, "Fire That Occurred During Welding Activities on MFW
Pump Turbine Train A."
1R20
Refueling and Outage Activities (71111.20)
a.
Inspection Scope
The inspectors reviewed the licensee's Unit 1 Refueling Outage 1R11 shutdown risk
assessment to confirm that the licensee had appropriately considered risk, industry
experience, and a previous site-specific problem in developing and implementing a plan
that assured maintenance of defense-in-depth. During the refueling outage, the
inspectors observed portions of the shutdown and cooldown processes and monitored
licensee controls over the outage activities listed below. Documents reviewed during
the inspection are listed in the attachment.
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Licensee configuration management, including maintenance of
defense-in-depth commensurate with the shutdown risk assessment for key
safety functions and compliance with the applicable Technical Specifications
when taking equipment out of service
Implementation of clearance activities and confirmation that tags were properly
hung and equipment appropriately configured to safely support the work or
testing
Installation and configuration of reactor coolant pressure, level, and temperature
instruments to provide accurate indication and an accounting for instrument
error
Controls over the status and configuration of electrical systems to ensure that
Technical Specification and outage safety plan requirements were met, and
controls over switchyard activities
Monitoring of decay heat removal processes
Controls to ensure that outage work was not impacting the ability of the
operators to operate the SFP cooling system
Reactor water inventory controls including flow paths, configurations, and
alternative means for inventory addition, and controls to prevent inventory loss
Controls over activities that could affect reactivity
Maintenance of secondary containment as required by Technical Specification
Refueling activities
Startup and ascension to full power operation, tracking of startup prerequisites,
walkdown of the drywell (primary containment) to verify that debris had not been
left which could block emergency core cooling system (ECCS) suction strainers,
and reactor physics testing
Licensee identification and resolution of problems related to refueling outage
activities
b.
Findings
Degraded Refueling Machine
Introduction. A Green noncited violation was identified for failing to correct a degraded
refueling machine equipment condition that could have impacted the ability to safely
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handle fuel.
Description. On April 27, 2004, the inspectors questioned the licensee's decision to
continue core alterations following the identification of a degraded equipment condition
associated with the refueling machine hoist. The refueling machine driver noticed that
the sprag brake was not functioning properly while lowering a fuel assembly into the
reactor vessel. The sprag brake functions to slow the downward motion if the speed
exceeds that of the input mode, either electrical motor or manual crank shaft, used to
lower the assembly. The licensee decided to electrically raise and lower the fuel
assembly to determine if the sprag brake was functioning properly. Following this
troubleshooting evolution, which confirmed that the sprag brake was degraded, the
licensee manually lowered the fuel assembly into the appropriate core location in
accordance with contingencies provided in Procedure 78OP-9FX01, "Refueling
Machine Operations," Revision 17, Appendix G, "Manual Operation of the Refueling
Machine."
The licensee decided to continue core alterations with the degraded refueling machine
hoist to raise a second fuel assembly already located in the vessel, rotate the assembly
to a different orientation, and then manually lower it back into the reactor vessel. The
inspectors identified that the licensee inappropriately implemented contingencies in
Procedure 78OP-9FX01, Appendix K, "Action Plan for Movement of a Difficult
Assembly," to operate the refueling machine hoist in manual mode. Step 3.1.5 of this
procedure states, "The refueling machine hoist shall not be operated manually except
to place a fuel assembly in a safe condition, or for testing, maintenance, or operations
involving an assembly which is not seating, lowering, or raising correctly." The licensee
justified manual hoist operation based on the need to use Appendix K when the
assembly was initially seated in the vessel in a rotated position, even though a "difficult
assembly" condition did not actually exist. Furthermore, operators believed that the
degraded brake condition only affected electric motor operation and failed to recognize
that the degraded condition also impacted manual hoist operation. The licensee
suspended further core alterations following movement of the second fuel assembly
until refueling machine sprag brake repairs were completed.
Analysis. The finding is greater than minor since it would become a more significant
safety concern if left uncorrected, in that continuing core alterations using degraded
equipment impacts the ability to safely handle fuel and increases the probability of a
fuel handling accident. This finding is associated with the barrier integrity cornerstone.
Using the Phase 1 worksheets in Manual Chapter 0609, "Significance Determination
Process," the finding was determined to have very low safety significance because it
only affects the barrier integrity cornerstone and was a deficiency that did not result in
the actual degradation of the fuel cladding barrier. The finding involved human
performance crosscutting aspects associated with poor decision making and a lack of
questioning attitude by operations and refueling personnel.
Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires,
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in part, that conditions adverse to quality be promptly identified and corrected. Contrary
to the above, the licensee did not promptly correct a condition adverse to quality.
Specifically, the licensee identified a degraded equipment condition associated with the
refueling machine sprag brake and continued core alterations prior to correcting the
degraded condition. Because the finding is of very low safety significance and has
been entered into the corrective action program as CRDR 2704331, this violation is
being treated as a noncited violation, consistent with Section VI.A of the NRC
Enforcement Policy: NCV 05000528/2004003-04, "Core Alterations with Degraded
Refueling Machine."
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
Applicable test data was reviewed to verify whether the licensee met Technical
Specification, Updated Final Safety Analysis Report, and licensee procedure
requirements. The inspectors verified that testing effectively demonstrated that
systems were operationally ready and capable of performing their intended safety
functions and that identified problems were entered into the corrective action program
for resolution. The inspectors observed the performance of and reviewed
documentation for the following five surveillance tests:
On April 12, 2004, performance of Procedure 73ST-9LC01-1, "Containment
Leakage Type "B" and "C" Testing," on Penetration 22 (Unit 1)
On April 15-16, 2004, performance of Procedure 73ST-9DG02, "Class 1E Diesel
Generator and Integrated Safeguards Test Train B," Revision 8, Section 8.5,
"DG-B 24 Hour Continuous Load Test/100% Load Rejection/DG-B Hot Start"
(Unit 1)
On May 7, 2004, performance of Procedure 73TI-9SG03, "ADV 30% Partial
Stroke Test," Revision 5 (Unit 1)
On June 9, 2004, performance of Procedure 36ST-9SI05, "SDC Interlocks Loop
& Alarm Calibration," Appendix G, Revision 4 (Unit 3)
On June 1, 2004, Procedure 73ST-9X113, "Train A HPSI Injection and
Miscellaneous SI Valves - Inservice Test," Revision 18 (Unit 2)
b.
Findings
Introduction. A Green self-revealing finding was identified when a pressurizer level
transient above Technical Specification limits occurred in Mode 3 while performing
simultaneous evolutions that affected reactor coolant system (RCS) inventory.
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Description. On May 7, 2004, the licensee was performing two surveillances,
Procedure 73TI-9SG03, "ADV 30% Partial Stroke Test," Revision 5, and
Procedure 40ST-9CH04, "Boron Injection Flow Test," Revision 1. Simultaneous
performance of these evolutions caused a loss of letdown due to high regenerative
heat exchanger outlet temperature. This condition occurred due to single charging
pump operation per Procedure 40ST-9CH04, combined with increased letdown flow to
accommodate the RCS heatup following atmospheric dump valve (ADV) partial stroke
testing. Operators implemented Procedure 40AO-9ZZ05, "Loss of Letdown,"
Revision 12, and restored letdown within 2 minutes. Subsequently, a pressurizer level
transient occurred to a level greater than 56 percent, requiring entry into Technical Specification 3.4.9, Condition A, for 23 minutes.
Analysis. The inspectors determined that the finding is a performance deficiency
because operators elected to perform a combination of surveillance tests that caused a
loss of letdown and pressurizer level transient above Technical Specification limits.
This finding is associated with the barrier integrity cornerstone. The upper pressurizer
level limit is to ensure that enough steam space volume is available to accommodate
insurges from anticipated transients and ensures steam passage through the safety
relief valves if called upon. The finding is more than minor since it is associated with
the equipment performance attribute of the barrier integrity cornerstone and affects the
cornerstone objective of protecting the RCS barrier from radionuclide releases caused
by accidents or events. Using the Phase 1 worksheets in Manual Chapter 0609,
"Significance Determination Process," the finding is determined to have very low safety
significance because it only affects the barrier integrity cornerstone and was a
deficiency that did not result in the actual degradation of the RCS barrier. This issue
involves human performance crosscutting aspects associated with poor decision
making, questioning attitude, awareness of plant conditions, and communications
between personnel performing concurrent evolutions.
Enforcement. No violation of regulatory requirements occurred. The inspectors
determined that the finding did not represent a noncompliance because surveillance
procedures were followed and pressurizer level was restored within the time required
by Technical Specifications. This finding has been entered into the corrective action
program as CRDR 2707290. FIN 05000528/2004003-05, "Pressurizer Level Transient
Above Technical Specification Limits."
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
The inspectors reviewed the two temporary modifications and associated 10 CFR 50.59
screening evaluations listed below. The inspectors reviewed these against the system
design basis documentation and verified that the modification did not adversely affect
system operability or availability. Additionally, the inspectors verified that the
installation was consistent with applicable modification documents and conducted with
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adequate configuration control.
