ML060440603
| ML060440603 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 02/13/2006 |
| From: | Clay Johnson NRC/RGN-IV/DRP/RPB-A |
| To: | Blevins M TXU Power |
| References | |
| IR-05-005 | |
| Download: ML060440603 (44) | |
See also: IR 05000445/2005005
Text
February 13, 2006
Mike Blevins, Senior Vice President
and Chief Nuclear Officer
TXU Power
ATTN: Regulatory Affairs
Comanche Peak Steam Electric Station
P.O. Box 1002
Glen Rose, TX 76043
SUBJECT: COMANCHE PEAK STEAM ELECTRIC STATION - NRC INTEGRATED
INSPECTION REPORT 05000445/2005005 AND 05000446/2005005
Dear Mr. Blevins:
On December 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Comanche Peak Steam Electric Station, Units 1 and 2, facility. The enclosed
integrated inspection report documents the inspection findings which were discussed on
January 12, 2006, with Mr. R. Flores and other members of your staff.
This inspection examined activities conducted under your licenses as they related 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.
The report documents four self-revealing findings of very low safety significance (Green). All
four of these findings were determined to involve violations of NRC requirements. However,
because of the very low safety significance and because they are entered into your corrective
action program, the NRC is treating these four findings as noncited violations (NCVs) consistent
with Section VI.A.1 of the Enforcement Policy. If you contest any NCV in this report, you should
provide a response within 30 days of the date of this inspection report, with the basis for your
denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington
DC 200555-0001; with copies to the Regional Administrator Region VI; the Director, Office of
Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001;
and the NRC Resident Inspector at the Comanche Peak Steam Electric Station.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its
enclosure will be made available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRCs
document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
TXU Power -2-
Should you have any questions concerning this inspection, we will be pleased to discuss them
with you.
Sincerely,
/RA/
Claude Johnson, Chief
Project Branch A
Division of Reactor Projects
Docket Nos.: 50-445, 50-446
Enclosure: NRC Inspection Report 05000445/2005005 and 05000446/2005005
w/Attachment: Supplemental Information
cc w/enclosure:
Fred W. Madden, Director
Regulatory Affairs
TXU Power
P.O. Box 1002
Glen Rose, TX 76043
George L. Edgar, Esq.
Morgan Lewis
1111 Pennsylvania Avenue, NW
Washington, DC 20004
Terry Parks, Chief Inspector
Texas Department of Licensing
and Regulation
Boiler Program
P.O. Box 12157
Austin, TX 78711
The Honorable Walter Maynard
Somervell County Judge
P.O. Box 851
Glen Rose, TX 76043
Richard A. Ratliff, Chief
Bureau of Radiation Control
Texas Department of Health
1100 West 49th Street
Austin, TX 78756-3189
TXU Power -3-
Environmental and Natural
Resources Policy Director
Office of the Governor
P.O. Box 12428
Austin, TX 78711-3189
Brian Almon
Public Utility Commission
William B. Travis Building
P.O. Box 13326
Austin, TX 78711-3326
Susan M. Jablonski
Office of Permitting, Remediation and Registration
Texas Commission on Environmental Quality
MC-122
P.O. Box 13087
Austin, TX 78711-3087
Technological Services Branch
Chief
FEMA Region VI
800 North Loop 288
Federal Regional Center
Denton, Texas 76201-3698
TXU Power -4-
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
DRS Deputy Director (RJC1)
Senior Resident Inspector (DBA)
Branch Chief, DRP/A (CEJ1)
Senior Project Engineer, DRP/A (TRF)
Team Leader, DRP/TSS (RLN1)
RITS Coordinator (KEG)
Regional State Liaison Officer (WAM)
NSIR/DIPM/EPHP (REK)
Only inspection reports to the following:
J. Dixon-Herrity, OEDO RIV Coordinator (JLD)
ROPreports
CP Site Secretary (ESS)
SUNSI Review Completed: __CEJ_ ADAMS: / Yes G No Initials: __CEJ_
/ Publicly Available G Non-Publicly Available G Sensitive / Non-Sensitive
R:\_REACTORS\_CPSES\2005\CP2005-05RP-DBA.wpd
RIV:RI:DRP/A PE:DRP/A SRI:DRP/A C:DRS/EB C:DRS/OB C:DRS/PEB
AASanchez MABrown DBAllen JAClark ATGody LJSmith
E-CEJ /RA/ E-CEJ /RA/ /RA/ DLProulx for
2/3/06 1/27/06 2/3/06 1/27/06 1/31/06 1/27/06
C:DRS/PSB C:DRP/A
MPShannon CEJohnson
/RA/ /RA/
1/31/06 2/13/06
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Dockets: 50-445, 50-446
Report: 05000445/2005005 and 05000446/2005005
Licensee: TXU Generation Company LP
Facility: Comanche Peak Steam Electric Station, Units 1 and 2
Location: FM-56
Glen Rose, Texas
Dates: September 24 through December 31, 2005
Inspectors: D. Allen, Senior Resident Inspector
A. Sanchez, Resident Inspector
T. Brown, Project Engineer
W. McNeill, Reactor Inspector, Engineering Branch 1
P. Elkmann, Emergency Preparedness Inspector
S. Garchow, Operations Engineer
D. Livermore, Reactor Inspector
J. Keeton, Consultant
Approved by: Claude Johnson, Chief, Project Branch A
Division of Reactor Projects
Attachment: Supplemental Information
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -3-
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -6-
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -6-
1R01 Adverse Weather Protection (71111.01) . . . . . . . . . . . . . . . . . . . . . . . . . . . . -6-
1R04 Equipment Alignment (71111.04) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -6-
1R05 Fire Protection (71111.05Q) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -8-
1R07 Heat Sink Performance (71111.07) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -9-
1R08 Inservice Inspection Activities (71111.08) . . . . . . . . . . . . . . . . . . . . . . . . . . . -9-
1R11 Licensed Operator Requalification (71111.11) . . . . . . . . . . . . . . . . . . . . . . -13-
1R12 Maintenance Rule Implementation (71111.12) . . . . . . . . . . . . . . . . . . . . . . -14-
1R13 Maintenance Risk Assessments and Emergent Work Evaluation (71111.13) -14-
1R14 Personnel Performance During Nonroutine Plant Evolutions (71111.14) . . -15-
1R15 Operability Evaluations (71111.15) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -16-
1R16 Operator Workarounds (71111.16) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -17-
1R19 Postmaintenance Testing (71111.19) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -17-
1R20 Refueling and Outage Activities (71111.20) . . . . . . . . . . . . . . . . . . . . . . . . -18-
1R22 Surveillance Testing (71111.22) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -19-
1R23 Temporary Plant Modifications (71111.23) . . . . . . . . . . . . . . . . . . . . . . . . . -20-
1EP1 Exercise Evaluation (71114.01) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -21-
1EP6 Drill Evaluation (71114.06) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -22-
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -22-
4OA1 Performance Indicator Verification (71151) . . . . . . . . . . . . . . . . . . . . . . . . . -22-
4OA2 Problem Identification and Resolution (71152) . . . . . . . . . . . . . . . . . . . . . . -23-
4OA3 Event Followup (71153) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -27-
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -30-
4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -34-
SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2
LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-5
-2- Enclosure
SUMMARY OF FINDINGS
IR 05000445/2005005, 05000446/2005005; 09/24/2005-12/31/2005; Comanche Peak Steam
Electric Station, Units 1 and 2; Inservice Inspection Activities, Event Follow-up, and Other
Activities
This report covered a 3-month period of inspection by two resident inspectors, two reactor
inspectors, one operations engineer, one emergency preparedness inspector, one regional
project engineer, and one consultant. Four Green non-cited violations were identified. The
significance of most findings is indicated by their color (Green, White, Yellow, Red) using
Inspection Manual Chapter 0609, Significance Determination Process (SDP). Findings for
which the SDP does not apply may be Green or may be assigned a severity level after NRC
management review. The NRC's program for overseeing the safe operation of commercial
nuclear power reactors is described in NUREG-1649, ?Reactor Oversight Process, Revision 3,
dated July 2000.
A. NRC-Identified and Self-Revealing Findings
Cornerstone: Mitigating Systems
C Green. A Green self-revealing noncited violation of Technical Specification 5.4.1.a was identified for failure to implement the maintenance procedure to
properly install a check valve in the Emergency Diesel Generator 1-01 lubrication
system. On October 20, 2005, the diesel generator shutdown for lack of lube oil
to the turbo-chargers after 60 seconds during a post maintenance test. The lube
oil strainer check valve had been installed backwards during the previous
refueling outage but the opposite strainer had been in service for the ensuing 18
months. The check valve was reinstalled properly, the flow direction of similar
check valves verified, and the damaged turbo-chargers replaced.
The violation was more than minor because one of two lube oil strainers for the
turbo-chargers was incapable of flow, thus affecting the reliability of the diesel
generator. The finding has a human performance crosscutting aspect because
the failure to follow the procedure caused the diesel generator failure. However,
the error was committed in April 2004. The violation is of very low safety
significance because CPSES operating experience indicated that the lube oil
strainers had never been swapped outside of an outage, and then only to
balance run time on the equipment. The significance determination process
screened this out as Green because it only affected the mitigating systems
cornerstone and it did not cause an actual loss of safety function of a single train
nor a loss of safety function that contributed to external event initiated core
damage sequences. This finding has a problem identification and resolution
crosscutting aspect because it was caused by lack of effective corrective actions.
