ML070300881
| ML070300881 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 01/30/2007 |
| From: | Widmann M T Reactor Projects Region 2 Branch 6 |
| To: | Singer K W Tennessee Valley Authority |
| References | |
| IR-06-002, IR-06-005 | |
| Download: ML070300881 (51) | |
See also: IR 05000327/2006005
Text
January 30, 2007Tennessee Valley AuthorityATTN:Mr. Karl W. SingerChief Nuclear Officer and
Executive Vice President6A Lookout Place
1101 Market Street
Chattanooga, TN 37402-2801SUBJECT:SEQUOYAH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT05000327/2006005, 05000328/2006005 AND 07200034/2006002Dear Mr. Singer:
On December 31, 2006, the United States Nuclear Regulatory Commission (NRC) completedan inspection at your Sequoyah Nuclear Plant, Units 1 and 2. The enclosed integrated
inspection report documents the inspection results, which were discussed on January 3, 2007,
with Mr. R. Duet and other members of your staff.The inspection examined activities conducted under your licenses as they relate to safety andcompliance 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 one NRC-identified finding of very low safety significance. This findingwas determined to involve a violation of NRC requirements. Additionally, a licensee-identified
violation which was determined to be of very low safety significance is listed in this report.
However, because of their very low safety significance and because they are entered into your
corrective action program, the NRC is treating these findings as non-cited violations (NCVs)
consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this
report, you should provide a response within 30 days of the date of this inspection report, with
the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN.:
Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional
Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory
Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Sequoyah
Nuclear Plant.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public inspection in the
NRC Public Document Room or from the Publically Available Records (PARS) component of
2NRC's document system (ADAMS). ADAMS is accessible from the NRC Website athttp://www.nrc.gov/reading-rm/adams.html
(the Public Electronic Reading Room).Sincerely,/RA/Malcolm T. Widmann, ChiefReactor Projects Branch 6
Division of Reactor ProjectsDocket Nos.:50-327, 50-328, 72-034License Nos.:DPR-77, DPR-79Enclosure: Inspection Report 05000327/2006005 and 05000328/2006005 and07200034/2006002 w/Attachment: Supplemental Informationcc: w/encl: (See page 3)
____ML070300881
__OFFICERII:DRPRII:DRPRII:DRPRII:DRPRII:DRSRII:DRSRII:DRSSIGNATURELXG /RA/WTM /RA/JBB via emailMES via emailJXD /RA/FJE /RA/LFL /RA/NAMELGarnerMWidmannJBaptistMSpeckJDiaz-VelezFEhrhardtLLakeDATE01/30/200701/30/200701/30/200701/30/200701/30/200701/30/200701/30/2007
E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICERII:DRSRII:DRSRII:DRSRII:DRSRII:DRSRII:DRSRII:DRSSIGNATUREGWL /RA/DLM /RA/ECM /RA/BWM /RA/CRO forSDR /RA/CRO forNAMEGLaskaDMasPenarandaEMichelBMillerRMooreSRoseCSmithDATE01/30/200701/30/200701/30/200701/30/200701/30/200701/30/200701/30/2007
E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICERII:DRSSIGNATURECRS /RA/NAMECStancilDATE01/30/2007
E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO
3cc w/encls:Ashok S. Bhatnagar
Senior Vice President
Nuclear Operations
Tennessee Valley Authority
Electronic Mail DistributionPreston D. SwaffordSenior Vice President
Nuclear Support
Tennessee Valley Authority
Electronic Mail DistributionLarry S. Bryant, Vice PresidentNuclear Engineering &
Technical Services
Tennessee Valley Authority
Electronic Mail DistributionRandy DouetSite Vice President
Sequoyah Nuclear Plant
Electronic Mail DistributionGeneral CounselTennessee Valley Authority
Electronic Mail DistributionJohn C. Fornicola, General ManagerNuclear Assurance
Tennessee Valley Authority
Electronic Mail DistributionGlenn W. Morris, ManagerLicensing and Industry Affairs
Sequoyah Nuclear Plant
Tennessee Valley Authority
Electronic Mail DistributionBeth A. Wetzel, ManagerCorporate Nuclear Licensing and
Industry Affairs
Tennessee Valley Authority
4X Blue Ridge
1101 Market Street
Chattanooga, TN 37402-2801Robert H. Bryan, Jr., General ManagerLicensing and Industry Affairs
Sequoyah Nuclear Plant
Tennessee Valley Authority
4X Blue Ridge
1101 Market Street
Chattanooga, TN 37402-2801David A. Kulisek, Plant ManagerSequoyah Nuclear Plant
Tennessee Valley Authority
Electronic Mail DistributionLawrence E. Nanney, DirectorTN Dept. of Environment & Conservation
Division of Radiological Health
Electronic Mail DistributionCounty MayorHamilton County Courthouse
Chattanooga, TN 37402-2801Ann Harris341 Swing Loop
Rockwood, TN 37854
James H. Bassham, DirectorTennessee Emergency Management
Agency
Electronic Mail DistributionDistribution w/encl: (See page 4)
4Letter to Karl W. Singer from Malcolm T. Widmann dated January 30, 2007SUBJECT:SEQUOYAH NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT05000327/2006005, 05000328/2006005 AND 07200034/2006002Distribution w/encl
- Bob Pascarelli, NRR
D. Pickett, NRR
C. Evans, RII
L. Slack, RII EICS
OE Mail
RIDSNRRDIRS
PUBLIC
TABLE OF CONTENTSSUMMARY OF FINDINGS....................................................2REPORT DETAILS..........................................................3
REACTOR SAFETY.........................................................31R01Adverse Weather Protection.......................................41R02Evaluations of Changes, Tests or Experiments.........................41R04Equipment Alignment.............................................41R05Fire Protection..................................................41R07Heat Sink Performance...........................................51R08Inservice Inspection (ISI) Activities...................................61R11Licensed Operator Requalification Program............................91R12Maintenance Effectiveness.......................................121R13Maintenance Risk Assessments and Emergent Work Control.............121R15Operability Evaluations..........................................131R17Permanent Plant Modifications.....................................151R19Post-Maintenance Testing........................................161R20Refueling and Other Outage Activities...............................171R22Surveillance Testing.............................................191EP6Drill Evaluation.................................................19RADIATION SAFETY.......................................................202OS1Access Control To Radiologically Significant Areas.....................20OTHER ACTIVITIES........................................................214OA2Identification & Resolution of Problems..............................214OA5Other Activities.................................................234OA6Management Meetings...........................................294OA7 Licensee Identified Violations......................................29ATTACHMENT: SUPPLEMENTARY INFORMATIONKey Points of Contact......................................................A-1