April 21, 2004, Temporary Modification 2690709, "Implement Upgraded
Temperature and Vibration Monitoring to Support Resolution of Shutdown
Cooling Suction Line Vibration," Revision 1 (Unit 1)
April 23, 2004, Temporary Modification 2691696, "Install Heat Tracing on the
Unit 1 Train A Shutdown Cooling Suction Line to Reduce Vibration," Revision 0
(Unit 1)
b.
Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation (71114.06)
a.
Inspection Scope
The inspectors observed portions of the announced emergency preparedness drill
conducted on June 30, 2004, to evaluate emergency response organization
performance by focusing on the risk-significant activities of classification, notification,
and protective action recommendations. The inspectors also assessed personnel
recognition of abnormal plant conditions, the transfer of emergency responsibilities
between facilities, communications, and the overall implementation of the emergency
plan. The drill was conducted using the Unit 1 simulator and all onsite response
facilities (emergency operations facility, technical support center, and the operations
support center) were activated. The scenario involved a loss of feedwater and failure
of auxiliary feedwater, leading to the failure of three fission product barriers and the
declaration of a general emergency.
b.
Findings
No findings of significance were identified.
Cornerstone: Occupational Radiation Safety
2.
RADIATION SAFETY
2OS1 Access Control to Radiologically Significant Areas (71121.01)
a.
Inspection Scope
The inspector assessed the licensees performance in implementing physical and
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administrative controls for airborne radioactivity areas, radiation areas, high radiation
areas, and worker adherence to these controls. The inspector used the requirements
in 10 CFR Part 20, the Technical Specifications, and the licensees procedures required
by Technical Specifications as criteria for determining compliance. During the
inspection, the inspector interviewed the radiation protection (RP) manager,
RP supervisors, and radiation workers. The inspector performed independent radiation
dose rate measurements and reviewed the following items:
Controls (surveys, posting, and barricades) of three radiation, high radiation, or
airborne radioactivity areas
Radiation exposure permit, procedure, and engineering controls and air sampler
locations
Conformity of electronic personal dosimeter alarm setpoints with survey
indications and plant policy; workers knowledge of required actions when their
electronic personnel dosimeter noticeably malfunctions or alarms
Barrier integrity and performance of engineering controls of two airborne
radioactivity areas
Physical and programmatic controls for highly activated or contaminated
materials (nonfuel) stored within spent fuel and other storage pools
Self-assessments, audits, licensee event reports (LERs), and special reports
related to the access control program since the last inspection (no LERs or
special reports identified)
Corrective action documents related to access controls
Radiation exposure permit briefings and worker instructions
Adequacy of radiological controls, such as required surveys, RP job coverage,
and contamination controls during job performance
Dosimetry placement in high radiation work areas with significant dose rate
gradient
Controls for special areas that have the potential to become very high radiation
areas during certain plant operations
Posting and locking of entrances to all accessible high dose rate - high radiation
areas and very high radiation areas
Radiation worker and RP technician performance with respect to RP work
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Enclosure
requirements
Either because the conditions did not exist or an event had not occurred, no
opportunities were available to review the following items:
Licensee actions in cases of repetitive deficiencies or significant individual
deficiencies
Changes in licensee procedural controls of high dose rate - high radiation areas
and very high radiation areas
Adequacy of the licensees internal dose assessment for any actual internal
exposure greater than 50 millirem committed effective dose equivalent
Performance indicator events and associated documentation packages reported
by the licensee in the occupational radiation safety cornerstone
The inspector completed 21 of the required 21 samples.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
a.
Inspection Scope
The inspector sampled licensee submittals for the performance indicators listed below
for the period from October 1, 2003, through March 31, 2004. To verify the accuracy of
the performance indicator data reported during that period, performance indicator
definitions and guidance contained in Nuclear Engineering Institute 99-02, "Regulatory
Assessment Indicator Guideline," Revision 2, were used to verify the basis in reporting
for each data element.
The inspector completed two of the required two samples.
Occupational Radiation Safety Cornerstone
Occupational Exposure Control Effectiveness Performance Indicators
Licensee records reviewed included corrective action documentation that identified
occurrences in high radiation areas with dose rates greater than 1,000 millirem per hour
at 30 centimeters (as defined in Technical Specification 5.7.2), very high radiation areas
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Enclosure
(as defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in
Nuclear Engineering Institute 99-02). Additional records reviewed included as low as is
reasonably achievable records and whole body counts of selected individual exposures.
The inspector interviewed licensee personnel that were accountable for collecting and
evaluating the performance indicator data. In addition, the inspector toured plant areas
to verify that high radiation and very high radiation areas were properly controlled.
Public Radiation Safety Cornerstone
Radiological Effluent Technical Specification/Offsite Dose Calculation Manual
Radiological Effluent Occurrences
Licensee records reviewed included corrective action documentation that identified
occurrences for liquid or gaseous effluent releases that exceeded performance indicator
thresholds and those reported to the NRC. The inspector interviewed licensee
personnel that were accountable for collecting and evaluating the performance indicator
data.
b.
Findings
No findings of significance were identified.
Mitigating Systems Cornerstone
a.
Inspection Scope
The inspectors reviewed unit logs, the maintenance rule unavailability tracking
database, and Technical Specification component condition records from January 2003
through March 2004 to verify the accuracy and completeness of data used to calculate
and report the following performance indicators:
Emergency ac Power System Unavailability (Units 1, 2, and 3)
Residual Heat Removal System Unavailability (Units 1, 2, and 3)
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
1.
Routine Review of Identification and Resolution of Problems
a.
Inspection Scope
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Enclosure
The inspectors reviewed a selection of CRDRs written during this period to determine if
the licensee was entering conditions adverse to quality into the corrective action
program at an appropriate threshold, the CRDRs were appropriately categorized and
dispositioned in accordance with the licensee's procedures, and in the case of
significant conditions adverse to quality, the licensee's root cause determination and
extent of condition evaluation were accurate and of sufficient depth to prevent
recurrence of the condition.
b.
Findings
No findings of significance were identified.
2.
Annual Sample Review
1.
SDC Heat Exchanger Temperature Loop Channel Calibration
a.
Inspection Scope
The inspectors selected CRDRs 280178 and 2686919 for detailed review. The CRDRs
were associated with Technical Specification required calibration of resistance
temperature detectors (RTDs) for SDC heat exchanger temperature Loops JSIA351X/Y
and JSIB352X/Y. The reports were reviewed to ensure that the full extent of the issues
were identified, appropriate evaluation was performed, and adequate corrective actions
were identified. The inspectors evaluated the reports against the requirements of
licensee Procedure 90DP-0IP10, "Condition Reporting," Revision 16, and
b.
Findings
Introduction. A Severity Level IV noncited violation finding was identified for the failure
to perform a complete SDC heat exchanger temperature loop channel calibration as
required by Technical Specification 3/4.3.3.5 (Improved Technical Specification
requirement is 3.3.11), "Remote Shutdown System."
Description. On June 11, 1998, the licensee initiated CRDR 280178 in response to
concerns regarding the implementation of surveillance requirements associated with
Technical Specification 3/4.3.3.5, which specified that the channel calibration shall
encompass the entire channel, including the sensor RTD. Specifically, the licensee had
not performed calibrations of the SDC heat exchanger temperature instrument. The
inspector determined that the licensees response to CRDR 280178 provided an
adequate justification for why the RTDs remained functional. Although the need to
calibrate the RTDs to comply with the Technical Specifications was mentioned, the
licensee failed to institute corrective actions to ensure compliance with the Technical
Specifications.
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Enclosure
Due to the licensees failure to properly evaluate CRDR 280178 and correct the
noncompliant condition, this same issue regarding Technical Specification compliance
was questioned on February 27, 2004, in CRDR 2686919 following an engineering
review. The inspectors determined that the licensee's response to CRDR 2686919 was
adequate in that immediate actions were taken to calibrate the RTDs while the licensee
determined whether a qualitative assessment had been performed as allowed by
Improved Technical Specifications. Improved Technical Specifications were
incorporated into the PVNGS license in August 1998, which revised the definition for
channel calibration. The revised definition states, in part, that calibration of instrument
channels with RTD sensors may consist of an in-place qualitative assessment of sensor
behavior. The licensee determined through review of Procedure 36ST-9SI07, "Remote
Shutdown Monitoring System Instrumentation Calibration for the SI System," Revision 5,
that the calibration of the SDC heat exchanger temperature elements included a check
of instrument output to verify that it reads as expected, which satisfies the Technical
Specification required in-place qualitative assessment.
The inspectors identified that the licensee failed to properly review this condition for
reportability during their evaluation of CRDR 2686919. Procedure 36ST-9SI07 provided
for an in-place qualitative assessment when revised on February 17, 2000. The
licensee based the reportability review on the current surveillance procedure revision
and incorrectly concluded that the qualitative assessment had been performed since the
implementation of improved Technical Specifications in August 1998. The instrument
output verification was incorporated into Procedure 36ST-9SI07 on February 17, 2000.