This event was entered into the corrective action program as Smart Form 2005-
004233 (Section 4OA3.1).
-3- Enclosure
C Green. A Green self-revealing noncited violation of Appendix B, Criterion XVI
was identified for failure to implement effective corrective actions for a significant
condition adverse to quality. Specifically, station service water Pump 1-01 was
returned to service on October 20, 2005, and after two hours of operation tripped
on an electrical fault on Phase C of the motor leads. The degraded electrical
condition of the motor lead had been identified during restoration from the pump
maintenance, but the actions taken to ensure the pump was reliable failed.
Phase C of the motor leads was replaced prior to returning the pump to service.
The failure to take effective corrective actions was the performance deficiency.
The violation was more than minor because the pump was returned to service
with a degraded motor lead. At the time of the event, Unit 1 was defueled and
did not require an operable station service water pump. However, Unit 2 was
required by Technical Specifications 3.7.8 to have at least one operable station
service water pump from the opposite unit. With Unit 2 at 100 percent power, a
significance determination was performed using Appendix A of Manual
Chapter 0609. The finding was determined to be of very low safety significance
(Green) because it did not represent a loss of system safety function, was not an
actual loss of safety function for a single Unit 2 train, did not involve equipment
or function specifically designed to mitigate a seismic, flooding, or severe
weather initiating event, and did not involve the total loss of any safety function
that contributed to external event initiated sequences. The cause of this finding
is related to the crosscutting aspects of problem identification and resolution.
The event was entered into the corrective action program as Smart
Form 2005-004220 (Section 4OA3.2).
- Green. A Green self-revealing noncited violation of Technical Specification 3.8.1
was identified, after both the alternate and emergency power supplies to a
6.9 kV safeguards bus failed to provide power to the bus within the time
assumed in the accident analysis. On October 19, 2004, an unplanned loss of
the preferred offsite power caused the Unit 2, Train B, 6.9 kV safeguards bus to
de-energize. A degraded Agastat relay delayed the normal power supply
breaker from opening for 30 seconds, which delayed powering the bus from the
alternate offsite AC power supply or the emergency diesel generator. This issue
had crosscutting aspects in the area of problem identification and resolution
because the licensee previously identified that aged Agastat relays were
unreliable and should be replaced if they were in service greater than 12 years.
The failed relay had been in service for 16 years.
The violation was more than minor because it impacted the Mitigating Systems
Cornerstone objective of availability, reliability, and capability of systems that
respond to initiating events. Using Inspection Manual Chapter 0609,
Appendix A, Determining the Significance of Reactor Inspection Findings for
At-Power Situations, the finding was determined to be of very low safety
significance because the likelihood of a medium or large break loss of coolant
accident coincident with a loss of offsite power, which are the only conditions
where the deficiency would cause a non-negligible change in the baseline risk
-4- Enclosure
profile, is less than or equal to 1E-6 per year. Therefore the change in core
damage frequency will be less than 1E-6 per year. The licensee captured the
issue in their corrective action program as Smart Form SMF-2004-003528
(Section 4OA5.2).
Cornerstone: Barrier Integrity
- Green. A Green noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI
(Corrective Action) was identified, in that licensee personnel failed to identify the
cause for a body-to-bonnet leak, a significant condition adverse to quality and
take corrective action to prevent recurrence. Specifically, licensee welders
repaired a body-to-bonnet leak on Valve 1-8702B, Residual Heat Removal Pump
1-02 hot-leg recirculation isolation valve, in April 2004 by installing a seal weld.
The valve required additional repair in October 2005 for a body-to-bonnet leak.
The failure to identify the root cause and to take effective corrective action to
prevent recurrence was a performance deficiency. This finding is greater than
minor because it is similar to Example 3.g. of Appendix E of Manual
Chapter 0612 because the leakage reoccurred. The inspectors found this
finding screened out of the Phase 1 process as Green. The inspectors
considered this finding to be of very low safety significance because the event
was leakage and not a line break. The cause of this finding is related to the
crosscutting aspects of problem identification and resolution. (Section 1R08.1)
B. Licensee Identified Violations
None.
-5- Enclosure
REPORT DETAILS
Summary of Plant Status
Comanche Peak Steam Electric Station (CPSES) Unit 1 began the reporting period at
100 percent power. The unit began power coastdown on October 5, 2005 and commenced a
reactor shutdown on October 8, 2005 at 8:56 a.m. to begin refueling outage 1RF11. The
reactor was manually tripped and entered Mode 3 at 11:39 a.m. that same day. On
November 8, 2005 Unit 1 ended refueling outage 1RF11 when the main generator output
breakers were closed at 1:51 a.m. The reactor achieved 100 percent reactor power on
November 15, 2005 at 3:51 p.m., and operated at essentially 100 percent power for the
remainder of the period.
CPSES Unit 2 operated at essentially 100 percent power for the entire reporting period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
a. Inspection Scope
The inspectors reviewed Abnormal Conditions Procedure Manual (ABN) ABN-912, Cold
Weather Preparations / Heat Tracing and Freeze Protection System Malfunction,
Revision 7, Section 2, Cold Weather Preparations, in the Unit 1 control room at the
onset of colder weather conditions during the week of November 28, 2005. The
inspectors reviewed the ABN-912 attachments and control room log to verify that plant
cooling units and dampers had been aligned for cold weather and that temperatures
were being monitored in accordance with the attachments.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment (71111.04)
.1 Partial System Walkdown (71111.04)
a. Inspection Scope
The inspectors: (1) walked down portions of the below listed risk important system and
reviewed plant procedures and documents to verify that critical portions of the selected
system were correctly aligned; and (2) compared deficiencies identified during the
walkdown to the licensee's corrective action program to ensure problems were being
identified and corrected.
-6- Enclosure
- Unit 2 Train B safety injection system in accordance with System Operating
Procedure (SOP) SOP-201B, Safety Injection System, Revision 6, while the
Train A emergency diesel generator (EDG) system was inoperable for scheduled
surveillance, on December 14, 2005
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
.2 Detailed Semiannual System Walkdown (71111.04S)
a. Inspection Scope
The inspectors conducted a detailed semiannual inspection of the Unit 1 and Unit 2
atmospheric relief valves (ARVs), and supporting systems, to verify the functional
capability of the system. The inspectors referenced and used the following documents
to verify proper system alignment, electrical power supply and setpoints :
- Integrated Plant Operating Procedure (IPO) IPO-002A, Plant Startup From Hot
Standby, Revision 18
- SOP-301A, Main Steam System, Revision 14
- CPSES Drawings M1-202 and M2-202, Flow Diagram Main Steam Reheat and
Steam Dump, multiple sheets and revisions
The inspectors also reviewed recent corrective action documents, system health reports,
outstanding work requests, and design issues to determine if any of these items
impacted the systems ability to operate as designed or indicated a degradation in
capability. In addition, the inspectors interviewed the system engineer and site valve
experts and discussed the systems maintenance history, and current and long range
plans to monitor, modify, or update the system and its components. A complete field
walkdown was completed by the inspectors during the week of December 26, 2005.
The inspector completed one sample.
b. Findings
No findings of significance were identified.
-7- Enclosure
1R05 Fire Protection (71111.05Q)
Fire Area Tours
a. Inspection Scope
The inspectors walked down the listed plant areas to assess the material condition of
active and passive fire protection features and their operational lineup and readiness.
The inspectors: (1) verified that transient combustibles and hot work activities were
controlled in accordance with plant procedures; (2) observed the condition of fire
detection devices to verify they remained functional; (3) observed fire suppression
systems to verify they remained functional; (4) verified that fire extinguishers and hose
stations were provided at their designated locations and that they were in a satisfactory
condition; (5) verified that passive fire protection features (electrical raceway barriers,
fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems)
were in a satisfactory material condition; (6) verified that adequate compensatory
measures were established for degraded or inoperable fire protection features; and
(7) reviewed the corrective action program to determine if the licensee identified and
corrected fire protection problems.
- Fire Area CA - Unit 1 containment building, all elevations on November 4, 2005
- Fire Zone SE016 - Unit 1 safeguards building 832 foot elevation electrical
equipment Room 96 on November 10, 2005
- Fire Zone EA057 - Unit 1 inverter battery room corridor Room 125 on
November 26, 2005
- Fire Zone EA054 - Unit 2 inverter battery room corridor Room 122 on
November 26, 2005
- Fire Zone 1-SB008 - Unit 1 safeguards corridor 810 foot elevation Rooms 78, 79,
and 82 on December 13, 2005
- Fire Zone 2-SB008 - Unit 2 safeguards corridor 810 foot elevation Rooms 78, 79,
and 82 on December 13, 2005
- Fire Zone AA21F - Units 1 and 2 auxiliary building 852 foot elevation
Rooms 234-235, 238-242 on December 13, 2005
The inspectors completed seven samples.
b. Findings
No findings of significance were identified.
-8- Enclosure
1R07 Heat Sink Performance (71111.07)
a. Inspection Scope
The inspectors reviewed the licensees program for maintenance, testing, and
surveillance of the Unit 1 Trains A and B Component Cooling Water (CCW) heat
exchangers to ensure that these risk-important heat exchangers are capable of
performing their required safety function during the design basis accident. Specifically,
the Unit 1 Train A CCW heat exchanger interior was physically inspected for foreign
material following the Unit 1 Train A station service water (SSW) pump ingestion of a
vacuum hose in August 2005. The inspectors also viewed the contents from a
containment spray seal oil cooler that was supplied from Train A CCW heat exchanger.