List of Items Opened, Closed, and Discussed....................................A-1List of Documents Reviewed.................................................A-3
List of Acronyms.........................................................A-14
EnclosureU. S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos:50-327, 50-328, 72-034License Nos:DPR-77, DPR-79
Report No:05000327/2006005 and 05000328/2006005 and07200034/2006002Licensee:Tennessee Valley Authority (TVA)
Facility:Sequoyah Nuclear Plant
Location:Sequoyah Access RoadSoddy-Daisy, TN 37379Dates:October 1, 2006 - December 31, 2006
Inspectors:J. Baptist, Acting Senior Resident InspectorJ. Diaz-Velez, Health Physicist (Section 2OS1)
F. Ehrhardt, Operations Engineer (Section 1R11.2)
L. Lake, Reactor Inspector (Section 1R08)
G. Laska, Senior Operations Examiner (Section 1R11.3)
D. Mas-Penaranda, Reactor Inspector (Sections 1R02, 1R17)
E. Michel, Reactor Inspector (Section 4OA5.3)
B. Miller, Reactor Inspector (Sections 1R08, 4OA5.2)
R. Moore, Senior Reactor Inspector (Section 4OA5.3)
S. Rose, Senior Operations Engineer (Section 1R11.3)
C. Smith Senior Reactor Inspector (Sections 1R02, 1R17)
M. Speck, Resident Inspector
C. Stancil, Resident Inspector (Section 1EP6)Approved by:M. Widmann, Chief Reactor Projects Branch 6
Division of Reactor Projects
EnclosureSUMMARY OF FINDINGSIR 05000327/2006005, IR 05000328/2006005; IR 07200034/2006002; 10/01/2006 -12/31/2006; Sequoyah Nuclear Plant, Units 1 & 2; Licensed Operator Requalification
Program.The report covered a three-month period of inspection by resident inspectors andannounced inspections by 10 regional inspectors and one resident inspector from
another site. One NRC-identified Green finding, which was also a non-cited violation,
was identified. The significance of most findings is indicated by their color (Green,
White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance
Determination Process" (SDP). Findings for which the SDP does not apply may be
Green or be assigned a severity level after NRC management review. The NRC's
program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.A.NRC-Identified and Self-Revealing FindingsCornerstone:Mitigating Systems
Green. The inspectors identified a Green, non-cited violation (NCV) of 10 CFR 55.53,"Conditions of Licenses" for failure to certify the qualifications and status of licensed
operators were current and valid prior to their resumption of license duties. Specific
aspects of the requalification program that were not valid included plant tours that were
not completed with another licensed operator and not completing all shift functions in
positions to which the individuals will be assigned. The licensee entered the finding into
the corrective action program as PER No.112004. The finding is greater than minor because it is associated with the human performanceattribute of the Mitigating Systems Cornerstone that affects the cornerstone objective of
ensuring the availability, reliability, and capability of operators to respond to initiating
events to prevent undesirable consequences that could pose a potential risk to
operations. The finding was evaluated using the Operator Requalification Human
Performance Significance Determination Process. Under this SDP, record deficienciescan be either minor or of very low safety significance (Green). This finding was
determined to be Green because it was related to the program for maintaining active
licenses and more than 20% of the records reviewed had deficiencies. (Section 1R11.3).B. Licensee-Identified ViolationsA violation of very low safety significance, which was identified by the licensee, wasreviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensee's corrective action program. This violation and corrective
action are listed in Section 4OA7.
EnclosureREPORT DETAILSSummary of Plant Status
- Unit 1 operated at or near 100% rated thermal power (RTP) for the duration of thereporting period.Unit 2 operated at or near 100% RTP until November 27, 2006 when it shut down for arefueling outage. Unit 2 achieved criticality on December 24, 2006, and reached 100%
RTP on December 29, 2006, where it remained for the duration of the reporting period.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather Protection a.Inspection ScopeThe inspectors reviewed design features and licensee preparations for protecting theessential raw cooling water (ERCW) intake structure and both Unit 1 and 2 refueling
water storage tanks (RWSTs) from extreme cold and freezing conditions. The
inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), and Technical
Specifications (TS), reviewed and observed implementation of licensee freeze protection
procedures, and walked down portions of the systems to assess the status of system
deficiencies and the system readiness for extreme cold weather. Inspectors performed
corrective action program keyword searches to verify deficiencies were being identified
at an appropriate level and that actions were taken to correct problems. Documents
reviewed are listed in the Attachment to this report. b.FindingsNo findings of significance were identified.1R02Evaluations of Changes, Tests or Experiments a.Inspection Scope
The inspectors reviewed selected samples of 10 CFR 50.59 evaluations to verify that
the licensee had appropriately considered the conditions under which changes to the
facility, Updated Final Safety Analysis Report (UFSAR), or procedures may be made,
and tests conducted, without prior NRC approval. The inspectors reviewed ten
evaluations completed for changes made by the licensee without prior NRC approval.