The inspectors determined that the Technical Specification required in-place qualitative
assessment for the SDC heat exchanger temperature instruments had been performed
during channel calibrations since February 2000. Nevertheless, with respect to the
SDC heat exchanger temperature instruments, the inspectors determined that between
August 1998 and January 25, 2001 (Unit 1), and on June 15 (Unit 2) and May 18, 2001
(Unit 3), the licensee did not perform either a qualitative assessment of sensor behavior
or a calibration of the sensor. The inspectors identified that the past noncompliant
condition was reportable per 10 CFR 50.73, "Licensee Event Report System."
Analysis. This finding is greater than minor because the licensee's failure to report the
condition impacted the NRC's ability to perform its regulatory function. This finding is
associated with the mitigating systems cornerstone. This finding was considered
applicable to traditional enforcement. Although the significance determination process
is not designed to assess significance of violations that potentially impact or impede the
regulatory process, the finding can be assessed using the significance determination
process. Using the Phase 1 worksheet in Manual Chapter 0609, "Significance
Determination Process," this finding is determined to be of very low safety significance
because it only affected the mitigating system cornerstone and the RTDs were found to
be within calibration.
Enforcement. Technical Specification 3.3.11, "Remote Shutdown System," requires that
the remote shutdown system instrumentation functions in Table 3.3.11-1 be operable.
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Enclosure
Item 4.a of Table 1 includes SDC heat exchanger temperature. Technical Specification
Surveillance Requirement 3.3.11.3 required that a channel calibration be performed
every 18 months. Technical Specification Surveillance Requirement 3.0.1 specified that
a failure to meet a surveillance requirement is a failure to meet the Technical
Specification. Contrary to this, the licensee failed to complete channel calibrations on
the SDC heat exchanger temperature elements. Specifically, the licensee did not test
the RTD or perform an in-place qualitative assessment. The inspectors also determined
that the licensees failure to implement effective corrective actions following the
identification of the issue documented in CRDR 280178 resulted in the violation of
Technical Specification 3.3.11 existing for an extended duration. This Severity Level IV
violation is being treated as a noncited violation, consistent with Section VI.A of the NRC
Enforcement Policy. This violation is in the licensees corrective action program as
CRDR 280178. NCV 05000528;05000529;05000530/2004003-06, "Failure to Perform a
Complete SDC Heat Exchanger Temperature Loop Channel Calibration."
2.
Failure to Perform Monthly Reviews to Ensure Excessive Hours Have Not Been
Assigned
a.
Inspection Scope
The inspectors selected CRDR 2646228 for detailed review. The CRDR was written to
describe a contract employee that exceeded the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in 7 days limit due to the
change from 10-12 hours shifts. The report was reviewed to ensure that the full extent
of the issue was identified, appropriate evaluation was performed, and adequate
corrective actions were identified. The inspectors evaluated the reports against the
requirements of licensee Procedure 90DP-0IP10, "Condition Reporting," Revision 16,
and 10 CFR Part 50, Appendix B. The inspectors also reviewed overtime limitation
exception reports generated during the latest refueling outages for Units 1 and 3.
b.
Findings
Introduction. The inspectors identified a noncited violation of Technical Specification 5.2.2.d for the failure of authorized individuals to review monthly overtime
to ensure that excessive hours have not been assigned.
Description. Technical Specification 5.2.2.d, states, in part, that controls shall be
included in procedures such that individual overtime shall be reviewed monthly by
authorized individuals or designees to ensure that excessive hours have not been
assigned. Procedure 01DP09EM01, step 4.5, states, in part, that the excess hours
report will be distributed to the applicable individuals that are one level higher than a
department leader of the applicable departments that this control applies to. This report
shall be reviewed monthly to ensure excessive hours have not been assigned and the
overtime limitations have not been violated. The inspectors identified, based on
interviews with the maintenance director, that he had not been performing these reviews
because the excess hours report had not been distributed to site maintenance
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Enclosure
management since an electronic reporting system was instituted in 2001.
Analysis. The finding is greater than minor because if left uncorrected it could become a
more significant safety concern, in that exceeding the NRC Generic Letter 82-02,
"Nuclear Power Plant Staff Working Hours," guidelines for overtime limits can be a
contributor to worker fatigue. Using the Phase 1 worksheet in Manual Chapter 0609,
"Significance Determination Process," this finding is determined to be of very low safety
significance because there were no known actual adverse plant or equipment conditions
that could be attributed to worker fatigue.
Enforcement. Technical Specification 5.2.2.d, states, in part, that controls shall be
included in procedures such that individual overtime shall be reviewed monthly by
authorized individuals or designees to ensure that excessive hours have not been
assigned. Contrary to the above, since 2001, the licensee has failed to perform the
monthly reviews to ensure excessive hours have not been assigned. Because the
finding is of very low safety significance and has been entered into the corrective action
program as CRDR 2727646, this violation is being treated as a noncited violation,
consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000528;
05000529;05000530/2004003-07, "Failure to Perform Monthly Reviews to Ensure
Excessive Hours Have Not Been Assigned."
3.
Semiannual Review
a.
Inspection Scope
During the inspection period, the inspectors reviewed the licensees corrective action
program, interviewed licensee personnel, and reviewed the maintenance rule program
documents to identify any significant adverse system or equipment trends. The
inspector performed a detailed review of the following problems that consisted of
multiple examples:
Fourteen examples where inappropriate lubricants were utilized on plant
equipment. The inspector verified that all examples were minor and did not have
an adverse impact on plant components.
Eight examples of motor-operated valve problems. In three cases, valve thrust
was found in excess of administrative design limits. In one case, valve thrust
was below design limits. In another example a valve failed to close on demand.
The final four problems involved high running loads, the inability to place an
actuator in the manual mode, an out of alignment motor pinion gear key, and a
broken worm shaft clutch broken dog. The inspectors verified that none of the
problems were the result of a programmatic breakdown and that all issues that
affected operability were properly resolved.
b.
Findings
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Enclosure
No findings of significance were identified.
4.
Section 2OS2 evaluated the effectiveness of the licensee's problem identification and
resolution processes regarding access controls to radiologically significant areas and
radiation worker practices. No findings of significance were identified.
4OA3 Event Followup (71153, 71111.14)
1.
Loss of Offsite Power, Subsequent Unit Reactor Trips, and Unit 2 Emergency Diesel
Generator Train A Failure to Maintain Voltage
The inspectors evaluated plant conditions, equipment performance, and licensee
actions related to the LOOP and reactor trips on Units 1, 2, and 3. Units 1
and 3 declared a notice of unusual event for this LOOP and Unit 2 declared an alert due
to emergency diesel generator Train A not maintaining voltage. An NRC Augmented
Inspection Team was chartered to review the complete LOOP. The results will be
documented in NRC Augmented Inspection Report 05000528; 05000529;
2.
Failure to Have Written Instructions for Testing a Remotely Controlled Submersible
Vehicle in the Unit 1 SFP
a.
Inspection Scope
The inspectors evaluated plant conditions, equipment performance, and licensee
actions related to a 3EF increase in the Unit 1 SFP due to operations isolating one of the
SFP cooling pumps to allow the retrieval of a remotely controlled submersible vehicle
which had entered into the common suction of the SFP cooling system.
b.
Findings
Introduction. A self-revealing noncited violation of 10 CFR Part 50, Appendix B,
Criterion V, "Instructions, Procedures, and Drawings," was identified for the failure of the
licensee to have written instructions for testing a remotely controlled submersible vehicle
in the Unit 1 SFP. The submersible unexpectedly entered into the common suction for
the pool cooling system. At the time of the event, the unit was in refueling operations
with 164 of the 241 fuel assemblies unloaded into the SFP.
Description. On April 12, 2004, during refueling operations in Unit 1, an RP technician
was testing, without written instructions and/or operations permission, a remotely
controlled submersible vehicle in the SFP in preparation for a scheduled inspection of
the reactor vessel the following day. While the technician discussed the process for
removing the vehicle from the SFP with the fuel building RP technician, the vehicle
began to sink and entered into the SFP cooling pump combined suction. The vehicle
was prevented from continuing through the pipe by the RP technician and spent fuel
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Enclosure
handling machine operator holding the tether until one of the two operating SFP cooling
pumps could be stopped by operations. With only one SFP cooling pump operating, the
vehicle was pulled from the pipe and retrieved from the pool. A temperature increase of
3oF (97E to 100°F) was noted by operations during the 16 minutes that the Train A SFP
cooling pump was secured. The SFP cooling pump was subsequently restarted and
core offload resumed. At the time of the event, the plant was in refueling operations
with 164 of the 241 fuel assemblies unloaded into the SFP. The licensee reported that
the time-to-boil in the SFP was 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Analysis. The finding is greater than minor because it affected the configuration control
and human performance attributes of the initiating events cornerstone objective. This
finding cannot be evaluated by the significance determination process because Manual
Chapter 0609, "Significance Determination Process," Appendix A, "Significance
Determination of Reactor Inspection Findings for At-Power Situations," and Appendix G,
"Shutdown Operations Significance Determination Process," do not apply to the SFP.
This finding is determined to be of very low safety significance by management review
because radiation shielding was provided by the SFP water level, the SFP cooling and
fuel building ventilation systems were available, and there were multiple sources of
makeup water.
Enforcement. 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and
Drawings," required, in part, that activities affecting quality be prescribed by documented
instructions, procedures, or drawings, of a type appropriate to the circumstances and
shall be accomplished in accordance with these instructions, procedures, or drawings.