The inspectors also observed actual heat exchanger testing for the Train A CCW heat
exchanger, and reviewed the test data for the Train B CCW heat exchanger. The
inspectors verified that the frequency of monitoring and inspection was sufficient to
detect degradation prior to loss of heat removal capability. Corrective action documents
and system drawings were reviewed by the inspectors. The system engineer was also
interviewed by the inspectors.
The inspectors completed two samples.
b. Findings
No findings of significance were identified.
1R08 Inservice Inspection Activities (71111.08)
This inspection procedure requires a minimum sample size of four samples consisting of
Sections 02.01, 02.02, 02.03, and 02.04. All sections were completed except for 02.02
because the associated TI 2515/150 is not completed.
.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurizer Water
Reactor Vessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control
(Section 02.01)
a. Inspection Scope
The inspection procedure requires review of two or three types of nondestructive
examination activities and one to three welds performed on the reactor coolant pressure
boundary.
The inspectors observed 20 nondestructive examination activities including volumetric,
surface and visual examinations as follows:
-9- Enclosure
System Component/Weld Identification Examination Method
Safety 17 components, 11 struts, 5 snubbers and VT-3 (visual)
Injection 1 spring can: Summary Numbers 672400-
800, 673200, 673400-600, 673800,
673900, 674200, 674400, 674500, and
674600.
Safety 2 welded lugs: Summary Numbers 784300 Liquid Penetrant
Injection and 784550.
Residual Pipe to valve TBX-1-4101-3: Augmented Ultrasonic
Heat Removal Examination.
During the observation of each examination, the inspectors verified that activities were
performed in accordance with the American Society of Mechanical Engineers (ASME)
Boiler and Pressure Vessel Code requirements and applicable procedures. The
inspectors verified that the licensee compared the indications revealed by the
examinations against the previous outage examination reports as applicable. No
defects or reportable flaws were detected during the inservice examinations. The
inspectors verified that the licensee used calibrated and qualified instruments and
personnel.
Of the five ASME Class 1 and 2 welding activities performed by licensee personnel, the
inspectors reviewed Work Order (WO) WO-04-05-163997-00, a canopy seal weld on
Valve 1-CS8411. The inspectors verified that the welding activities met ASME Code
requirements.
The inspector completed all required samples.
b. Findings
Introduction. The inspectors identified a Green self-revealing noncited violation (NCV)
of 10 CFR Part 50, Appendix B, Criterion XVI. The licensee took inadequate corrective
actions in that the licensee repaired a leaking valve with a seal weld which subsequently
leaked.
Description. The inspectors found that licensee personnel planned to reweld a seal
weld because of evidence of boron leakage on Valve 1-8702B found during this outage.
Licensee welders repaired this valve in April 2004 because of boric acid leakage at that
time. Valve 1-8702B is a Residual Heat Removal Pump 1-02 hot-leg recirculation
isolation valve.
A review of the history of this type of repair found three additional examples where
licensee welders had seal welded the valve body-to-bonnet flanged connections
-10- Enclosure
because of evidence of boron leakage since 1995. The valves were 2-8378B, Reactor
Coolant System Loop 2-04 charging upstream check valve; 2-8379A, and 2-8379B,
Reactor Coolant System Loop 2-01 charging system downstream check valves.
Licensee personnel found all of these welds to subsequently leak within a year in 1996.
In 2005, licensee welders also repaired two valve body-to-bonnet flanged connections
because of evidence of leakage. These valves were numbered 2-8818B and 2-8818C,
residual heat removal loop check valves. In summary, this repair has been done six
times and failed four times. Two of the six times this repair has been done are unknown
at this time in respect to leakage because a refueling outage has not occurred. The
inspectors considered the evidence of boron leakage in these body-to-bonnet flanged
connections to be a significant condition adverse to quality.
Analysis. The inspectors found this finding to be greater than minor because it is similar
to Example 3.g. of Appendix E of Manual Chapter 0612 because the leakage reccurred.
The inspectors considered this finding as of very low safety significance because the
event was leakage and not a line break. The inspectors found this finding screened out
of the Phase 1 process as Green. The licensee issued a Smart Form (SMF)
SMF-2005-004209 regarding this finding.
Enforcement. Criterion XVI, Corrective Actions, of Appendix B to 10 CFR Part 50
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 action taken to preclude repetition. Contrary to the above,
the measures established to identity the root cause and take corrective actions to
prevent recurrence were inadequate in that leakage of the body-to-bonnet flanged
connections on Valve 1-8702B after previous repair in 2004, and on Valves 2-8378B,
2-8379A/B in 1995, were recurrent. The inspectors identified this finding as an NCV
because of its very low safety significance and because the licensee has entered this
finding in its corrective action program. This is consistent with Section VI.A. of the NRC
Enforcement Policy: NCV 05000445/2005005-01, Inadequate Corrective Actions for a
Leaking Valve with a Seal Weld which Subsequently Leaked.
.2 Pressurizer Water Reactor Vessel Upper Head Penetration Inspection Activities
(Section 02.02)
a. Inspection Scope
The inspection procedure requires observation or review of upper head inspections after
the completion of Temporary Instruction 2515/150. The procedure requires samples
similar in number to the preceding section.
The licensee plans to replace this head, and thus close the Temporary
Instruction 2515/150. The licensee did not perform upper head inspections other than
visual during this outage. The visual inspection activities are documented in
Section 1R20 of this report.
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b. Findings
No findings of significance were identified.
.3 Boric Acid Corrosion Control Inspection Activities (Section 02.03)
a. Inspection Scope
The procedure requires observation or review of boric acid corrosion control activities.
Specifically, the procedure requires review of one to three engineering evaluations
performed for boric acid residue found on reactor coolant system piping and
components. This procedure also required review of one to three corrective actions
taken because of evidence of boric acid leaks.
The inspectors reviewed records of a visual examination of the reactor coolant system
pressure boundary integrity walkdown. The inspectors reviewed the 58 areas with light
boric acid residue identified by the licensee as of the time of this review (the licensee
had not completed all the inspections) to assure identification and correction of leakage.
The inspectors reviewed the SMF written to evaluate and clean the areas identified
during the last inspection. The inspectors verified that licensee personnel adequately
evaluated 30 minor leaks including one active leak to assure correction of leakage
problems. The inspectors reviewed the corrective actions taken at that time.
The inspector completed all required samples.
b. Findings
No findings of significance were identified.
.4 Steam Generator Tube Inspection Activities (Section 02.04)
a. Inspection Scope
The inspectors reviewed the leakage history for the steam generators to verify that the
licensee had no leakage during operations before the shutdown. The inspectors verified
that licensee personnel and contractors used properly qualified eddy current probes and
equipment for the expected types of tube degradation to assure proper identification and
evaluation of indications. The inspectors observed the collection and analysis and
resolution of nine calibration groups of eddy current data performed by contractor
personnel to evaluate tubes and possible loose parts in the steam generators to assure
proper implementation of the procedures and program requirements. The inspectors
verified that the licensee analysts reviewed the areas of potential degradation, based on
site-specific and industry experience, to assure proper use of this information. The
inspectors verified that the licensee compared flaws detected during the current outage
against the previous outages data. The inspectors reviewed the repair criteria used to
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assure compliance with technical requirements. The inspectors also verified the
licensees eddy current examination scope and expansion criteria met the Technical
Specifications, industry guidelines, and commitments to the NRC.
Regarding plugging and in-situ pressure testing, at the time of this inspection the
licensee had not established the full scope of plugging and in-situ pressure testing to be
performed. The inspectors verified that the predictions of tube plugging appeared to be
the same as experienced in the past.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
Resident Inspector Quarterly Review (71111.11Q)
a. Inspection Scope
The inspector observed two licensed operator requalification training scenarios in the
control room simulator on December 14, 2005. The first training session began with a
short lesson on immediate operator actions for a pressurizer channel failure response.
This was followed by a scenario that consisted of a feedwater heater tube leak, a main
feedwater trip followed by a reactor trip, and loss of heat sink. The second training
scenario consisted of a slow degradation of grid voltage and frequency, eventual loss of
the 345kV buses, reactor trip, loss of the 138 kV switchyard, loss of all AC power and
Train B DC power.
Simulator observations included formality and clarity of communications, group
dynamics, the conduct of operations, procedure usage, command and control, and
activities associated with the emergency plan. The inspectors also verified that
evaluators and the operators were identifying crew performance problems as applicable.
The inspectors also observed a requalification classroom training session regarding the
main feedwater system.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
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1R12 Maintenance Rule Implementation (71111.12)
a. Inspection Scope
The inspectors independently verified that CPSES personnel properly implemented
10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at
Nuclear Power Plants, for the following equipment performance problems:
C During the week of November 28, the inspectors reviewed the corrective actions
and performance history of the Units 1 and 2 charging pump suction high point
vent problems identified in SMF-2002-002396 and SMF-2002-004242 that had
resulted in both systems being placed in Maintenance Rule (a)(1). Both Units
systems have been returned to (a)(2) status based on successfully meeting the
performance criteria.