The inspectors also reviewed documents prepared in connection with the changes.
Documents reviewed included supporting analyses, the UFSAR, and drawings to verify
that the licensee had correctly concluded that the changes could be made without
obtaining a license amendment. The ten evaluations reviewed are listed in the
Attachment to this report.
4EnclosureAdditionally, the inspectors reviewed samples of changes for which the licensee haddetermined that evaluations were not required. The reviews were performed to verify
that the licensee's conclusions to "screen out" these changes were correct, and the
changes were made in compliance with the requirements of 10 CFR 50.59. The sixteen
"screened out" changes reviewed are listed in the Attachment to this report.The inspectors also reviewed selected problem evaluation reports (PERs) to verify thatplant problems were evaluated for root/apparent causes; extent of condition; and that
the developed corrective actions were adequate to ensure recurrence control of the
identified plant problem. b.FindingsNo findings of significance were identified.1R04Equipment Alignment a.Inspection ScopePartial System Walkdowns. The inspectors performed a partial walkdown of thefollowing three systems to verify the operability of redundant or diverse trains and
components when safety equipment was inoperable. The inspectors attempted to
identify any discrepancies that could impact the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
walked down control system components and verified that selected breakers, valves,
and support equipment were in the correct position to support system operation. The
inspectors also verified that the licensee had properly identified and resolved equipment
alignment problems that could cause initiating events or impact the capability of
mitigating systems or barriers and entered them into the corrective action program.
Documents reviewed are listed in the Attachment to this report.*Residual Heat Removal (RHR) Train 2B during maintenance on Train 2A*Emergency Diesels 1A, 1B, and 2A during diesel 2B Outage
- Unit 2 Spent Fuel Pool Cooling during full core offload b.FindingsNo findings of significance were identified.1R05Fire Protection a.Inspection ScopeThe inspectors conducted a tour of the eight areas listed below to assess the material
condition and operational status of fire protection features. The inspectors verified that
combustibles and ignition sources were controlled in accordance with the licensee's
administrative procedures, fire detection and suppression equipment was available for
use; that passive fire barriers were maintained in good material condition; and that
compensatory measures for out-of-service, degraded, or inoperable fire protection
5Enclosureequipment were implemented in accordance with the licensee's fire plan. Documentsreviewed are listed in the Attachment to this report.*Control Building Elevation 669 (Mechanical Equipment Room, 250-VDC Batteryand Battery Board Rooms)*Control Building Elevation 706 (Cable Spreading Room)
- Control Building Elevation 685 (Auxiliary Instrument Rooms)
- Auxiliary Building Elevation 690 (Corridor)
- Emergency Diesel Generator Building
- Control Building Elevation 732 (Mechanical Equipment Room and Relay Room)
- Auxiliary Building Elevation 714 (Corridor)
- Unit 2 Residual Heat Removal/Containment Spray Heat Exchanger RoomsThe inspectors observed the performance of the site fire brigade during unannounceddrills on March 29, 2006, and September 30, 23006, and reviewed the drill critique
report for an unannounced drill on October 3, 2006, to evaluate the readiness of the fire
brigade to fight fires and to assess the drill against the requirements of the Sequoyah
Nuclear Plant Fire Protection Report, Revision 17. The observed drills simulated fires at
the 480-volt Reactor Motor Operated Valve Board 1B1-B and the Motor-driven Auxiliary
Feedwater Pump 2A-A. The reviewed drill critique was for fire brigade response to a fire
alarm report from the Unit 1 RWST. Specifically, the inspectors reviewed the following
aspects of the drills: use of protective clothing, use of breathing apparatus, proper use
of fire hoses, control of the drill scenario, and recurrence of identified deficiencies. b.FindingsNo findings of significance were identified.1R07Heat Sink Performance a.Inspection ScopeThe inspectors observed performance and reviewed the results of the following activityto verify the heat exchanger's readiness and availability. Inspector's interviewed
maintenance and testing personnel and the system engineer, reviewed corrective action
program documents, previous heat exchanger flow rate data, and inspected the heat
exchanger internals for cleanliness. Inspectors also walked down the system while in
operation looking for evidence of leaks following system restoration. Documents
reviewed are listed in the Attachment to this report. * WO 06-777564-000, Open 2B Containment Spray Heat Exchanger for EddyCurrent Inspection b.FindingsNo findings of significance were identified.