Contrary to the above, the licensee failed to have written instructions to test a remotely
controlled submersible vehicle in the Unit 1 SFP. Because this violation is of very low
safety significance and has been entered into the corrective action program as
CRDR 2697384, this violation is being treated as a noncited violation, consistent with
Section VI.A of the NRC Enforcement Policy: NCV 05000528/2004003-08, "Failure to
Have Instructions for Testing a Submersible in the Unit 1 SFP."
4OA4 Crosscutting Aspects of Findings
1.
Cross-References to Human Performance Findings Documented Elsewhere
Section 1R19 describes a finding where inattention to detail resulted in the inadequate
removal of isopropyl alcohol from an MFW pump Train A turbine casing and caused a
flash fire.
Section 1R20 describes a finding for poor decision making and questioning attitude that
resulted in failing to correct a degraded refueling machine equipment condition.
Section 1R22 describes a finding where poor operator decision making, questioning
attitude, awareness of plant conditions, and communications between operators
resulted in a loss of letdown and pressurizer level transient.
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Enclosure
Section 4OA3 describes a finding associated with poor decision making and lack of
questioning attitude from an RP technician which lead to a remotely controlled
submersible being ingested into the common suction for the Unit 1 SFP cooling system
during refueling operations.
Section 4OA5 of this report and Section 4OA2 of NRC Inspection Report 05000528;
05000529; 05000530/2003004 described a finding that involved mispositioned valves,
improper procedure implementation, and a lack of operator awareness of plant
conditions that resulted in SFP inventory loss events.
4OA5 Other Activities
1.
(Closed) Unresolved Item (URI) 05000530/2003004-03: Nuclear Assurance
Department's Concurrence for Significant CRDR 2599869
Introduction. A Green noncited violation was identified for the failure to identify the root
cause of SFP inventory loss events and implement corrective actions to preclude
recurrence.
Description. NRC Inspection Report 05000528;05000529;05000530/2003004
documents inspector observations associated with the review of two significant
investigations, CRDRs 2599869 and 2451670, performed by the licensee to correct a
negative trend in SFP inventory control. Deficiencies involving inadequate root cause
identification and untimely corrective action implementation were identified by the
inspector during the review. The Nuclear Assurance Department reviewed
CRDR 2599869 and concluded that the cause evaluation was inadequate and rejected
the significant investigation. As a result of the untimely significant investigations and
corrective action implementation, two additional SFP inventory loss events occurred in
March and April 2004. Similar to the events identified in CRDR 2599869, causes of the
2004 events included improper positioning of fuel pool cleanup suction isolation
Valve XPPCNV004 and inadequate level monitoring, both locally and in the control
room. Significant Investigation Report 2599869 was approved April 22, 2004, and
adequately identified the root causes of past SFP inventory events and corrective
actions to preclude repetition. The root causes identified included: (1) the combination
of the inaccuracy of the position indicator for gear-driven Valve Operators 2PPCNV004
and 3PPCNV004, and the overconfidence and complacency of the auxiliary operators,
lead the auxiliary operator to believe that the valve was closed on initial positioning; the
resultant valve not in the full closed position caused the change in SFP level; and (2) the
expectation that local monitoring of the SFP level could be maintained a top priority,
given the embedded distraction inherent in performing tasks in the pool cooling system,
was not realistic or consistently achievable. Remote detection and warning of an SFP
level decrease was not provided for prompt event mitigation.
Analysis. The finding is greater than minor because it affected the configuration control
and human performance attributes of the initiating events cornerstone objective. This
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finding cannot be evaluated by the significance determination process because Manual
Chapter 0609, "Significance Determination Process," Appendix A, "Significance
Determination of Reactor Inspection Findings for At-Power Situations," and Appendix G,
"Shutdown Operations Significance Determination Process," do not apply to the SFP.
This finding is determined to be of very low safety significance by management review
because radiation shielding was provided by the SFP water level, the SFP cooling and
fuel building ventilation systems were available, and there were multiple sources of
makeup water.
Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," states, in
part, that measures shall be established to assure that conditions adverse to quality are
promptly identified and corrected. In the case of significant conditions adverse to
quality, the measures shall assure that the cause of the condition is determined and
corrective actions taken to preclude repetition. Contrary to the above, the licensee
failed to identify the root cause of SFP inventory loss events and did not implement
corrective actions to preclude repetition in a timely manner. Because this violation is of
very low safety significance and all SFP draindown events have been entered in the
corrective action program, this violation is being treated as a noncited violation,
consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000528;
05000529;05000530/2004003-09, "Failure to Prevent Loss of SFP Inventory Events
Through Timely Corrective Actions."
2.
(Closed) URI 05000529/2003009-02: Failure to Follow Heavy Load Movement
Procedure
Introduction. NRC Inspection Report 05000529/2003009 described a noncited violation
for failing to follow Procedure 31MT-9ZC07, "Miscellaneous Containment Building Heavy
Loads," Revision 8, preceding a heavy load drop inside containment. The finding was
identified as a URI pending the completion of a significance determination. The result of
the determination was that the finding was of very low safety significance.
Description. During the inspection documented in NRC Inspection Report 05000529/2003009, the inspectors identified a noncited violation having potential safety
significance greater than very low significance, involving the 12-24 inch drop of a
7000-pound steam generator snubber lever plate during the steam generator
replacement outage. The inspectors had determined that the licensee failed to follow
it's control of heavy loads procedure which led to the nonuse of numerous barriers which
should have been in place to prevent the load drop. The significance of this finding had
not been determined at the conclusion of the inspection.
Analysis. The finding was greater than minor because it affects the equipment
performance and human performance attributes of the initiating event cornerstone
objective to limit the likelihood of events that challenge safety functions during shutdown
conditions. During the current inspection period, the inspectors and senior reactor
analyst determined that the issue was of very low safety significance (Green). The
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following assumptions were used during the Manual Chapter 0609, "Significance
Determination Process," Appendix G, "Shutdown Operations Significance Determination
Process," evaluation:
The closest RCS piping in the horizontal direction from the lever plate was the
RCS Loop 1A cold leg. The licensee performed a calculation which concluded
that, if the lever dropped on the cold leg, it would have remained intact.
The pressurizer surge line was approximately 6.5 feet horizontally and 30 feet
vertically from the lever plate and was not a realistic target for the lever plate.
However, even if the pressurizer surge line had been severed, residual heat
removal operation would not have been impacted because the surge line exited
from the top of the RCS hot leg.
There were no other targets of RCS piping or interconnected systems in the
postulated drop zone of the lever plate that could have impacted residual heat
removal operation or that would have impaired equipment that could mitigate a
loss of RCS inventory (such as high pressure injection or containment spray).
Containment closure could have been achieved, if necessary, in less than
25 minutes of a loss of RCS inventory, and containment closure would not have
been impacted by a postulated break in the pressurizer surge line.
Based on the above, the senior reactor analyst concluded that this finding did not
significantly increase the likelihood of losing the RHR function and did not significantly
increase the likelihood that systems that could mitigate a loss of RHR function would be
degraded. Therefore, this finding was of very low safety significance.
Enforcement: NRC Inspection Report 05000529/2003009 described a noncited
violation for failing to follow Procedure 31MT-9ZC07, "Miscellaneous Containment
Building Heavy Loads," Revision 8, preceding a heavy load drop inside containment.
Because the finding is of very low safety significance and has been entered into the
corrective action program as CRDR 2639721, this violation is being treated as a
noncited violation, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000529/2004003-10, "Failure to Follow Heavy Load Movement Procedure."
3.
(Closed) URI 05000529/2003005-03: Missing Bolts on Support for Main Steam Line
Whip Restraint
Introduction. A Green self-revealing noncited violation of 10 CFR Part 50, Appendix B,
Criterion V, was identified for the failure to secure a main steam line pipe whip restraint
inside the Unit 2 containment in accordance with design drawings.
Description. As described in NRC Inspection Report 050000528; 05000529;
05000530/2003005, the inspectors identified an apparent violation of NRC requirements
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(with significance to be determined) for a finding involving the discovery that Unit 2
Steam Generator 2 Pipe Whip Restraint Hanger 02-SG-042-H-890 was missing
fasteners required by Drawing 13-C-ZCS-541. The inspectors determined that this
apparent violation was a URI pending determination of its risk significance. A concern
existed that with the pipe whip restraint fasteners absent, the containment liner or the
containment spray headers could be damaged by pipe whip following a main steam line
break accident. The licensee initiated an analysis to evaluate the consequences of a
postulated pipe whip in this condition.
Analysis. The finding is greater than minor since it is associated with the equipment
performance attribute of the barrier integrity cornerstone and affects the cornerstone
objective of protecting the containment barrier from radionuclide releases caused by
accidents or events. During the current inspection period, the inspectors and a senior
reactor analyst determined that the issue was of very low safety significance and did not
require a Phase 2 analysis using Manual Chapter 0609, "Significance Determination
Process," Appendix H, "Containment Integrity SDP." The factors causing the issue to
be of very low safety significance were:
The finding did not represent an actual open pathway in the physical integrity of
reactor containment.