C The common control room Heating Ventilation and Air Conditioning (HVAC)
System, Train B was placed into (a)(1) status due to exceeding the functional
performance criterion of two functional failures within two years. Both failures
were from misaligned motor control center electrical bucket stabs. New
performance criterion for the system has been established. This issue was
entered and is being tracked in the corrective action program as
SMF-2005-003830.
The inspectors reviewed whether the structures, systems, or components (SSCs) that
experienced problems were properly characterized in the scope of the Maintenance
Rule Program and whether the SSC failure or performance problem was properly
characterized. The inspectors assessed the appropriateness of the performance criteria
established for the SSCs where applicable. The inspectors also independently verified
that the corrective actions and responses were appropriate and adequate.
The inspectors completed two samples.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation (71111.13)
a. Inspection Scope
The inspectors reviewed selected activities regarding risk evaluations and overall plant
configuration control. 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. The activities reviewed
were associated with:
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C Delay of completion of maintenance on switchyard Breaker 7980 resulted in
increased risk for scheduled troubleshooting and maintenance of SSW
Pump 1-02 flow indication on September 30, 2005
C Reschedule of crane operations near Transformer XST1 during scheduled
surveillance testing of EDG 2-02 and ATWS Mitigation System Actuation Circuit
on October 5 - 6, 2005
C Outage Risk Assessment for Refueling Outage 1RF11 (scheduled for
October 8 - November 7, 2005) on October 6, 2005
C Delayed completion of maintenance on switchyard Breaker 8090 with concurrent
scheduled maintenance on EDG 2-02 and Unit 1 reactor coolant system reduced
inventory on October 27 - 28, 2005
C Switchyard Breaker 8050 restored but air switch left open, making the Venus line
inoperable, discovered October 30 after opening Breaker 7970 on
October 29-30, 2005
C Unit 1 reduced inventory evolution reschedule conflicted with the scheduled
EDG 2-02 surveillance on November 2, 2005
The inspectors completed six samples.
b. Findings
No findings of significance were identified.
1R14 Personnel Performance During Nonroutine Plant Evolutions (71111.14)
a. Inspection Scope
For the two nonroutine events described below, the inspectors observed the simulator
just-in-time training and reviewed the applicable procedures prior to the evolution. The
inspectors attended pre-job briefings and observed portions of the evolution from the
control room. Procedural use, communications, coordination between organizations and
safe operation of the plant during the evolution were evaluated to ensure risk was
minimized and safety was maintained.
- On October 8, 2005, the control room operators commenced the Unit 1 reactor
shutdown to begin refueling outage 1RF11 via boration as per IPO-003A, Power
Operations, Revision 24. At 11:39 a.m., reactor operators manually tripped the
reactor and entered EOP-0.0A, Reactor Trip or Safety Injection, Revision 7.
Operators transitioned to EOS-0.1A, Reactor Trip Response, Revision 7 and
IPO-005A, Plant Cooldown From Hot Standby to Cold Shutdown, Revision 21.
The inspectors observed control room activities and operator actions during the
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evolution to ensure formal and clear communications, proper procedure usage,
command and control activities, proper use of emergency procedures, and the
controlled and safe shutdown of the Unit 1 reactor.
- On October 11, 2005, the control room operators lowered Unit 1 reactor coolant
system water level to approximately 56 inches above the reactor core (Midloop)
in preparation to remove steam generator primary manways and install steam
generator nozzle dams. The inspectors reviewed Generic Letter Number 88-17,
Loss of Decay Heat Removal and TXUs responses. Integrated Plant
Operating Procedure IPO-010A, Reactor Coolant System Reduced Inventory
Operations, Revision 16, was reviewed to ensure adequate controls were in
place. The control room activities and operators actions were observed during
the evolution to ensure the procedure was followed, plant instruments were
responding correctly, conservative decisions were made, and that the evolution
was completed safely. Control room activities were periodically observed for
distractions to the operators while the reactor vessel water level remained in
reduced inventory.
The inspectors completed two samples.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors: (1) reviewed plant status documents such as operator shift logs,
emergent work documentation, deferred modifications, and standing orders to
determine if an operability evaluation was warranted for degraded components;
(2) referred to the Updated Safety Analysis Report and design basis documents to
review the technical adequacy of licensee operability evaluations; (3) evaluated
compensatory measures associated with operability evaluations; (4) determined
degraded component impact on any Technical Specifications; (5) used the SDP to
evaluate the risk significance of degraded or inoperable equipment; and (6) verified that
the licensee has identified and implemented appropriate corrective actions associated
with degraded components. The inspectors interviewed appropriate licensee personnel
to provide clarity to operability evaluations, as necessary. Specific operability
evaluations reviewed are listed below:
C Quick Technical Evaluation (QTE) QTE-2005-002098-01-00, distance between
Unit 1 Train C Cable NK130951 and Handswitch 1/1-8823 does not meet
separation criteria of ES-100 Appendix F, Attachment 1, Table 1, reviewed the
week of November 21, 2005
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- Evaluation (EVAL) EVAL-2005-004233-05-00, review past operability of
EDG 1-01 with Check Valve 1DO-0152 installed backwards, reviewed on
November 22, 2005
- QTE-2005-003945-01-00, determine operability of the common uninterruptible
power supply (UPS) and distribution room HVAC system Train B following an
observation of the compressor failing to start when the UPS air conditioning
system was manually requested to start, reviewed on December 29-30, 2005
The inspectors completed three samples.
b. Findings
No findings of significance were identified.
1R16 Operator Workarounds (71111.16)
Cumulative Review of the Effects of Operator Workarounds
a. Inspection Scope
On November 29, 2005, the inspectors reviewed cumulative effects of identified
operator workarounds on reliability, availability, and potential for system misoperation on
both Units. The inspectors reviewed the cumulative effects of the operator workarounds
on multiple mitigating systems and the ability of operators to respond in a correct and
timely manner to plant transients and accidents.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
The inspectors witnessed or reviewed the results of the postmaintenance tests for the
following maintenance activities:
- Unit 1 SSW Pump 1-01 motor following failure of the Phase C cable to the motor
on October 20, 2005, in accordance with Maintenance Section - Electrical
procedure MSE-G0-4201, "Megger Testing of Power Cables, Motors and
Generators," Revision 6, and MSE-G0-4003, "DC High Potential Testing With
Baker Advanced Winding Analyzer," Revision 0, on October 24, 2005
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C Unit 1 EDG 1-02 following digital upgrade of the voltage regulation system, in
accordance with Maintenance Section-Mechanical Manual Procedure
MSM-P0-3375, "Emergency Diesel Engine Break-in Run and Post Maintenance
Run," Revision 7, on November 3, 2005
C Unit 1 Turbine Driven Auxiliary Feedwater (TDAFW) Pump following outage
related maintenance including replacement of the governor, in accordance with
Equipment Test Procedure ETP-304A, "Turbine Driven Auxiliary Feedwater
Pump Overspeed Test," Revision 3, System Operation Procedure SOP-304A,
"Auxiliary Feedwater System," Revision 16, Testing Procedure PPT-S1-9103A,
"TDAFW Pump Actuation and Response Time Test, Train A," Revision 2 and
OPT-206A, "AFW System," Revision 25, on November 6, 2005
In each case, the associated work orders and test procedures were reviewed in
accordance with the inspection procedure to determine the scope of the maintenance
activity and to determine if the testing was adequate to verify equipment operability.
The inspectors completed three samples.
b. Findings
No findings of significance were identified.
1R20 Refueling and Outage Activities (71111.20)
a. Inspection Scope
The inspectors evaluated licensees 1RF11 activities to ensure that risk was considered
when developing and when deviating from the outage schedule, the plant configuration
was controlled in consideration of facility risk, mitigation strategies were properly
implemented, and Technical Specification requirements were implemented to maintain
the appropriate defense-in-depth. Specific outage inspections performed and outage
activities reviewed and/or observed by the inspectors included:
- Discussions and review of the outage schedule concerning risk with the Outage
Manager
C Unit shutdown and cooldown
C Containment walkdowns to identify indications of reactor coolant leakage,
evaluate material condition of equipment not normally available for inspection,
inspect fire protection equipment and fire hazards, observe radiation protection
postings and barriers, and evaluate coatings and debris for potential impact on
the recirculation containment sumps
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C Reduced inventory and midloop activities to perform steam generator manway
removal, nozzle dam installation and removal
C Reactor coolant system instrumentation including Mansell level instrumentation
C Defense in depth and mitigation strategy implementation
C Containment closure capability
C Verification of decay heat removal system capability
C Spent fuel pool cooling capability
C Reactor water inventory control including flow paths, configurations, alternate
means for inventory addition, and controls to prevent inventory loss
C Controls over activities that could affect reactivity
C Refueling activities that included fuel offloading, fuel transfer, and core reloading
C Electrical power source arrangement
C Containment cleanup and inspection
C Containment recirculation sump inspection
C Unit heatup and startup
C Reactor vessel upper head penetration review and inspection
C Reactor vessel lower head penetration review and inspection
C Licensee identification and resolution of problems related to refueling activities
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors evaluated the adequacy of periodic testing of important nuclear plant
equipment, including aspects such as preconditioning, the impact of testing during plant
operations, and the adequacy of acceptance criteria. Other aspects evaluated included
test frequency and test equipment accuracy, range, and calibration; procedure
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adherence; record keeping; the restoration of standby equipment; test failure
evaluations; system alarm and annunciator functionality; and the effectiveness of the
licensees problem identification and correction program. The following surveillance test
activities were observed and/or reviewed by the inspectors:
- Unit 1 containment close out inspection in accordance with procedure OPT-305,
"Containment Close Out Inspection," Revision 10 and WO-5-04-504191-AA,
reviewed on November 4, 2005
- Unit 1 low power physics testing following refueling, in accordance with Nuclear
Engineering Procedure NUC-301, "Low Power Physics Testing," Revision 12,
reviewed on November 10, 2005
- Unit 1, reactor coolant system leak rate surveillance, in accordance with
OPT-303, "Reactor Coolant System Water Inventory," Revision 10, reviewed on
November 21, 2005
- Unit 1 Train A slave relay and containment isolation valve actuation test, in
accordance with OPT-459A, Train A Safeguards Slave Relay K623 Actuation
Test, Revision 5, reviewed on December 13, 2005
The inspectors completed four samples.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report, plant drawings,
procedure requirements, Technical Specification and Technical Requirements Manual to
ensure that the below listed temporary modification was properly implemented. The
inspectors: (1) verified that the modification did not have an affect on system
operability/availability; (2) verified that the installation was consistent with the
modification documents; (3) ensured that the post-installation test results were
satisfactory and that the impact of the temporary modification on permanently installed
SSC's were supported by the test; (4) verified that the modification was identified on
control room drawings and that appropriate identification tags were placed on the
affected equipment; and (5) verified that appropriate safety evaluations were
completed. The inspectors verified that licensee identified and implemented any needed
corrective actions associated with temporary modifications.