6Enclosure1R08Inservice Inspection (ISI) Activities (71111.08).1Piping and Pressure Boundary Systems ISI a.Inspection ScopeFrom December 4 - December 8, 2006, the inspectors observed and reviewed thelicensee's implementation of their ISI program for monitoring degradation of the reactor
coolant system (RCS) boundary and other risk significant piping system boundaries for
Unit 2. The inspectors observed and reviewed a sample of American Society of
Mechanical Engineers (ASME),Section XI, Section III, and Risk Informed ISI required
examinations, in order of risk priority, as identified in Section 71111.08-03 of inspection
procedure 71111.08, "Inservice Inspection Activities" based upon the ISI activities
available for review during the onsite inspection period.The inspectors conducted an on-site review of nondestructive examination (NDE)activities to evaluate compliance with TSs and the applicable editions of ASME Section
V and Section XI to verify that indications and defects (if present) were appropriately
evaluated and dispositioned in accordance with the requirements of ASME Section XI
acceptance standards. The inspectors observed the following examinations:
Manual Ultrasonic Examination:
- 13SIF-142
Visual (VT3) examination of the following Hangers:
- 2-CVCH-004*2-CVCH-007
- 2-CVCH-010
- 2-CVCH-037Qualification and certification records for examiners, inspection equipment, andconsumables along with the applicable NDE procedures for the above ISI examination
activities were reviewed and compared to requirements stated in ASME Section V and
Section XI.The inspectors observed in-process welding activities for the following ASME pressureboundary locations. Inspectors reviewed quality records for welding procedures,
procedure qualification, welder qualification, and filler metal certification. The inspectors observed a sample of in-process weld-overlay activities for the followingPressurizer nozzles:*Pressurizer Spray Nozzle*Pressurizer Surge Nozzle
7Enclosure b.FindingsNo findings of significance were identified. .2Reactor Vessel Upper Head PenetrationsThe inspectors completed TI2515/150, Reactor Pressure Vessel Head and HeadPenetration Nozzles (NRC Order EA-03009) (Unit2), this outage. See Section 4OA5.2..3Boric Acid Corrosion Control (BACC) ISI a.Inspection ScopeThe inspectors reviewed the licensee's BACC activities to ensure implementation withcommitments made in response to NRC Generic Letter 88-05 "Boric Acid Corrosion of
Carbon Steel Reactor Pressure Boundary" and Bulletin 2002-01 "Reactor Pressure
Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity." The inspectors conducted an on-site record review as well as an independent walkdownof parts of the reactor building that are not normally accessible during at-power
operations to evaluate compliance with licensee BACC program requirements. In
particular, the inspectors assessed whether the visual examinations focused on
locations where boric acid leaks can cause degradation of safety significant components
and that degraded or non-conforming conditions were properly identified in the
licensee's corrective action program.The inspectors reviewed a sample of engineering evaluations completed for boric acidfound on reactor coolant system piping and components. The inspectors also reviewed
licensee corrective actions implemented for evidence of boric acid leakage to confirm
that they were consistent with requirements of Section XI of the ASME Code and 10 CFR 50 Appendix B Criterion XVI. b. FindingsNo findings of significance were identified..4Steam Generator ISI a.Inspection ScopeFrom December 11-15, 2006, the inspectors reviewed the Unit 2 Steam Generator (SG)tube eddy current testing (ECT) examination activities to ensure compliance with TSs,
applicable industry operating experience and technical guidance documents, and ASME
Code Section XI requirements.The inspectors reviewed licensee SG inspection activities to ensure that ECTinspections were conducted in accordance with the licensee's SG Program and
applicable industry standards. The inspectors reviewed the SG examination scope,
8EnclosureECT acquisition procedures, Examination Technique Specification Sheets (ETSS), ECTanalysis guidelines, the most recent SG degradation assessment and operational
assessment, and also the condition monitoring results as they became available. The
inspectors reviewed documentation to ensure that the ECT probes and equipment
configurations used were qualified to detect the expected types of SG tube degradation.
The inspectors ensured that all tubes evaluated in condition monitoring were
appropriately screened for in-situ testing. No tubes met the criteria for in-situ testing. In
addition, the inspectors ensured that the licensee had appropriately implemented the
NRC-approved Alternate Repair Criteria (ARC) applicable to tubes that experienced
outer diameter stress corrosion cracking (ODSCC) at tube support plates.The inspectors monitored the licensee's secondary side activities, which included aforeign object search and recovery (FOSAR) for loose parts, and sludge lancing. As
part of an industry commitment, the licensee was required to remove a tube from
service for destructive testing. The inspectors monitored this evolution to ensure there
was no damage to other tubes or other parts of the SG. b. FindingsNo findings of significance were identified..5 Identification and Resolution of Problems a.Inspection ScopeThe inspectors performed a review of piping system ISI related problems that wereidentified by the licensee and entered into the corrective action program. The inspectors
reviewed corrective action documents to confirm that the licensee had appropriately
described the scope of the problems. Additionally, the inspectors' review included
confirmation that the licensee had an appropriate threshold for identifying issues and
had implemented effective corrective actions. The inspectors evaluated the threshold
for identifying issues through interviews with licensee staff and review of licensee
actions to incorporate lessons learned from industry issues related to the ISI program.
The inspectors performed these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements. The corrective actiondocuments reviewed by the inspectors are listed in the Attachment to this report. b. FindingsNo findings of significance were identified.