The finding did not represent an actual reduction of the atmospheric pressure
control function of the reactor containment.
The licensees completed analysis, 0001-04-KB-APS-13-CC-ZC-0165A, "Main
Steam Line (Unit 2) SG#2 Pipe Whip Restraints," Revision 0, concluded that the
support structure and the pipe whip restraint would likely restrain the pipe lines
upon the occurrence of a steam line break without the required fasteners.
Neither the containment liner nor the containment spray headers would be
impacted.
Enforcement. Because this failure to comply with 10 CFR Part 50, Appendix B,
Criterion V, is of very low safety significance and has been entered into the corrective
action program as CRDR 2643347, this violation is being treated as an noncited
violation, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000529/2004003-11, "Missing Bolts on Support for Main Steam Line Whip
Restraint."
4.
(Closed) LER 05000528; 05000529;05000530/2003003-00, Technical Specification
Violation for Failure to Meet SDC Trains OPERABLE Action Statements
A licensee-identified noncited violation of Technical Specification 3.9.4, "Shutdown
Cooling (SDC) and Coolant Circulation - High Water Level," was identified for a
temporary, nonseismically qualified containment pedestal crane lifting heavy loads over
the operating train of SDC in all three units during SDC operations, thereby rendering
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the operating train of SDC inoperable. On September 19, 2003, during preparations for
the Unit 2 steam generator replacement project, the licensee identified that the
temporary containment pedestal crane was not seismically qualified. The containment
pedestal crane was installed in the containment building at the beginning of each
refueling outage after the unit entered cold shutdown. It was removed prior to exiting
cold shutdown. The containment pedestal crane had been used for rigging
maintenance equipment needed during refueling outages for all three units since
May 1995. The licensee determined that the crane was not analyzed for operation with
a loaded hook during a seismic event. If a heavy load lift was in progress using the
containment pedestal crane and a seismic event occurred while the load was above
equipment needed for SDC when fuel was in the reactor vessel, and the load was
dropped, a potential existed for SDC capability or RCS inventory to be lost. This
constituted a violation of Technical Specifications 3.4.7, 3.9.4, and 3.9.5, which required
operability of SDC systems during shutdown conditions. Upon discovery of this finding,
the licensee restricted use of the containment pedestal crane. The maximum load lifted
with the containment pedestal crane was approximately 3500 pounds.
The finding is greater than minor because it affects the mitigating systems cornerstone
objective and because the finding could be reasonably viewed as a precursor to a
significant event. In determining the significance of this finding, the inspectors assumed
the possibility of a seismic event resulting in the loss of a single train of SDC. All
mitigating systems remained available to the operators and the finding did not increase
the likelihood of a fire or flooding. The inspectors, in coordination with the senior reactor
analyst, determined that the finding was of very low safety significance based on the
number of outages the containment pedestal crane was used, an estimate of the
number of lifts and load paths over reactor coolant system targets, a qualitative review
of the fragility of the containment pedestal crane, and the low seismicity of the area.
This licensee-identified finding involved a violation of Technical Specification 3.9.4,
"Shutdown Cooling (SDC) and Coolant Circulation - High Water Level." The
enforcement aspects of the violation are discussed in Section 4OA7. This LER is
closed.
5.
Reactor Pressure Vessel (RPV) Head and Vessel Head Penetration Nozzles Temporary
Instruction (TI) 2515/150
In October 2002, the inspectors completed the review of the licensees Unit 1 RPV head
bare metal visual examination using TI 2515/145. This review was documented in NRC
Inspection Report 0500528/2002006. Per TI 2515/150, Section 07, "Expiration," the
October 2002 completion of TI 2515/145 was credited as one of the two required
TI 2515/150 reviews. The second occurrence of TI 2515/150 for Unit 1 is documented
below. Therefore, TI 2515/145 is closed for Unit 1.
The first occurrence of TI 2515/150 was documented for Unit 2 in NRC Inspection
Report 0500529/2003-005. The first occurrence of TI 2515/150 was documented for
Unit 3 in NRC Inspection Report 0500530/2003003.
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Susceptibility Ranking Calculation
a.
Inspection Scope
On April 5-23, 2004, the inspectors performed NRC Inspection Manual TI 2515/150 for
Unit 1 during Cycle 11 Refueling Outage 1R11. The inspectors reviewed the licensee's
inspection plan in response to NRC Order EA-03-009, which established interim
inspection requirements for RPV heads.
The inspectors reviewed the susceptibility ranking calculation to verify that appropriate
plant-specific information was used as input. The calculation determines the effective
degradation years, which is the effective full power years, normalized to 600EF. Two
periods were used to determine RPV head temperature and corresponded to the
periods before and after implementation of T-hot reduction, which reduced T-hot from
621EF to approximately 612EF to minimize steam generator tube degradation. The
head temperature for each period was based on using a combination of an evaluation to
calculate fluid temperature in the upper head based on mixing of bypass flow through
different paths and heated junction thermocouple data. The more conservative of the
two temperatures was used for each period.
The inspectors noted that Unit 1 was projected to be in the highly susceptible category
at the end of Cycle 11. Required inspections for the refueling outage were bare metal
visual examination of 100 percent of the RPV head surface (Order,Section IV.C.(1)(a)),
ultrasonic testing of each RPV head penetration nozzle from 2 inches above the
J-groove weld to the bottom of the nozzle (Order,Section IV.C.(1)(b)(i)), or eddy current
testing of the wetted surface of each J-groove weld and RPV head penetration nozzle
base material to at least 2 inches above the J-groove weld (Order Section IV.C.(1)(b)(ii)).
Because of hardships the licensee had with the ability to perform required inspections,
two relaxation requests submitted to the NRC were approved based on the
demonstration of good cause for the proposed relaxations. The first proposed
alternative examination was to perform a bare metal visual examination of the one
RPV head vent line nozzle in accordance with Order Section IV.C.(1)(a), since internal
volumetric or surface examination would be difficult and would require the removal of
the welded orifice and testing of the remaining control element drive mechanism nozzles
per Order Section IV.C.(1)(b). The second proposed alternative examination was to
perform ultrasonic testing of each nozzle from 2 inches above the J-groove weld to
approximately 0.4" above the top of the nozzles chamfer face control element drive
mechanism since ultrasonic scans in the area below 0.4" to the bottom of the nozzle do
not yield useful data because of the geometry of the nozzle and funnel.
b.
Findings
No findings of significance were identified.
Volumetric and Surface Examinations
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Enclosure
a.
Inspection Scope
The inspectors verified that the licensee's volumetric inspection plan and critical
performance objectives were incorporated into site procedures. They also interviewed
plant inspection personnel and contractors performing the inspections to determine their
understanding of inspection standards and acceptance criteria required during data
gathering and analysis. The inspectors reviewed the Westinghouse field service
procedures, which governed the instrument calibration, data gathering, and data
analysis requirements for ultrasonic and eddy current testing. Nuclear Reactor
Regulation personnel, in conjunction with the inspectors, reviewed the qualification of
these methods and their ability to determine flaws in J-groove welds and base metals
associated with primary water stress corrosion cracking. The inspectors reviewed
licensee and contractor qualifications and certification records which were obtained
through a combination of written and practical examinations. The inspectors conducted
interviews with plant engineers and Westinghouse contractors to determine their
training, background, basis used for certifications, and expertise in conducting and
analyzing these examinations. The inspectors also observed equipment operation
during data gathering for 10 nozzles and data analysis for 100 percent of the head
penetration nozzles. The inspectors compared 4 nozzles of special interest to data
collected from the previous outage and determined that there were no changes in the
anomalies.
b.
Findings
No findings of significance were identified.
Bare Metal Visual Examinations
a.
Inspection Scope
The inspectors observed the video acquired during visual inspection of the RPV head
vent line nozzle and noted that the camera and remote monitoring equipment used
during the examination process provided adequate visual clarity. The inspectors
reviewed certification records and discussed the qualifications and experience of the
examiners. The inspectors verified that a clear 360E observation of the nozzles was
completed and that no evidence of cracking or boric acid crystals were present. There
were no boron deposits, debris, or insulating material which masked the ability to identify
the existence of boric acid. There were no structural interferences which impeded the
ability to complete the bare metal visual inspections. The inspectors determined that the
licensee had procedures in place to identify leakage from pressure retaining
components located above the RPV head.
b.
Findings
No findings of significance were identified.
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6.
RPV Lower Head Penetration Nozzles (TI 2515/152)
a.
Inspection Scope
On April 8-23, 2004, the inspectors reviewed the licensees response to
NRC Bulletin 2003-02, "Leakage from Reactor Pressure Vessel Lower Head
Penetrations and Reactor Coolant Pressure Boundary Integrity." The response
described the licensees commitment to perform a bare metal visual inspection of all
62 nozzle penetrations in the lower reactor head of all three units. The inspectors
reviewed the licensee's procedures for the inspection of the Unit 1 lower head
penetrations. The inspector also reviewed the qualification and certifications for the
personnel performing the inspections.