- Unit 1 Construction Access Facility installed at tornado missile Door S1-27 at the
south end of the Unit 1 safeguards building, reviewed on December 4, 2005
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The inspectors completed one sample.
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP1 Exercise Evaluation (71114.01)
a. Inspection Scope
The inspectors reviewed the objectives and scenario for the 2005 biennial emergency
plan exercise to determine if the exercise would acceptably test major elements of the
emergency plan. The scenario simulated a failure to automatically isolate a liquid
release, plant fire lasting greater than 15 minutes, a reactor coolant pump failure,
mechanical core damage, fission product barrier failures, and a radiological release to
the environment via a steam generator tube rupture and stuck-open steam generator
atmospheric safety valve, to demonstrate the licensee's capabilities to implement the
The inspectors evaluated exercise performance by focusing on the risk-significant
activities of classification, notification, protective action recommendations, and offsite
dose consequences in the following emergency response facilities:
- Simulator Control Room
- Operations Support Center
- Emergency Operations Facility
The inspectors also assessed personnel recognition of abnormal plant conditions, the
transfer of emergency responsibilities between facilities, communications, protection of
emergency workers, emergency repair capabilities, and the overall implementation of
the emergency plan.
The inspectors attended the post-exercise critiques in each of the above facilities to
evaluate the initial licensee self-assessment of exercise performance. The inspectors
also attended a subsequent formal presentation of critique items to plant management.
The inspectors completed one sample.
b. Findings
No findings of significance were identified.
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1EP6 Drill Evaluation (71114.06)
a. Inspection Scope
On November 28, 2005, the inspectors evaluated the adequacy of emergency drills that
contributed to performance indicator statistics performed on that day. Observations of
two operations crews in the control room simulator included opportunities for emergency
classifications and offsite notifications. The inspectors reviewed the drill scenario, drill
objectives, activity log sheets, evaluations, and critique notes. The inspectors also
observed the shift manager critique for both crews and discussed observations with the
drill controllers and evaluators from the control room simulator. The inspectors verified
that the licensee adequately conducted the drills and critiqued the drill performance in
accordance with the facility guidelines.
The inspectors completed one sample.
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 July 2004 through September 2005. The definitions and guidance of
NEI 99-02, Regulatory Assessment Indicator Guideline, Revisions 2 and 3, were used
to verify the licensees basis for reporting each data element in order to verify the
accuracy of performance indicator data reported during the assessment period.
Licensee performance indicator data was reviewed against the requirements of Staff
Guideline 20, NRC Performance Indicators, Revisions 6 and 7.
Emergency Preparedness Cornerstone:
- Drill and Exercise Performance
- Emergency Response Organization Participation
- Alert and Notification System Reliability
The inspector reviewed a 100 percent sample of drill and exercise scenarios and
licensed operator simulator training sessions, notification forms, and attendance and
critique records associated with training sessions, drills, and exercises conducted during
the verification period. The inspector reviewed selected emergency responder drill
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participation records. The inspector reviewed alert and notification system testing
procedures, maintenance records, and a 100 percent sample of siren test records. The
inspector also interviewed licensee personnel responsible for collecting and evaluating
performance indicator data.
The inspector completed three samples during this inspection.
b. Findings
The inspector identified 11 instances in which the licensee evaluated offsite notification
forms as accurate when a site-wide emergency condition was marked as applying only
to Unit 1. NEI 99-02, Regulatory Assessment Performance Indicators, Revisions 2
and 3, identifies the unit applicability of an emergency condition as a component of
offsite notification form accuracy. The inspector determined that the licensee had not
provided guidance regarding the correct marking of unit applicability when emergency
conditions impact more than one unit, resulting in inconsistent performance in marking
the offsite notification form. The reevaluation of these 11 opportunities has the potential
to cause the licensees Drill and Exercise Performance Indicator to drop below the
established 90% threshold.
This finding is similar to the Reactor Oversight Program (ROP) Frequently Asked
Question (FAQ) 338, dated March 2003, which addressed evaluation of Drill or Actual
Event as marked on offsite notification forms. FAQ 338 instructed licensees to submit
similar issues to the ROP working group for guidance regarding post-submittal
reevaluation. An Unresolved Item has been opened pending resolution of an FAQ
submitted to the ROP working group on this issue; URI 05000445;05000446/2005005-
02, Notification Form Accuracy Requires Additional Guidance.
4OA2 Problem Identification and Resolution (71152)
.1 Review of Items Entered into the Corrective Action Program
a. Inspection Scope
As required by Inspection Procedure 71152, "Identification and Resolution of Problems,
and in order to help identify repetitive equipment failures or specific human performance
issues for follow-up, the inspectors performed a routine screening of all items entered
into the licensees corrective action program. This review was accomplished by
reviewing the licensees computerized corrective action program database (SMFs),
reviewing hard copies of selected SMFs and attending related meetings such as Plant
Event Review Committee (PERC) meetings.
b. Findings
No findings of significance were identified.
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.2 Semiannual Trend Review
a. Inspection Scope
On December 23, 2005, the inspectors completed a semiannual review of licensee
internal documents, reports, and performance indicators to identify trends that
might indicate the existence of more safety significant issues. The inspectors reviewed
the following types of documents:
C Corrective Action Documents (Smart Forms)
C System Health Reports
C Planned Maintenance Work Week Critiques
C CPSES Nuclear Overview Department Evaluation Reports (Audits)
C Human Performance Program Health Indicators Package
C Corrective Action Program Health report
C Station Reliability Issues
C Degraded conditions evaluated in accordance with Generic Letter 91-18
C CPSES Self-Assessment Reports
b. Findings and Observations
No findings of significance were identified. However, during the review, the inspectors
did note the following two items: (1) several issues related to foreign material exclusion,
including fuel clad failure due to debris; and (2) issues related to the reliability of the
main turbine generator digital control system and operator errors committed while
operating the controls. The inspectors did not identify any additional trends.
The inspectors determined that the licensee had adequately identified adverse trends
and entered them into the corrective action program using an appropriate threshold.
.3 Selected Issue for In-Depth Review: Review of Unit 2 TDAFW Pump
a. Inspection Scope
The inspectors performed a detail review of an issue involving the Unit 2 TDAFW pump
failure to reduce speed during an operational surveillance test run. This issue was
placed into the licensees corrective action program as SMF-2005-002054. The
inspectors reviewed the apparent cause evaluation, vendor written communication
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(VL-05-002561), and procedure MSM-C0-8721, Governor Valve for Terry Turbine,
Revision 1. The inspectors also performed a detailed system walkdown, and discussed
the issue with the system engineer.
b. Findings and Observations
No findings of significance were identified. On May 12, 2005 during an operational
surveillance run on the Unit 2 TDAFW pump, the turbine failed to reduce speed below
2440 revolutions per minute (rpm) when directed, by the procedure, for verification of
governor oil level. The licensee determined that there was proper oil level in the
governor, and determined that the ability of the governor valve to close completely did
not cause the TDAFW pump to become inoperable. The safety function of the TDAFW
pump is to operate at a speed of at least 4075 rpm, which it was capable of doing at that
time.
The apparent cause analysis was completed and approved on August 10, 2005 and was
determined using the Why Tree technique. The cause for the TDAFW pump not being
able to reduce speed below 2440 rpm was determined to be the improper setting of the
governor valve linkage. The governor valve linkage was not set correctly due to the
difficulty of measuring the gap between the governor valve stem and the cam plate,
which was specified as 0.075 inch, with a dial indicator in a physically cramped space.
Two corrective actions were generated from the apparent cause analysis. The
procedure controlling the TDAFW maintenance was modified to measure the gap
between the governor valve stem and the cam plate in terms of 1/16 inch. This allows
the mechanics to measure the gap with a ruler instead of a dial indicator. The licensee
plans to purchase a spare Terry Turbine to allow the just-in-time training of the
mechanics.