9Enclosure1R11Licensed Operator Requalification Program.1Quarterly Inspection a.Inspection ScopeThe inspectors observed licensed operator requalification simulator testing on October24, 2006. The testing involved a failed impulse pressure transmitter failure followed by
loss of condenser vacuum and automatic turbine trip. The reactor failed to automatically
trip and resulted in an anticipated transient without scram (ATWS). The ATWS was
compounded by the inability to trip the reactor from the Main Control Room, auxiliary
feedwater control valves failed to operate automatically for Steam Generators Number 1
and 2, and the Turbine Driven Auxiliary Feedwater Pump (TDAFP) was unable to supply
feedwater, all of which required operator action. As plant conditions were being
stabilized, a pressurizer power operated relief valve (PORV) failed open and required
operators to shut its blocking valve. The inspectors observed crew performance in terms of communications; ability to taketimely and proper actions; prioritizing, interpreting and verifying alarms; correct use and
implementation of procedures, including the alarm response procedures and emergency
plan event classification; timely control board operation and manipulation, including highrisk operator actions; oversight and direction provided by shift manager, including the
ability to identify and implement appropriate TS actions; independent event classification
by the Shift Technical Advisor; and group dynamics involved in crew performance. The
inspectors also observed the examining staff's assessment of the crew's performance
and compared them to inspector observations. Documents reviewed are listed in the
Attachment to this report. b.FindingsNo findings of significance were identified..2Annual Review of Licensee Requalification Examination Results a.Inspection ScopeOn November 17, 2006, the licensee completed the comprehensive requalificationbiennial written examinations and annual operating tests required to be given to alllicensed operators by 10 CFR 55.59(a)(2). The inspectors performed an in-office review
of the overall pass/fail results of the written examinations, individual operating tests, and
the crew simulator operating tests. These results were compared to the thresholds
established in Manual Chapter 609 Appendix I, Operator Requalification Human
Performance Significance Determination Process. b.FindingsNo findings of significance were identified.
10Enclosure.3Licensed Operator Requalification Program - Biennial Review a.Inspection ScopeThe inspectors reviewed facility operating history and associated documents inpreparation for this inspection. While onsite the inspectors reviewed documentation,
interviewed licensee personnel, and observed the administration of operating tests and
written examinations associated with the licensee's operator requalification program.
Each of the activities performed by the inspectors was done to assess the effectiveness
of the licensee in implementing requalification requirements identified in 10 CFR 55,
"Operators' Licenses." The evaluations were also performed to determine if the licensee
effectively implemented operator requalification guidelines established in NUREG 1021,
"Operator Licensing Examination Standards for Power Reactors," and Inspection
Procedure 71111.11, "Licensed Operator Requalification Program." The inspectors also
evaluated the licensee's simulation facility for adequacy for use in operator licensing
examinations using ANSI/ANS-3.5-1985, "American National Standard for Nuclear
Power Plant Simulators for use in Operator Training and Examination." The inspectors
observed two crews during the performance of the operating tests. Documentation
reviewed included written examinations, job performance measures, simulator
scenarios, licensee procedures, on-shift records, licensed operator qualification records,
watchstanding and medical records, simulator modification request records and
performance test records, the feedback process, and remediation plans. Documents
reviewed during the inspection are listed in the Attachment to this report. b.FindingsIntroduction: A Green NCV was identified for failure to certify that the qualifications andstatus of licensed operators were current and valid prior to their resumption of license
duties. The applicable requirements of 10 CFR 55.53, "Conditions of Licenses" for
license reactivation were not met. Specific aspects of the requalification program that
were not valid included plant tours that were not completed with another licensed
operator and not completing all shift functions in the position to which the individual will
be assigned. Description: The inspectors identified problems with several aspects of the reactivationprocess for licensed operators who had been reactivated between October 1, 2004 and
September 30, 2006. The inspectors performed a detailed review for 5 of the 15
individuals who had licenses reactivated during this time period. The inspectors identified that complete tours of the plant were not being conducted inaccordance with OPDP-1 "Operations Department Procedure", Revision 6 and 10 CFR 55.53 requirements. Some individuals reactivating their licenses were performing the
required plant tours without being accompanied by another licensed individual. The
inspectors also identified that some individuals reactivating their licenses had
documented standing watch in non-TS positions, i.e., those positions that TSs do not
require a licensed operator to fill. 10 CFR 55.53, requires that an authorized
representative of the facility certify that individuals reactivating their license must
complete a minimum of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of shift functions in the position to which the individual
11Enclosurewill be assigned and under the direction of a reactor operator or senior reactor operatoras appropriate. The 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> shall also include a complete tour of the plant.The inspectors noted that the licensee performed a self assessment of the licensedoperator requalification program on September 11-26, 2006. The assessment identified
problems in several different areas related to operator license reactivation and
maintenance of active license process. Specifically, one licensed operator's reactivationdocuments could not be located, two licensed operators were returned to active status
without all required training completed, and one inactive licensed operator assumed
licensed duties without being reactivated. Analysis: The inspectors determined that the licensee's failure to properly certify andmaintain the reactivation records of licensed operators and the failure to perform plant
tours with another licensed operator and complete shift functions in the position to which
the individual will be assigned is a performance deficiency because the licensee must
satisfy the requirements of 10 CFR 55.53 for license reactivation.The finding is more than minor because it is associated with the human performance attribute of the Mitigating Systems Cornerstone and adversely affects the cornerstone
objective of ensuring the availability, reliability, and capability of operators to response to
initiating events to prevent undesirable consequences. The failure to properly reactivate
the licenses of operators could adversely impact their performance. The finding was
evaluated using the Operator Requalification Human Performance Significance
Determination Process. Under this SDP, record deficiencies can be either minor or of
very low safety significance (Green). This finding was determined to be Green because
it was related to the program for maintaining active licenses and more than 20% of the
records reviewed had deficiencies.Enforcement: 10 CFR 55.53.(f) "Conditions of Licenses" requires, in part, that anauthorized representative of the facility licensee shall certify that qualifications and
status of operator licensees are current and valid prior to the resumption of license
duties. Included in the certification required by 10 CRF 55.53 is that the individual
complete a minimum of 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of shift functions in the position to be assigned and
also complete a plant tour while accompanied by a licensed operator. Contrary to the
above, the licensee did not properly certify that qualifications and status were current
and valid prior to allowing operators to perform licensed duties. The failure to properly reactivate licensed operators was determined to be of very lowsafety significance (Green) and has been entered into the licensee's corrective action
program as PER No.112004. The finding is being treated as an NCV consistent with
Section VI.A of the NRC Enforcement Policy: NCV 05000327,328/2006005-01, Failure
to certify qualifications and status of licensed operators were current and valid in
accordance with 10CFR 55.53.