The inspectors reviewed a video tape of all nozzle inspections. The inspections covered
a full 360E of all 62 nozzle penetrations. The camera and remote monitoring equipment
used during the examination process provided adequate visual clarity. The inspectors
verified that a clear 360E observation of the nozzles was completed and that no
evidence of cracking or boric acid crystals were present. The inspectors determined that
there was no debris, insulation, or boric acid deposit on the RPV lower head. TI
2515/152 has been completed on Units 1 and 2.
b.
Findings
No findings of significance were identified.
7.
Reactor Containment Sump Blockage - NRC Bulletin 2003-01, "Potential Impact of
Debris Blockage on Emergency Sump Recirculation at Pressurized-Water Reactors"
Generic Safety Issue 191 was established to determine whether the transport and
accumulation of debris in pressurized water reactor containments following a loss of
coolant accident (or other high energy line break, if recirculation is credited) will impede
the long-term operation of the ECCS or containment spray system. In the event of a
loss of coolant accident, materials in the vicinity of the break, such as thermal insulation,
coatings, and concrete, would be damaged and dislodged.
The inspector reviewed the licensees response and supporting basis which showed that
the ECCS and containment spray system recirculation functions have been analyzed
with respect to the potentially adverse postaccident debris blockage effects as specified
in the bulletin. The inspector assessed that this determination is based on a
mechanistic (plant-specific) evaluation of debris generation, transport, and accumulation
rather than arbitrary (generic) assumptions.
The inspector also confirmed that the licensee performed walkdowns of their
containments to quantify potential debris sources and check for gaps in the sumps
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screened flowpath and for major obstructions in containment upstream of the sumps.
The inspector also assessed any sump-related modifications.
TI 2515/153 has been completed for Units 1 and 2.
Interim Compensatory Measures
a.
Inspection Scope
Possible interim compensatory measures may include, but are not limited to, the
following:
Operator training on indications of and responses to sump clogging
Procedural modifications, if appropriate, that would delay the switchover to
containment sump recirculation (e.g., shutting down redundant pumps that are
not necessary to provide required flows to cool the containment and reactor core
and operating the containment spray system intermittently)
Ensuring that alternative water sources are available to refill the refueling water
storage tank or to otherwise provide inventory to inject into the reactor core and
spray into the containment atmosphere
More aggressive containment cleaning and increased foreign material controls
Ensuring containment drainage paths are unblocked
Ensuring sump screens are free of adverse gaps and breaches
b.
Findings
The licensee informed operators of the actions for potential blockage but decided to
defer any procedure changes until the Combustion Engineering Owners Group
evaluates the bulletin.
No findings of significance were identified.
Debris Sources in Containment
a.
Inspection Scope
The inspectors reviewed the potential debris sources in containment described in
Updated Final Safety Analysis Report, Section 6.2.2, and in Calculation 13-MC-SI-309,
"Containment Sump Blockage," Revision 3. The inspectors also toured the Unit 1
containment to determine that there were no additional debris sources.
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Enclosure
b.
Findings
The inspectors toured containment and identified exposed Fiberfrax due to improper
insulation installation in five bio-shield wall penetrations. This condition was evaluated
by the licensee in CRDR 2710401. The engineering evaluation determined that the
quantity of Fiberfrax identified would not impact ECCS sump operability since the design
basis accident scenario bounds all fiber and pads located in the five penetrations for
No findings of significance were identified.
Containment Sump Inspection and Design
a.
Inspection Scope
The inspectors reviewed the design of the containment sumps which are designed to be
reservoirs of water to the ECCS following a loss of coolant accident. The inspectors
verified that the sump configuration satisfied design requirements in that particles
greater than 3/16-inch diameter were precluded from entering the ECCS sump.
b.
Findings
No findings of significance were identified.
8.
Offsite Power System Operational Readiness TI 2515/156
a.
Inspection Scope
The inspectors collected data from licensee maintenance records, event reports, and
corrective action documents and procedures and through interviews of station
engineering, maintenance, and operations staff as required by TI 2515/156. The data
was gathered to assess the operational readiness of the offsite power systems in
accordance with NRC requirements such as Appendix A to 10 CFR Part 50, "General
Design Criterion (GDC) 17"; Criterion XVI of Appendix B to10 CFR Part 50; Plant
Technical Specifications for offsite power systems; 10 CFR 50.63; 10 CFR 50.65(a)(4);
and licensee procedures. Documents reviewed for this TI are listed in the attachment.
b.
Findings
No findings of significance were identified. Based on the inspection, no immediate
operability issues were identified. In accordance with TI 2515/156 reporting
requirements, the inspectors provided the required data to the headquarters staff for
further analysis. This completes TI 2515/156 for the Palo Verde Nuclear Generating
Station.
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Enclosure
4OA6 Meetings, Including Exit
On April 22, 2004, the senior reactor inspector presented the inservice inspection results
to Mr. G. Overbeck, Senior Vice President, Nuclear, and other members of his staff.
The licensee acknowledged the findings.
On April 23, 2004, the health physicist inspector presented the radiation safety
inspection results to Mr. G. Overbeck, Senior Vice President, Nuclear and other
members of his staff. The licensee acknowledged the findings.
On May 21, 2004, the resident inspectors presented partial integrated inspection results
to Mr. G. Overbeck, Senior Vice President, Nuclear, and other members of his staff.
The licensee acknowledged the findings.
On June 1, 2004, a subsequent conference call was held with Mr. Tom Weber, Section
Leader, and licensing personnel to discuss the final conclusion and characterization of
the findings for the inservice inspection. The licensee acknowledged the findings.
On July 8, 2004, the resident inspectors presented the integrated inspection results to
Mr. G. Overbeck, Senior Vice President, Nuclear, and other members of his staff. The
licensee acknowledged the findings.
The inspectors noted that, while proprietary information was reviewed, none would be
included in this report.
40A7
Licensee-identified Violations
The following violations of very low significance (Green) were identified by the licensee
and are violations of NRC requirements which meet the criteria of Section VI of the
NRC Enforcement Policy, NUREG-600, for being dispositioned as an NCV.
Technical Specification 5.4.1.a requires written procedures be established,
implemented, and maintained covering the activities specified in Regulatory
Guide 1.33, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A,
Item 3a, requires procedures containing instructions for operation of the RCS.
Contrary to the above, on May 5, 2004, the licensee did not follow
Procedure 40ST-RC01, "RCS and Pressurizer Heatup and Cooldown,"
Revision 13, step 8.1.2, while preparing for Mode 4 entry. Step 8.1.2 provided
instructions for the appropriate instruments to be used during RCS heatup and
cooldown. Operators were inappropriately controlling RCS temperature with
SDC heat exchanger Train A outlet temperature on the emergency response
facility data acquisition and data system to maintain RCS temperature in Mode 5,
just below Mode 4 conditions. Due to an unknown emergency response facility
data acquisition and data system deficiency, the indication used by operators to
control temperature indicated approximately 17EF lower than the procedurally
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Enclosure
approved temperature indications. Operators identified the condition when they
unexpectedly noted, on trend Recorder SIATT351Y, that RCS temperature was
at the upper limit for Mode 5. An RCS cooldown was initiated to establish more
temperature margin from Mode 5 conditions. This was identified in the licensees
corrective action program as CRDR 2706235. This finding is of very low safety
significance because the condition was identified prior to making an inadvertent
mode change.
Technical Specification 5.4.1.a requires that written procedures be established,
implemented, and maintained covering the applicable procedures referenced in
Regulatory Guide 1.33, Revision 2, Appendix A. Regulatory Guide 1.33,
Appendix A, Section 7, requires procedures for access control to radiation areas
including a radiation work permit system. On April 8, 2004, a contract worker
entered the Unit 1 containment building on Radiation Exposure Permit 1-305B,
Task 1. The radiation exposure permit required the worker to review current
radiological survey data and receive an area specific RP prejob briefing prior to
entry; however, the worker failed to comply with these requirements prior to
entering the work area. This event was described in the licensees corrective
action program as CRDR 2696454. The finding was determined to be of very
low safety significance because the violation did not involve as low as
reasonably achievable planning or work controls, no individual received an
overexposure or a substantial potential for overexposure, and the ability to
assess dose was not compromised.