The licensee took the immediate action of readjusting the governor valve linkage and
completed the necessary corrective action in a reasonable amount of time
commensurate with the safety significance of the issue. SMF-2005-004986-00 was
initiated to complete an effectiveness review of the completed corrective actions.
The inspectors completed one sample.
.4 Selected Issue for In-Depth Review: Review of Unit 2, Steam Generator 2-04
Atmospheric Relief Valve Repeatedly Exceeding Operational Alert Limits
a. Inspection Scope
The inspectors performed a detail review of an issue involving the Unit 2 ARV,
2-PV-2328, repeatedly exceeding its operational alert limit stroke time (open direction)
test. The inspectors identified at least five occurrences since February 2004. The stroke
time surveillance is performed on a 92 day frequency. The inspectors reviewed
OPT-504B, MS Section XI Valves, Revision 10, recent system and component health
reports, and Smart Forms. The Smart Forms reviewed are: SMF-2004-000566,
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SMF-2004-003610, SMF-2005-000228, SMF-2005-002654, and SMF-2005-003804.
Interviews were conducted with the system engineer, in-service testing engineer, and
licensee valve experts. The inspectors also performed a system walkdown.
b. Findings and Observations
No findings of significance were identified; however the inspectors identified that the
licensee had not identified nor had any action in place for Unit 2 ARV, 2-PV-2328,
repeatedly exceeding the alert threshold for stroke time (open direction) during
operational surveillance testing.
Between February 15, 2004 and October 10, 2005, the Unit 2 ARV, 2-PV-2328, had
exceeded its operational alert limit stroke time test five times. In each instance the ARV
had exceeded its surveillance alert stroke time limit of 9.0 seconds (open direction), but
had not exceeded the acceptance criterion of 10 seconds. The design basis document
states that the ARVs are required to be capable of a full stroke within 20 seconds,
therefore, the valve was declared operable. Each of these instances of the valve
exceeding its stroke time alert limit, the issue was placed into the corrective action
program and evaluated. In each instance, the inservice testing engineer had evaluated
the results, recommended no action, and determined that there was no significant
degradation of valve performance.
In general, there has been a step increase in all Unit 2 ARV stroke times in the October
2003 time frame. The step change and the trend are especially obvious for the ARV
2-PV-2328. This trend was not identified and was not being addressed by the licensee.
ASME Section XI sets alert limits and acceptance criteria for valve stroke times based
on reference stroke time valves. This program is in place to detect degrading
components to protect from unexpect failures. The licensee was not trending any of the
surveillance testing results or the number of times this valve had exceeded the alert
setpoint. The result of this review is that the licensee was not trending or aware of the
change in ARV performance. This was a missed opportunity to identify a change in
component function. The licensee has entered the issue into the corrective action
program as SMF-2006-00125 and is currently reviewing the issue to determine a cause
and to determine what corrective actions should be taken.
The inspectors complete one sample.
.5 Emergency Preparedness Annual Sample Review
a. Inspection Scope
The inspectors reviewed summaries of corrective actions assigned to emergency
preparedness during calendar years 2004 and 2005, reviewed 6 drill reports, and
observed licensee performance during a full-scale exercise, to determine the
effectiveness of previous corrective actions.
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b. Findings and Observations
No findings of significance were identified.
.6 Inservice Inspection Review of Problem Identification and Resolution
a. Inspection Scope
The inspection procedure requires review of a sample of problems associated with
inservice inspections and steam generator inspections documented by licensee
personnel in the corrective action program for appropriateness of the corrective actions.
The inspectors reviewed 9 of the 56 SMFs written since the last outage which dealt with
inservice inspection and steam generator eddy current inspection activities and found
the corrective actions were appropriate. The inspectors performed this review to assure
that the licensee had an appropriate threshold for entering issues into the corrective
action program and had procedures that direct root cause evaluations when necessary.
b. Findings
No findings of significance were identified.
4OA3 Event Follow-up (71153)
.1 Unit 1 EDG 1-01 trip due to Check Valve 1DO-0152 installed backwards in lubrication oil
system
a. Inspection Scope
The inspectors reviewed the trip of the EDG 1-01 which occurred on October 20, 2005
during the initial post maintenance run. The inspectors interviewed personnel involved,
attended the PERC meeting, reviewed SMFs and procedures.
b. Findings
Introduction. A Green, self-revealing, NCV was identified for failure to properly perform
the installation procedure for Check Valve 1DO-0152 in the EDG 1-01 lube oil system,
as prescribed in Technical Specification 5.4.1.a.
Description. On October 20, 2005, EDG 1-01 was started for a post maintenance run
following the 1RF11 outage work on the EDG. The EDG tripped 60 seconds after
starting on low lube oil pressure to the turbo-chargers. Troubleshooting by the licensee
found that the right bank lube oil strainer outlet Check Valve 1DO-0152 was installed
backwards, preventing lube oil flow to the turbo-chargers and rocker arm assemblies.
The turbo-chargers were replaced and found to have been damaged by this event.
Check Valve 1DO-0152 had last been replaced the previous refueling outage on
-27- Enclosure
April 11, 2004. The installation had been performed in accordance with maintenance
procedure MSM-P0-332, "Emergency Diesel Generator Lube Oil Check Valve
Maintenance," Revision 2, Step 8.16.2, which required a verification of the check valve
to ensure it was installed with the flow (arrow) pointing away from the strainer. Check
Valve 1DO-0152 was found with the flow arrow pointing towards the strainer. The
EDG 1-01 lube oil system had been aligned through the left bank lube oil strainer during
the operating cycle, and the strainer alignment was shifted following the 1RF11 work
window to balance run time on the equipment. Similar check valves in the other three
EDGs were verified to be installed with the proper orientation, and Check
Valve 1DO-0152 was reinstalled correctly. A review of the CPSES operating experience
indicated the lube oil strainers had never been swapped outside of an outage for either
units.
Analysis. The inspectors determined that the licensees failure to install check valve
1DO-0152 in the EDG 1-01 lube oil system correctly was a performance deficiency.
This finding is more than minor because the improper installation of the check valve
prevented flow through the right bank lube oil strainer, which affected the mitigating
systems cornerstone objective to ensure the availability, reliability and capability of
systems that respond to initiating events to prevent undesirable consequences. This
finding has a human performance cross-cutting aspect because the failure to follow the
maintenance procedure was the cause of the degraded condition. Phase 1 of the
significance determination process screened this finding as very low safety significance
(Green) because it only affected the mitigating systems cornerstone, was not a design
or qualification deficiency, did not cause a loss of system safety function or an actual
loss of safety function of a single train, did not involve equipment or functions
specifically designed to mitigate a seismic, flooding, or severe weather initiating event,
and did not involve the total loss of a safety function that contributes to external event
initiated core damage sequences.
Enforcement. Technical Specification 5.4.1.a requires written procedures to be
established, implemented, and maintained covering activities recommended in
Regulatory Guide 1.33, Revision 2, Appendix A, which includes maintenance
procedures that could affect performance of safety-related equipment. Contrary to the
above, maintenance procedure MSM-P0-332, "Emergency Diesel Generator Lube Oil
Check Valve Maintenance," Revision 2 was not properly implemented on April 11, 2004.
Because this violation was of very low safety significance and was entered into the
corrective action program as SMF-2005-004233, it is being treated as an NCV,
consistent with Section VI.A.1 of the NRC Enforcement Policy:
NCV 05000445/2005005-03, Trip of Emergency Diesel Generator Due to Lube Oil
Check Valve Installed Backwards.
-28- Enclosure
.2 Unit 1 Station Service Water Pump 1-01 Trip Due to Overcurrent Condition on Phase C
a. Inspection Scope
The inspectors reviewed the trip of the SSW Pump 1-01 which occurred on October 20,
2005. The inspectors interviewed personnel involved, attended the PERC meeting,
reviewed Smart Forms, and procedures.
b. Findings
Introduction. A Green, self-revealing, NCV was identified for failure to implement
effective corrective actions for a condition adverse to quality prior to returning a safety
related SSW pump to service.
Description. On October 19, 2005, a degraded condition had been noted on the Phase
C cable of the SSW Pump 1-01 during preparations to reland the motor leads following
pump overhaul. The licensee made repairs to correct the degraded conditions by
replacing part of the Phase C cable closest to the motor. Following surveillance testing,
the licensee declared the SSW Pump 1-01 operable. On October 20, 2005 at 5:00 a.m.,
SSW Pump 1-01 was placed in service and SSW Pump 1-02 was tagged out in
preparations for a scheduled Train B SSW outage. At 6:55 a.m., SSW Pump 1-01
tripped on an overcurrent condition sensed on the Phase C motor lead. At the time of
the trip, Unit 1 was in "no mode" (reactor fuel was in the spent fuel pool for 1RF11) and
Unit 2 was at 100 percent power with both SSW trains in service. In response to the trip
of SSW Pump 1-01, the licensee restored SSW Pump 1-02 to service at 10:35 a.m.
The degraded condition on Phase C motor lead was corrected by replacing the entire
cable.