12Enclosure1R12Maintenance Effectiveness a.Inspection ScopeThe inspectors reviewed the following three maintenance activities to verify theeffectiveness of the activities in terms of: 1) appropriate work practices; 2) identifying
and addressing common cause failures; 3) scoping in accordance with 10 CFR 50.65
(b); 4) characterizing reliability issues for performance; 5) trending key parameters for
condition monitoring; 6) charging unavailability for performance; 7) classification in
accordance with 10 CFR 50.65(a)(1) or (a)(2); 8) appropriateness of performance
criteria for Systems, Structures, and Components (SSCs) and functions classified as
(a)(2); and 9) appropriateness of goals and corrective actions for SSCs and functions
classified as (a)(1). Documents reviewed are listed in the Attachment to this report. *PER 115421, B-B Main Control Room Ventilation *PER 115780, 2B Residual Heat Removal HX Outlet Valve 74-28 Failure
- PER 85481, Repeated Packing Leaks of Safety Injection (SI) Valve 2-FCV-63-156 b.FindingsNo findings of significance were identified.1R13Maintenance Risk Assessments and Emergent Work Control a.Inspection ScopeThe inspectors reviewed the following six activities to verify that the appropriate riskassessments were performed prior to removing equipment from service for
maintenance. The inspectors verified that risk assessments were performed as
required by 10 CFR 50.65 (a)(4), and were accurate and complete. When emergent
work was performed, the inspectors verified that the plant risk was promptly reassessed
and managed. The inspectors verified the appropriate use of the licensee's risk
assessment tool and risk categories in accordance with Procedure SPP-7.1, On-Line
Work Management, Revision 8, and Instruction 0-TI-DSM-000-007.1, Risk Assessment
Guidelines, Revision 8. Documents reviewed are listed in the Attachment to this report. *Unit 2 ECCS Train A Room Cooler Outage*Unplanned EDG 2B Inoperability
- 2-SI-OPS-082-26A, Loss of Offsite Power with SI - DG 2A-A Test, Revision 35
- ORAM Orange risk condition from Unit 2 midloop activities prior to vacuum refill
- Franklin 500KV line tripped resulting in Technical Specification 3.8.1.1 entry
- Unit 2 initial RCS level drain to partial draindown condition b.FindingsNo findings of significance were identified.
13Enclosure1R15Operability Evaluations a.Inspection ScopeFor the five operability evaluations described in the PERs listed below, the inspectorsevaluated the technical adequacy of the evaluations to ensure that TS operability was
properly justified and the subject component or system remained available, such that no
unrecognized increase in risk occurred. The inspectors reviewed the UFSAR to verify
that the system or component remained available to perform its intended function. In
addition, the inspectors reviewed compensatory measures implemented to verify that
the compensatory measures worked as stated and the measures were adequately
controlled. The inspectors also reviewed a sampling of PERs to verify that the licensee
was identifying and correcting any deficiencies associated with operability evaluations.
Documents reviewed are listed in the Attachment to this report.*PER 111814, Train 'A' MCR Air-Conditioning System Air Flow Greater ThanAcceptance Criteria*PERs 114769, 114941, Emergency Diesel Generator 2B Feeder Breaker Failedto Close When Required *PER 109326, ERCW Screen Wash Pump B-B Failed Pump Performance Test
- PER 115490, Charging Pump Discharge Manual Isolation Valve Appendix ROperability*PER 117113, Unit 1 Steam Generator Levels Exhibited Lowering Trend b.FindingsNo findings of significance were identified. An unresolved item (URI) is discussedbelow.Inability to Perform Actions Required by AOP-N.08, Appendix R Fire Safe ShutdownIntroduction: The inspectors identified an Unresolved Item (URI) for not promptlyidentifying and correcting problems associated with manual valve 2-62-527. These
problems resulted in operators not being able to comply with licensee procedure AOP-
N.08, Appendix R Fire Safe Shutdown due to manual valve 2-62-527 not being able to
be closed within the 13 minutes required.Description: On October 28, 2005, a procedure change to AOP-N.08, Appendix R FireSafe Shutdown, was implemented. This change incorporated updated guidance
provided by a Westinghouse technical bulletin (TB -04-022) concerning RCP seal
performance during Appendix R fires and a loss of all pump seal cooling. This change
reduced the time available to perform manual actions and restore RCP seal flow from 24
minutes to 13 minutes. In the event of an Appendix R fire resulting in a spurious safety
injection signal, plant procedures required that all RCS injection sources be stopped to
prevent filling the pressurizer solid. The vendor guidance stated that actions taken to
prevent this condition and restore RCP seal flow should be completed within 13 minutes
to prevent seal damage. The actions outlined by AOP-N.08 required an auxiliary unit
operator (AUO) to manipulate several valves in the appropriate Charging Pump room
14Enclosureand then a CCP restarted to restore seal flow. Specifically, the AUO was to open adedicated flow path to the RCP seals using manual valve 62-526 (A-train), or 62-534 (B-
train) and close the associated CCP manual discharge valve,62-527 (A-train) or 62-533
(B-train) to the CCP Injection Tank (CCPIT). To support the procedure change, these
manipulations were subjected to a manual action validation that consisted of a table top
review of the necessary steps. The licensee determined that the CCP manual
discharge valves to the CCPIT could be closed by an individual AUO in 5 minutes and
20 seconds.Prior to the procedure being approved, PER 91383 was written on October 24, 2005. The PER addressed concerns by at least one plant AUO that the manual actions
required by the change to procedure AOP-N.08 may not be able to be completed within
the time required. PER 91383 requested the need to further evaluate the time
necessary to perform the manual actions by actual valve manipulations, or whether
additional procedure changes were needed to provide more margin to the required time.