Technical Specification 3.9.4, "Shutdown Cooling (SDC) and Coolant
Circulation - High Water Level," requires one SDC loop to be operable and in
operation. Contrary to the above, during refueling outages in all three units
dating back to May 1995, the licensee used a temporary, nonseismically qualified
containment pedestal crane to lift heavy loads over the operating train of SDC
which rendered the operating train of SDC inoperable. This event was described
in the licensees corrective action program as CRDR 2636484. In determining
the significance of this finding, the inspectors assumed the possibility of a
seismic event resulting in the loss of a single train of SDC. All mitigating systems
remained available to the operators and the finding did not increase the
likelihood of a fire or flooding. The inspectors, in coordination with the senior
reactor analyst, determined the finding was of very low safety significance based
on the number of outages the containment pedestal crane was used, an
estimate of the number of lifts and load paths over RCS targets, a qualitative
review of the fragility of the containment pedestal crane, and the low seismicity of
the area.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Attachment
A-1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
P. Brandjes, Department Leader, Maintenance
D. Carnes, Director, Nuclear Assurance and Regulatory Affairs
W. Chapin, Department Leader, Nuclear Fuels Management
C. Churchman, Director, Steam Generator Replacement Project
M. Fladager, Department Leader, Radiation Protection
J. Gaffney, Director, Radiation Protection
T. Gray, Department Leader, Radiation Protection
M. Grigsby, Unit Department Leader, Operations
D. Hautala, Senior Engineer, Regulatory Affairs
R. Henry, Site Representative, El Paso Gas and Electric
D. Kanitz, Senior Engineer, Regulatory Affairs
P. Kirker, Unit Department Leader, Operations
D. Mauldin, Vice President, Engineering and Support
M. McGhee, Unit Department Leader, Operations
M. Milton, Section Leader, Inservice Inspection
G. Overbeck, Senior Vice President, Nuclear Operations
S. Peace, Consultant, Owners Services
R. Pontes, Section Leader, Steam Generator Replacement Project
M. Powell, Department Leader, Maintenance Engineering
J. Taylor, Department Leader, Operations
C. Seaman, Director, Nuclear Fuels Management
D. Smith, Plant Manager, Nuclear Production
E. Sterling, Section Leader, Nuclear Assurance
K. Sweeney, Section Leader, Steam Generator Project Group
T. Weber, Section Leader, Regulatory Affairs
M. Winsor, Director, Engineering
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
SFP Water Siphon due to Check Valve Failure
(Section 1R14)
05000528;05000529;05000530/2004003-02
Containment Purge Penetration Nonconformance
(Section 1R15)
Attachment
A-2
Fire that Occurred During Welding Activities on the MFW
Pump Turbine Train A (Section 1R19)05000528/2004003-04
Core Alterations with Degraded Refueling Machine
(Section 1R20)05000528/2004003-05
Pressurizer Level Transient Above Technical
Specification Limits (Section 1R22)
05000528;05000529;05000530/2004003-06
Failure to Perform a Complete SDC Heat Exchanger
Temperature Loop Channel Calibration (Section 4OA2)
05000528;05000529;05000530/2004003-07
Failure to Perform Monthly reviews to Ensure Excess
Hours Have Not Been Assigned (Section 4OA2)05000528/2004003-08
Failure to Have Instructions for Testing a Submersible in
the Unit 1 SFP (Section 4OA3)
05000528;05000529;05000530/2004003-09
Failure to Prevent Loss of SFP Inventory Events Through
Timely Corrective Actions (Section 4OA5)05000529/2004003-10
Failure to Follow Heavy Load Movement Procedure
(Section 4OA5)05000529/2004003-11
Missing Bolts on Support for Main Steam Line Whip
Restraint (Section 4OA5)
Closed
NAD's Concurrence for Significant CRDR 2599869
(Section 4OA5)05000529/2003009-02
Failure to Follow Heavy Load Movement Procedure
(Section 4OA5)05000529/2003005-03
Missing Bolts on Support for Main Steam Line Whip
Restraint (Section 4OA5)05000528/2003003-00;
LER
Technical Specification Violation for Failure to Meet SDC
Trains OPERABLE Action Statements (Section 4OA5)
LIST OF DOCUMENTS REVIEWED
In addition to the documents called out in the inspection report, the following documents were
selected and reviewed by the inspectors to accomplish the objectives and scope of the
inspection and to support any findings:
Attachment
A-3
Section 1R04: Equipment Alignment
Procedure
40OP-9DG02, "Emergency Diesel Generator B," Revision 31
Plant Drawings
01-M-SIP-001, "P&I Diagram, Safety Injection and Shutdown Cooling System," Revision 25
01-M-SIP-002, "P&I Diagram, Safety Injection and Shutdown Cooling System," Revision 24
01-M-DGP-001, "P&I Diagram - Diesel Generator Fuel Oil and Transfer System," Revision 11
01-M-DGP-001, "P&I Diagram - Diesel Generator System, Sheet 1," Revision 44
01-M-DGP-001, "P&I Diagram - Lube Oil, Diesel Generator System, Sheet 3," Revision 44
01-M-DGP-001, "P&I Diagram - Jacket Water, Diesel Generator System, Sheet 4," Revision 44
01-M-DGP-001, "P&I Diagram - Fuel Oil, Diesel Generator System, Sheet 7," Revision 44
01-M-DGP-001, "P&I Diagram - Diesel Generator System, Sheet 9," Revision 44
Section 1R07: Heat Sink Performance
CRDR
2653867
Procedures
73DP-9ZZ10, "Guidelines for Heat Exchanger Thermal Performance Analysis," Revision 4
70TI-9EW01, "Thermal Performance Testing of Essential Cooling Water Heat Exchangers,"
Revision 4
Nondestructive Examination Activities Reviewed
System/Line No/Compoent ID
Weld Number
Exam Method
SG/SG-E-70-DLBB-12
51-30
UT/MT
SG/SG-E-70-DLBB-12
51-31
UT/MT
SG/SG-E-70-DLBB-12
51-32
UT/MT
SG/SG-E-70-DLBB-12
51-33
UT/MT
SG-E-207-DLLBB-28
48-2
SG-E-207-DLLBB-28
48-3
Attachment
A-4
SG-E-207-DLLBB-28
48-4
Support
VT-3
SI-A-307-GCBC-24
84-26
UT/PT
IJSIBFE0348
250635-1
Examinations from Previous Outage with Recordable Indications
Weld 74-37 (Determined to be geometry) (SI system)
Weld 59-16 (Determined to be geometry) (SG Downcomer)
Weld 84-26 (Determined to be geometry) (SI system)
Weld 74-37 (Determined to be geometry) (SI system)
Weld 2581743-2 (Feedwater) RF11
Weld 2581743-3 (Feedwater) RF11
Weld 2581743-6 (Feedwater) RF11
ASME Code Repair and Replacement
WO 2590635; Flange to Pipe; Containment spray discharge line; Weld 250635-1
Miscellaneous Documents
Unit 1 Summary Reports for RF8, 9, and 10
Relief Requests, submitted dated April 10, 2000
Deviations (Technical Justification) from NEI 97-06 (99-SGPG-TJ-002, -003, -004, -005, -007;
and 2001-SGPG-TJ-011)
Relief Request 26 (Supplement 10 to Appendix VIII)
Procedures
73TI-9ZZ07, "Liquid Penetrant Examination," Revision 9
73TI-9ZZ10, "Ultrasonic Testing Examination Of Welds In Ferritic Components," Revision 10
73TI-9ZZ17, "Visual Examination Of Welds, Bolting, And Components," Revision 8
73TI-9ZZ79, "ASME Section XI Appendix VIII Ultrasonic Testing Of Ferritic Piping," Revision 3
73TI-9ZZ80, "ASME Section XI Appendix VIII Ultrasonic Testing Of Austenitic Piping,"
Revision 3
73TI-9RC01, "Steam Generator Eddy Current Examinations," Revision 23
Attachment
A-5
81CP-9RC28, "Checkout and Operation of the Steam Generator Tube In Situ Pressure Test
System 2"
81DP-9RC01, "PVNGS Steam Generator Degradation Management Program," Revision 3
81CP-9RC29, "In-Situ Pressure Test Using the Computerized Data Acquisition System
(Westinghouse PVNGS-010, Revision 5)," Revision 4
81CP-9RC19, "Welded Tube/Tubesheet Plug Removal utilizing the Phase III Drill Assembly,"
Revision 3
CRDRs
658882, 2682277, 2670186, 2668058, 2667731, 2661027, and 2699053
Section 1R12: Maintenance Implementation
CRDRs
2682409, 2640655, 2547814, and 2691427
2584849, 2560952, 2551842, and 2584695
Miscellaneous
Low Pressure Alarm for Main Steam Isolation Valve MSIV-180 Train A Accumulator due to
Faulty Pressure Transmitter (Unit 1, CRDR-2547756)
Steam Generator - Main Steam Isolation Valve Reliability Performance Criteria
Nuclear Administrative and Technical Manual 40OP-9SG01, "Main Steam," Revision 37
Nuclear Administrative and Technical Manual 90DP-0IP10, "Condition Reporting," Revision 18
Nuclear Administrative and Technical Manual 70DP-0MR01, "Maintenance Rule," Revision 9