Analysis. The failure to take effective corrective actions for the degraded motor lead
was the performance deficiency. The inspectors consider this finding to be more than
minor because there are several examples in Appendix E of Manual Chapter 0612
where an issue is more than minor because the system is returned to service with a
degraded condition. Although Unit 1 was in an outage, Appendix G of Manual
Chapter 0609 was not applicable, as there was no requirement for Unit 1 to have an
operable SSW system. However, Unit 2 was required to have an operable Unit 1
SSW pump for Mode 1 by Technical Specification 3.7.8. A Phase 1 significance
determination in accordance with Appendix A was performed. Since this finding did not
affect the initiating events cornerstone for Unit 2, it only affected one cornerstone, the
mitigating systems cornerstone. The finding was determined to have a very low safety
significance (Green) because it did not represent a loss of system safety function, was
not an actual loss of safety function for a single Unit 2 train, did not involve equipment or
function specifically designed to mitigate a seismic, flooding, or severe weather initiating
event, and did not involve the total loss of any safety function that contributed to external
event initiated sequences. This finding has a problem identification and resolution
crosscutting aspect because it was caused by lack of effective corrective actions.
-29- Enclosure
Enforcement. Criterion XVI of Appendix B to 10 CFR Part 50 requires that measures
shall be established to assure that conditions adverse to quality, such as failures,
malfunctions, deficiencies, deviations, defective material and equipment and
nonconformances are promptly identified and corrected. Contrary to the above, on
October 20, 2005, SSW Pump 1-01 was returned to service after identification of a
deficiency in the Phase C motor lead without implementing effective corrective actions.
Because this violation was of very low safety significance and was entered into the
corrective action program as SMF-2005-004220, it is being treated as an NCV,
consistent with Section VI.A.1 of the NRC Enforcement Policy:
NCV 05000445/2005005-04, Trip of Station Service Water Pump Due to Degraded
Motor Lead.
4OA5 Other Activities
.1 Pressurizer Penetration Nozzles and Steam Space Piping Connections in U.S.
Pressurized Water Reactors (NRC Bulletin 2004-01) (Temporary Instruction 2515/160)
This Temporary Instruction provided the guidelines to verify compliance with licensee
commitments to NRC Bulletin 2004-01, Inspection of Alloy 82/182/600 Materials Used
in the Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at
Pressurized-Water Reactors. The inspector used the inspection requirements for the
bare metal visual examination to conduct this inspection on the CPSES Unit 1
pressurizer and steam space penetrations during the 1RF11 refueling outage, Fall 2005.
a. Inspection Scope
The inspector performed this performance-based evaluation and assessment to ensure
that the NRC had an independent review of the condition of the pressurizer and steam
space piping alloy 82/182 dissimilar metal welds. The inspector assessed the
effectiveness of the licensee examinations of the pressurizer vessel and penetrations.
Specifically, the inspector:
- met with licensee representatives to review and discuss inspection plans and
contingencies
- attended pre-job briefs
- directly inspected and assessed the condition of the pressurizer and the
associated piping weld penetrations
- assessed the physical difficulties in performing the inspection, which included
any debris, dirt, boron, and other viewing impediments
- interviewed the licensee inspectors
-30- Enclosure
- assessed the licensees ability to distinguish small boron deposits located at the
weld locations
- verified that the licensee documented deficiencies in their corrective action
program
- assessed the overall effectiveness of the process used to perform the bare metal
visual inspection
The inspector also reviewed the following documents during this inspection:
- NRC Bulletin 2004-01, Inspection of Alloy 82/182/600 Materials Used in the
Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at
Pressurized-Water Reactors, dated May 28, 2004
- NRC Information Notice 2004-11, Cracking in Pressurizer Safety and Relief
Nozzles and in Surge Line Nozzle, dated May 6, 2004
- Comanche Peak Steam Electric Station 60-Day Response to NRC
Bulletin 2004-01, Inspection of Alloy 82/182/600 Materials Used in the
Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at
Pressurized Water Reactors, TXX-04140, dated July 27, 2004
- Comanche Peak Steam Electric Station Response to NRCs Request for
Additional Information Request regarding the response to NRC Bulletin 2004-01,
Inspection of Alloy 82/182/600 Materials Used in the Fabrication of Pressurizer
Penetrations and Steam Space Piping Connections at Pressurized Water
Reactors, TXX-05056 , dated March 7, 2005
- CPSES Station Administration Manual Procedure STA-737, Boric Acid
Corrosion Detection and Evaluation, Revision 3
- NRC Inspection Manual, Inspection Procedure 57050, Visual Testing
Examination, issued March 9, 1999
b. Findings
No findings of significance were identified. The inspector concluded that the licensee
met the applicable commitments in that they performed a 100 percent bare metal visual
inspection of the circumference over the axial length of the Alloy 82/182 identified welds
for the Unit 1 pressurizer. These inspections were performed by a VT-2 Level II certified
examiner. The inspector has provided the following details of the inspection as required
by Temporary Instruction 2515/160, Pressurizer Penetration Nozzles and Steam Space
Piping Connections in U.S. Pressurized Water Reactors (NRC Bulletin 2004-01), issued
October 6, 2004.
-31- Enclosure
1. Examination
The licensees examiner was certified in accordance with CPSES procedures to meet
the ASME Section XI for VT-2 Level II.
The examination was conducted in accordance with a CPSES examination plan, RCS
Pressure Boundary DM Weld Supplemental Visual Examination Plan, Revision 1,
approved on March 28, 2005. The examination plan provided: (1) responsibilities for the
examination process; (2) examiner qualification; (3) scope of welds to be examined, a
description of the basic bare metal inspection technique and the expectation of
100 percent inspection coverage; (4) acceptance criteria for the inspection; (5) types of
indications that shall be further investigated; (6) criteria for cleaning the examined area;
and (7) sufficient guidance to satisfy licensee commitments for the inspection. The
inspectors concluded that the inspection plan, combined with training, have provided
adequate guidance for the licensee examiner to identify, disposition, and resolve
deficiencies.
Due to the proximity of the bare metal visual examination, VT-2 Level II qualified
personnel, and the accessability of the specified Alloy 82/182 welds, the inspectors
determined that RCS leakage described in NRC Bulletin 2004-01 would be identified, if
present.
2. Physical condition penetration nozzles and steam space piping
In general, the condition of the weld areas examined were in excellent condition.
Access to the welds only required the removal of a relatively small amount of mirror
insulation, radiation levels were acceptable, and the welds themselves were very new
looking with no residue of previous spills or in-service inspections. Only on the downhill
side of the safety and pressurizer power operated relief valve welds was it necessary to
use a mirror (due to limited space below the piping). All other examinations were
performed with the naked eye.
3. Visual inspection protocol
Direct visual inspection and the use of a mirror were the inspection techniques used by
qualified examination personnel.
4. Inspection coverage
The inspectors observed that the licensee completed a 100 percent, 360 degree bare
metal inspection of the pressurizer penetration nozzles and steam space piping
connections.
5. Capability to identify and characterize small boric acid deposits
-32- Enclosure
The inspectors determined that the direct visual inspections, coupled with mirror
assisted visual inspections were capable of detecting, identifying and characterizing
small boric acid deposits, if present, as described in NRC Bulletin 2004-01. This fact
was determined via direct inspection during the licensee inspection of the pressurizer
and associated steam space piping connections.
6. Identified deficiencies that required repair
No deficiencies were identified.
7. Impediments to effective examinations
There were no impediments that adversely affected effective bare metal visual
examinations. In all examination cases, mirror insulation was required to be removed.
The examination of the pressurizer safety and power operated relief valve line welds
was supplemented by a mirror to allow examination of the downhill side of the welds.
The dose rates were acceptable, and the inspectors received approximately 50 mRem
to complete the in-plant portion of the temporary instruction.
8. Techniques used for augmented inspections
Augmented inspections were not required.
9. Appropriateness of follow-on examinations
Follow-on examinations were not required.
.2 (Closed) URI 05000446/2005009-01: Inoperability of Emergency Power to a Safety Bus
Introduction. A Green self-revealing noncited violation of Technical Specification 3.8.1
was identified because both the alternate offsite AC power source and the EDG did not
supply power to a 6.9 kV safeguards bus within the time assumed in the accident
analysis.
Description. Technical Specification 3.8.1 requires two operable qualified circuits
between the offsite transmission network and the onsite Class 1E AC electrical power
distribution system; and two operable diesel generators (DGs) capable of supplying the
onsite Class 1E power distribution subsystem. On October 19, 2004, an unplanned loss
of the preferred offsite power caused the Unit 2, Train B, 6.9 kV safeguards bus to
deenergize. A degraded Agastat relay delayed the normal power supply breaker from
opening for 30 seconds. Both the EDG and the alternate power supply were prevented
from powering the bus due to a breaker interlock with the normal supply. This delay
rendered both the EDG and alternate offsite AC power supplies inoperable. The
30 second delay in providing power to the safeguards bus would have resulted in the
station not meeting the 10 CFR Part 50, Appendix K, Emergency Core Cooling System
Evaluation Models Acceptance Criteria, for that equipment train.
-33- Enclosure
The licensee had a previous opportunity to correct the degraded Agastat relay issues.
On October 7, 2002, EDG 1-02 unexpectedly started due to a degraded Agastat relay.
The licensee concluded that the failure could have been caused by aging and formed a
corrective action plan to replace all safety-related Agastat relays that have been in
service for greater than the licensee established 12 year lifetime.
EVAL-2003-001440-01-01 stated that the main effect of aging on these relays was an
increase in setpoint drift. The licensee issued SMF-2004-003528 to track the root cause
and corrective actions associated with the faulty Agastat relays. Also, the NRC
previously identified that Agastat relays used in the 6.9 kV bus transfer circuitry were
exhibiting setpoint drift (SMF-2002-001504 and Inspection Report 05000445/2003006;
05000446/2003006). The relay that failed in October 2004 was 16 years old.