The corrective action planned was to perform a timed valve stroke of CCP discharge
valve 2-62-527 to validate procedural change assumptions. Work Order (WO) 06-
771729-000 was written to implement and track this action during an appropriate CCP
maintenance period. PER 91383 was closed as completed on February 24, 2006 based
on the WO being written. On November 9, 2006, during a self-assessment, the licensee
determined that the WO had not been completed and was not scheduled for
performance until January 22, 2007. PER 114455 was written to document the
incomplete corrective action. Upon review of PER 114455, the inspectors questioned
the licensee on the valve's history, the status of corrective actions, and whether a valid
safety concern existed if the valve could not be operated within the prescribed time.
Prior to resolution by the licensee, on November 27, 2006, during Unit 2 refueling
outage activities, operators closed valve 2-62-527 to support maintenance. The
operators reported that the valve was very difficult to operate and required
approximately 30 minutes for two AUOs to shut the valve. This observation was
documented in in PER 115490 and supported the initial concern expressed in PER
91383. This information prompted the license to evaluate the consequences of the additionaltime needed to operate valve 2-62-527 with plant Appendix R procedures. Functional
Evaluation (FE) 41722 was drafted and the licensee determined that RCP seal
degradation would not occur if RCP seal flow was restored with a CCP prior to
completing of the Appendix R Fire safe shutdown manual actions The licensee also
evaluated whether the same problems were likely for other Appendix R manual valves. .
The licensee drafted a document to support the determination that other valves in both
units could be operated in adequate time in the event of an Appendix R fire.
Analysis: The inspectors determined that the delay in implementing the WO resulted innot promptly identifying and correcting problems with manual valve 2-62-527 resulting in
operators not being able to comply with procedure AOP-N.08, Appendix R Fire Safe
Shutdown. The corrective action for PER 91383 was closed to a WO and rescheduled
several times in the work control process with a performance date of January 22, 2007.
The inspectors referenced Inspection Manual Chapter (IMC) 0612 and determined the
finding is more than minor because if left uncorrected, the licensee would not be able to
15Enclosurecomply with AOP-N.08. The finding is associated with the mitigating systemcornerstone and could be reasonably viewed as affecting the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. This finding is unresolved pending the
review of supporting documentation and completion of the significance determination. Enforcement: Pending additional information involving the circumstances surroundingthe event, its extent of condition and completion of the significance determination, this
finding is identified as URI 05000328/2006005-02, Inability to Perform Required Actions
of AOP-N.08, Appendix R Fire Safe Shutdown.1R17Permanent Plant Modifications a.Inspection ScopeThe inspectors performed independent design reviews of six plant modifications in theInitiating Events, Mitigating Systems, and Barrier Integrity cornerstone areas, to verify
that the plant modifications did not have any adverse effects on system availability,
reliability, and functional capability. Documents reviewed included procedures,
engineering calculations, modification design and implementation packages, work
orders, Condition Reports (CRs), applicable sections of the UFSAR, TSs, and design
basis information. The plant modifications and the associated attributes reviewed are as
follows: DCN D22050, Pressurizer Relief Tank Level Transmitter Removed (Barrier Integrity)*Control Signal
- Energy Needs
- Process Medium
- Update of Licensee DocumentsDCN D21781, Change Steam Generator Narrow Range Level Transmitter Scaling(Mitigating System)
- Control Signal
- Energy Needs
- Process Medium
- Update of Licensee Documents
- OperationsDCN D21911, Replace Containment Isolation Valve 2-FCV-030-0014(Barrier Integrity)*Pressure Boundary
- Structural
- Process Medium
- Update of Licensee Documents
- Materials/Replacement ComponentsDCN 21900, Replace Unit 1B Main Bank Transformer and Associated Fire ProtectionRing Header, Revision A.(Initiating Event)
- Energy Needs
- Control Signals
- Post-Installation Testing
16Enclosure*Update of Licensee Documents*Functional Testing Adequacy and ResultsDCN D21971, Replace Cable PP351A for D/G 1A-A, Revision A. (Mitigating Systems)*Materials/ Replacement
- Failure Modes
- Post-Installation Testing
- Update of Licensee Documents
- Functional Testing Adequacy and ResultsDCN D21827, Revise Setting on Raw Cooling Water Pump Breaker, Revision A.*Control Signals
- Response Time
- Post-Insulation Testing
- Update of Licensee Documents
- Functional Testing Adequacy and ResultsThe inspectors also performed field inspections of selected plant modifications to verifythat the as-built installation complied with design requirements delineated in approved
design documents. Additionally, the inspectors reviewed selected PERs to verify that
plant problems were evaluated for root/apparent causes, extent of condition, and that
the developed corrective actions were adequate to ensure recurrence control of the
identified plant problem. b.FindingsNo findings of significance were identified.1R19Post-Maintenance Testing a.Inspection ScopeThe inspectors reviewed the five post-maintenance tests listed below to verify thatprocedures and test activities ensured system operability and functional capability. The
inspectors reviewed the licensee's test procedure to verify that the procedure
adequately tested the safety function(s) that may have been affected by the
maintenance activity, that the acceptance criteria in the procedure were consistent with
information in the applicable licensing basis and/or design basis documents, and that
the procedure had been properly reviewed and approved. The inspectors also
witnessed the test or reviewed the test data, to verify that test results adequately
demonstrated restoration of the affected safety function(s). Documents reviewed are
listed in the Attachment to this report.*WO 05-782379-000, Breaker Changeout for Motor-driven Auxiliary Feedwater(AFW) Pump 2B*2-SI-OPS-000-009.0, Actuation of Emergency Core Cooling Systems (ECCS)and Boron Injection Flowpath Valves Via SI Signal, Revision 1*WO 05-777912-001, Repack SI system Hot Leg Injection Valve, 2-FCV-63-156
17Enclosure*WO 06-780773-000, Calibrate FCV and Limit Switches on 2-FCV-074-28 *2-SI-SLT-088-156.0, Containment Integrated Leak Rate Test, Revision 2 b.FindingsNo findings of significance were identified.1R20Refueling and Other Outage Activities a.Inspection ScopeFor the Unit 2 refueling outage that began on November 27, 2006, the inspectorsevaluated licensee activities to verify that the licensee considered risk in developing
outage schedules, followed risk reduction methods developed to control plant
configuration, developed mitigation strategies for the loss of key safety functions, and
adhered to operating license and TS requirements that ensure defense-in-depth. The
inspectors also walked down portions of Unit 2 not normally accessible during at-power
operations to verify that safety-related and risk-significant SSCs were maintained in an
operable condition. Specifically, between November 27, 2006, and December 26, 2006,
the inspectors performed inspections and reviews of the following outage activities.