Nuclear Administrative and Technical Manual 70DP-0EE01, "Equipment Root Cause of Failure
Analysis," Revision 12
Section 1R13: Risk Assessment/Emergent Work
CRDRs
2704090, 2713743, and 2711884
Attachment
A-6
Procedures
31MT-9ZC07, "Miscellaneous Containment Building Heavy Loads," Revision 15
31MT-9RC43, "Control Element Assembly Extension Shaft Replacement," Revision 8
Section 1R14: Nonroutine Events
CRDRs
2327899, 2707423, 2714544, 2717298, 2715941, and 2715727
Procedures
40EP-9EO02, "Reactor Trip," Revision 7
40OP-9ZZ10, "Mode 3 to Mode 5 Operation," Revision 42
42ST-2ZZ02, "Inoperable Power Sources Action Statement," Appendix B, Revision 31
78OP-9ZZ02, "NAC-UMS Cask Loading Operations," Revision 8
Vendor Drawings
PVNGS-026, "VDS P&ID Schematics," Revision J
PVNGS-030, "Cooldown Elevations," Revision B
PVNGS-031, "VDS Spargers," Revision D
Miscellaneous
Core Protection Calculator Functional Block Diagram
Section 1R15: Operability Evaluations
CRDRs
2703945, 2705929, 2693663, 2704218, 2702302, 2707309, and 2707812
Procedures
Procedure 90DP-0IP1, "Condition Reporting," Revision 16
Procedure 40DP-9OP26, "Operability Determination," Revision 12
2693355, 2394073, and 2342097
Miscellaneous
Operability Determination 202, Revision 4
TSCCR 2375135, "LCO 3.6.3 Containment Isolation Valves SR 3.6.3.6 not Performed
Attachment
A-7
Adequately for CP 2B and 3B"
Design Change Request 2455773, "Design and Install a 42" Testable Blind Flange Inside
Containment on Penetrations 56 and 57 of the Containment Purge Refueling Train"
Analysis RA-13-C00-1997-052, "Proprietary-COLSS Cycle Independent Database Constants
Analysis," Revision 15
Deficiency WO 2704890
Section 1R19: Postmaintenance Testing
CRDRs
2699288, 2699943, and 2700187
Engineering Source Document, DMWO 2692447, "
Appendix A to 01-J-ZZI-004, "Controlled Motor Operator Database (CMODB)," Revision 22
Procedures
30DP-9MP01, "Conduct of Maintenance," Revision 36
Drawings
01-E-SIF-011, "Control Wiring Diagram - Safety Injection Shutdown CLG System HPSI 2 Flow
Control to Reactor Coolant Valve 1J-SIB-UV-626," Revision 2
01-E-SIB-011, "Elementary Diagram - Safety Injection Shutdown CLG System HPSI 2 Flow
Control to React Coolant Valve 1JSIB-UV-626," Sheet 2, Revision 7
Section 1R20: Refueling and Outage Activities
CRDRs
2695262, 2710401, and 2707372
Procedures
40OP-9ZZ16, "RCS Drain Operations," Revision 40
40OP-9ZZ20, "Reduced Inventory Operations," Revision 5
40OP-9SI01, "Shutdown Cooling Initiation," Revision 32
40ST-9ZZ09, "Containment Cleanliness Inspection," Revision 8
72IC-9RX03, "Core Reloading," Revision 24
Drawings
01-M-SIP-001, "P&I Diagram, Safety Injection and Shutdown Cooling System," Revision 25
Attachment
A-8
01-M-SIP-002, "P&I Diagram, Safety Injection and Shutdown Cooling System," Revision 24
01-M-RCP-001, "P&I Diagram, Reactor Coolant System," Revision 30
01-P-RCF-172, "Containment Building Reactor Vessel Head Vent Isometric," Revision 1
Vendor Drawing C-246-751-0, "Vent Pipe Orifice Installation," Revision 1
Vendor Drawing C-STD11-1070036-00, "Vent Pipe Orifice - 182.25" ID PWR," dated
November 24, 1981
Miscellaneous
U1R11 Shutdown Risk Assessment, Revision 0
U1R11 Shutdown Risk Assessment, Revision 1
U1R11 Shutdown Risk Assessment, Revision 2
Component Data Sheet for Valve 1PRCEVV221
Clearance 102479, "EDG Storage Tank"
Clearance 99955, "Half Pipe Permit"
Section 2OS1: Access to Radiologically Significant Areas
CRDRs
2489355, 2616040, 2637565, 2639813, 2642822, 2646026, 2650039, 2651063, 2651332,
2655725, 2664593, 2665023, 2670009, 2689815, 2691798, 2695319, 2695508, and 2696454
Nuclear Assurance Evaluation Reports and Self Assessments
ER-03-0151, "Dosimetry, Electronic Logs, SGRP, Training"
ER-03-0266, "ALARA, Contamination Control, Surveys, Radiation Exposure Permits"
ER-03-0269, "Reactor Head Stand, Posting, Job Coverage"
ER-03-0281, "U2R11Posting, REPs, and Surveys"
ER-03-0289, "Posting, Labeling, RP Walkdowns, Pump Bay Worker Knowledge"
ER-03-0300, "Radworker Practices, ALARA, Job Coverage, Contamination Control,
Radiography"
ER-03-0339, "Radioactive Material, Posting, Job Coverage, Radiography"
ER-03-0451, "Radiation Exposure, Access Control, Locked High Radiation Area
Self Assessment, Review of High Noise EPD Utilization in U2R11," dated January 22, 2004
Attachment
A-9
Radiation Exposure Permits
1-1343A, "Refuel Machine- Hoist Box Maintenance"
1-3002E, "Reactor Destack and Restack"
1-3306E, "Primary Side Steam Generator Maintenance"
1-3047A, "Reactor Vessel Closure Head Insulation Modification and Inspection"
Procedures
75DP-9RP01, "Radiation Exposure and Access Control," Revision 6
75DP-0RP02, "Radioactive Contamination Control," Revision 5
75RP-0RP01, "Radiological Posting and Labeling," Revision 19
75RP-9OP01, "Radiological Controls for Diving Operations," Revision 7
75RP-9OP02, "Control of Locked High radiation Areas and Very High Radiation Areas,"
Revision 15
75RP-9RP02, "Radiation Exposure Permits," Revision 16
75RP-9RP10, "Conduct of R.P. Operations," Revision 12
75RP-9RP16, "Special Dosimetry," Revision 10
Section 1EO6: Drill Evaluation
04-D-FAC-06005, "2004 Emergency Preparedness Drill"
EPIP-01, "Satellite Technical Support Center Actions," Revision 15
EPIP-02, "Operations Support Center Actions," Revision 27
EPIP-03, "Technical Support Center Actions", Revision 33
EPIP-04, "Emergency Operations Facility Actions," Revision 33
EPIP-99, "Standard Appendices, Appendix A- Emergency Action Levels," Revision 1
EPIP-99, "Standard Appendices, Appendix B- Protective Action Recommendations," Revision 1
EPIP-99, "Standard Appendices, Appendix D- Notification," Revision 1
EPIP-99, "Standard Appendices, Appendix E- ERDS Activation," Revision 1
EPIP-99, "Standard Appendices, Appendix F- Dose Projection," Revision 1
Attachment
A-10
EPIP-99, "Standard Appendices, Appendix G- Core Damage Assessment," Revision 1
EPIP-99, "Standard Appendices, Appendix H- Autodialer Activation," Revision 1
EPIP-99, "Standard Appendices, Appendix P- EAL Technical Bases," Revision 1
Section 4OA2: Identification and Resolution of Problems
CRDRs
2641696, 2456073, 2638327, 2630020, 2635803, 2639367, 2639681, 2643914, 2643868,
2643998, 2645590, 2647458, 2652045, 2653658, 2659887, 2684877, 2686659, 2687062,
2691715, 2699434, 2699031, 2699765, 2700949, 2705184, and 2706202
Procedure
01DP-9EM01, "Overtime Limitations," Revision 3
Section 4OA5: Other Activities
CRDRs
2699775, 2687861, and 2626902
Procedures
73TI-9ZZ78, "Visual Examination for Leakage," Revision 4
31ST-9SI01, "Cleaning/Inspection of ECCS Sumps," Revision 7
40ST-9ZZ09, "Containment Cleanliness Inspection," Revision 8
Miscellaneous
10 CFR 50.59 Screening, "40ST-9ZZ09 Procedure Change for Inspection to Ensure Open
Position of RCP Bay Personnel Access Gates," Revision 0
Calculation 01-EC-MA-0221, "AC Distribution," Revision 8
Calculation 02-EC-MA-0221, "AC Distribution," Revision 8
Calculation 03-EC-MA-0221, "AC Distribution," Revision 8
Calculation 13-EC-PB-0202, "Degraded Voltage Relay Setpoint," Revision 2
GL-79-36, "Adequacy of Station Electric Distribution Systems Voltages,"
Attachment
A-11
http://www.nrc.gov/reading-rm/doc-collections/gen-comm/gen-letters/1979/gl79036.html
Millstone 7/5/1976
ANO 9/16/78
NUREG-0800, Standard Review Plan, Branch Technical Position PSB-1, "Adequacy of Station
Electric Distribution System Voltages," http://www.nrc.gov/reading-
rm/doc-collections/nuregs/staff/sr0800/ch8/08a-app.pdf
Information Notice IN 2000-06, Offsite Power Voltage Inadequacies, ADAMS
Accession ML003695551
Regulatory Information Summary RIS 2000-24, Concerns about Offsite Power Voltage
Inadequacies and Grid Reliability Challenges Due to Industry Deregulation, ADAMS
Accession ML003695551
Callaway - LER 50-483/99-005, "Loss of Both Offsite Sources," ADAMS
Accession ML003706314, ML 003684343, and ML003691949
LIST OF ACRONYMS
ADV
atmospheric dump valve
American Society of Mechanical Engineers
control element assembly
CFR
Code of Federal Regulations
CRDR
condition report/disposition request
LER
licensee event report
main feedwater
radiation protection
resistance temperature detector
spent fuel pool
TI
temporary instruction
unresolved item
work order