Analysis. The licensees failure to identify the cause and implement corrective actions to
prevent repetitive failures of safety-related Agastat relays was a performance deficiency.
The violation was more than minor because it impacted the Mitigating Systems
Cornerstone objective of availability, reliability, and capability of systems that respond to
initiating events. Using Inspection Manual Chapter 0609, Appendix A, Determining the
Significance of Reactor Inspection Findings for At-Power Situations, the finding was
determined to be of very low safety significance because the likelihood of a medium or
large break loss of coolant accident coincident with a loss of offsite power, which are the
only conditions wherein the deficiency would cause a non-negligible change in the
baseline risk profile, is less than or equal to 1E-6 per year. Therefore the change in
core damage frequency will be less than 1E-6 per year. The violation has a problem
identification and resolution crosscutting aspect because the licensee had previously
identified that aged Agastat relays can cause these types of problems but had failed to
take effective corrective actions in a timely manner. The licensee captured the issue in
their corrective action program as SMF-2004-003528.
Enforcement. Technical Specification 3.8.1 required the licensee to restore either the
alternate offsite transmission source or the EDG to the onsite Class 1E AC electrical
distribution system within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to the above, neither the alternate offsite
transmission source nor the EDG were capable of supplying the Class 1E AC electrical
distribution within the response time assumed in the accident analysis. This condition
existed for an extended duration, in excess of the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> TS limiting condition for
operation. Because this issue is of very low safety significance and has been entered
into the corrective action program as SMF-2004-003528, this violation is being treated
as a NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000446/2005005-05, Inoperability of Emergency Power to a Safety Bus Due to
Degraded Relay.
4OA6 Meetings, Including Exit
Exit Meeting Summary
The inspectors presented the results of the inservice inspection to Mr. M. Lucas, Vice
President of Nuclear Engineering, and other members of licensee management on
-34- Enclosure
October 21, 2005. Licensee management acknowledged the inspection findings. The
licensee confirmed that any proprietary information reviewed by the inspectors was not
retained by the inspectors.
On December 15, 2005, the inspector debriefed the preliminary results of the
emergency preparedness inspection to Mr. M. Blevins, Senior Vice President and Chief
Nuclear Officer, and other members of his staff who acknowledged the findings. The
inspector confirmed that proprietary information was not provided or examined during
the inspection. After additional information was provided by the licensee on January 11,
2006, the inspector presented the inspection results to Mr.R. Flores, Vice President,
Nuclear Operations, and other members of his staff who acknowledged the findings.
On January 31, 2006, Mr. N. O'Keefe presented the inspection results of the URI in
regards to Agastat relays to Mr. T. Hope and D. Snow of your staff, who acknowledged
the finding, by teleconference.
The inspector presented the resident inspection results to Mr. R. Flores, Vice President,
Operations, and other members of licensee management on January 12, 2006. The
inspectors confirmed that proprietary information was not provided or examined during
the inspection.
ATTACHMENT: SUPPLEMENTAL INFORMATION
-35- Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
O. Bhatty, Inservice Test Engineer
M. Blevins, Senior Vice President and Chief Nuclear Officer
D. Bozeman, Manager, Emergency Planning
S. Bradley, Supervisor, Health Physics, Radiation Protection & Safety Services
R. Calder, Executive Assistant
T. Clouser, Manager, Shift Operations
J. Curtis, Radiation Protection Manager, Radiation and Industrial Safety
D. Ellis, Level III Qualified Data Analyst
S. Ellis, Director, Nuclear Oversight
R. Flores, Vice President, Nuclear Operations
T. Hope, Manager, Regulatory Performance
R. Kidwell, Licensing Engineer
M. Lucas, Vice President Nuclear Engineering
F. Madden, Director, Regulatory Affairs
J. Meyer, Technical Support Manager
P. Passalugo, Inservice Inspection Program Coordinator
P. Polefrone, Plant Manger
V. Polizzi, Steam Generator Programs Engineer
S. Sewell, Nuclear Training Manager
J. Skelton, System Engineer
R. Smith, Director, Operations
S. Smith, Director, System Engineering
C. Tran, Engineering Programs Manager
D. Wilder, Radiation and Industrial Safety Manager
I. Witt, Boric Acid Program Coordinator
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000445;05000446/2005005-02, URI Notification Form Accuracy Requires Additional
Guidance (Section 40A1)
Opened and Closed
05000445/2005005-01 NCV Inadequate Corrective Actions for a Leaking Valve
with a Seal Weld which Subsequently Leaked
(Section 1R08.1)
A-1 Attachment
05000445/2005005-03 NCV Trip of Emergency Diesel Generator Due to
Lube Oil Check Valve Installed Backwards
(Section 4OA3.1)05000445/2005005-04 NCV Trip of Station Service Water Pump Due to
Degraded Motor Lead (Section 4OA3.2)05000446/2005005-05 NCV Inoperability of Emergency Power to a
Safety Bus Due to Degraded Relay
(Section 4OA5.2)
Closed
05000446/2005009-01 URI Inoperability of Emergency Power to a
Safety Bus (Section 4OA5.2)
Discussed
None
LIST OF DOCUMENTS REVIEWED
Section 1R08 Inservice Inspection Activities (71111.08)
Boric Acid Evaluation
Unit 1 Containment Boron Leaks 1RF11, draft report
Procedures
Number Title Revision
STA-737 Boric Acid Corrosion Detection and Evaluation 3
TX-ISI-8 VT-1 and VT-3 Visual Examination 56
TX-ISI-11 Liquid Penetrant Examination for Comanche Peak Steam 11
Electric Station
TX-ISI-302 Ultrasonic Examination of Austenitic Piping Welds 2
WLD-106 ASME/ANSI General Welding Requirements 2 with
Procedure
Change
Notice 4
A-2 Attachment
Nondestructive Examination Reports
Penetrant Report, 11PT06, dated October 14, 2005
Ultrasonic, Calibration Data Sheet, Weld TBX-1-4101, dated October 14, 2005
Visual Examination Data, Report No. 11VT14, dated October 11, 2005
Smart Forms
SMF-2004-000502 SMF-2004-002974 SMF-2005-004021
SMF-2004-001292 SMF-2005-000934 SMF-2005-004095
SMF-2004-001971 SMF-2005-001089 SMF-2005-004195
SMF-2004-002758 SMF-2005-001635 SMF-2005-004209
SMF-2004-002074 SMF-2005-002813 SMF-2005-004243
Work Orders
3-04-344421-01
Miscellaneous
Site specific training and testing results of various contracted eddy current testing personnel
Technical Specifications Sections 5.5.9, Amendment 112
TXU Power Comanche Peak Steam Electric Station Steam Generator Assessment for Unit #1
Cycle 11, September 2, 2004
Unit 1 - Second Interval ASME Section XI Inservice Inspection Program Plan, Revision 4
Unit 1 Steam Generator Eddy Current Analysis Guidelines 1RF11, Revision 0
Welding Procedure Specification CP-301, Revision 11
Westinghouse Letter MSR-TRC-1669, Use of Appendix H Qualified Techniques at Comanche
Peak Unit 1 11th RFO, dated September 9, 2005
Various Certifications of education, training, experience and visual acuity of contracted ECT
personnel
Section 1EP1 Exercise Evaluation (71114.01)
EP1
Procedures
1. EPP-109, Duties and Responsibilities of the Emergency Coordinator/Recovery
Manager, Revision 12
A-3 Attachment
2. EPP-116, Emergency Repair and Damage Control and Immediate Entries," Revision 6
3. EPP-204, Activation and Operation of the Technical Support Center," Revision 14
4. EPP-205, Activation and Operation of the Operations Support Center, Revision 11
5. EPP-206, Activation and Operation of the Emergency Operations Facility, Revision 14
6. EPP-303, Operation of the Computer Based Emergency Dose Assessment System,
Revision 12
7. EPP-305, Emergency Exposure Guidelines and Personnel Dosimetry, Revision 11
8. EPP-306, Use of Thyroid Blocking Agents, Revision 10
4OA1
Procedures
1. EPP-201, Assessment of Emergency Action Levels, Emergency Classification, and
Plan Activation, Revision 11
2. EPP-203, Notifications, Revision 14
3. EPP-304, Protective Action Recommendations, Revisions 17 and 18
Section 4OA5.2 , Inoperability of Emergency Power to a Safety Bus
Smart Forms: SMF-2002-003391 , SMF-2004-003528
A-4 Attachment
LIST OF ACRONYMS
ABN abnormal conditions procedure
ARV atmospheric relief valve
ASME American Society of Mechanical Engineers
ATWS anticipated transient without scram
CCW component cooling water
CFR Code of Federal Regulations
CPSES Comanche Peak Steam Electric Station
EDG emergency diesel generator
EVAL evaluation
HVAC heating, ventilation and air conditioning
IPO integrated plant operating procedure
MSM maintenance section-mechanical manual
NCV noncited violation
NRC Nuclear Regulatory Commission
OPT operations testing
PERC plant event review committee
QTE quick technical evaluation
SMF smart form
SOP system operating procedure
SSC structures, systems, or components
SSW station service water
STA station administrative procedure
TDAFW turbine driven auxiliary feed water
UPS uninterruptible power supply
WO work order
A-5 Attachment