Documents reviewed are listed in the Attachment to this report.*Outage Plan. The inspectors reviewed the outage safety plan and contingencyplans to confirm that the licensee had appropriately considered risk, industry
experience, and previous site-specific problems in developing and implementing
a plan that assured maintenance of defense-in-depth.*Reactor Shutdown. The inspectors observed the shutdown in the control roomfrom the time the reactor was tripped until operators placed it on the RHR
system for decay heat removal to verify that TS cooldown restrictions were
followed. The inspectors also toured the lower containment as soon as
practicable after reactor shutdown to observe the general condition of the RCS
and emergency core cooling system components and to look for indications of
previously unidentified leakage inside the polar crane wall.*Licensee Control of Outage Activities. On a daily basis, the inspectors attendedthe licensee outage turnover meeting, reviewed PERs, and reviewed the
defense-in-depth status sheets to verify that status control was commensurate
with the outage safety plan and in compliance with the applicable TS when
taking equipment out-of-service. The inspectors further toured the main control
room and areas of the plant daily to ensure that the following key safety
functions were maintained in accordance with the outage safety plan and TS:
electrical power, decay heat removal, spent fuel cooling, inventory control,
reactivity control, and containment closure. The inspectors also observed a
tagout of the containment spray heat exchanger to verify that the equipment was
appropriately configured to safely support the work or testing. To ensure that
RCS level instrumentation was properly installed and configured to give accurate
information, the inspectors reviewed the installation of the Mansell level
18Enclosuremonitoring system. Specifically, the inspectors discussed the system withengineering, walked it down to verify that it was installed in accordance with
procedures and adequately protected from inadvertent damage, verified that
Mansell indication properly overlapped with pressurizer level instruments during
pressurizer draindown, verified that operators properly set level alarms to
procedurally required setpoints, and verified that the system consistently tracked
while lowering RCS level to reduced inventory conditions. The inspectors also
observed operators compare the Mansell indications with locally-installed
ultrasonic level indicators during entry into mid-loop conditions.*Refueling Activities. The inspectors observed fuel movement at the spent fuelpool and at the refueling cavity in order to verify compliance with TS and that
each assembly was properly tracked from core offload to core reload. In order to
verify proper licensee control of foreign material, the inspectors verified that
personnel were properly checked before entering any foreign material exclusion
(FME) areas, reviewed FME procedures, and verified that the licensee followed
the procedures. To ensure that fuel assemblies were loaded in the core
locations specified by the design, the inspectors independently reviewed the
recording of the licensee's final core verification.*Reduced Inventory and Mid-Loop Conditions. Prior to the outage, the inspectorsreviewed the licensee's commitments to Generic 88-17, "Loss of Decay Heat
Removal. Before entering reduced inventory conditions the inspectors verified
that these commitments were in place, that plant configuration was in
accordance with those commitments, and that distractions from unexpected
conditions or emergent work did not affect operator ability to maintain the
required reactor vessel level. While in mid-loop conditions, the inspectors
verified that licensee procedures for closing the containment upon a loss of
decay heat removal were in effect, that operators were aware of how to
implement the procedures, and that other personnel were available to close
containment penetrations if needed.*Heatup and Startup Activities. The inspectors toured the containment prior toreactor startup to verify that debris that could affect the performance of the
containment sump had not been left in the containment. The inspectors
reviewed the licensee's mode change checklists to verify that appropriate
prerequisites were met prior to changing TS modes. To verify RCS integrity and
containment integrity, the inspectors further reviewed the licensee's RCS
leakage calculations and containment isolation valve lineups. In order to verify
that core operating limit parameters were consistent with core design, the
inspectors also reviewed low power physics testing results and the Core
Operating Limits Report. b.FindingsNo findings of significance were identified.
19Enclosure1R22Surveillance Testing a.Inspection ScopeFor the seven surveillance tests identified below, by witnessing testing and/or reviewingthe test data, the inspectors verified that the SSCs involved in these tests satisfied the
requirements described in the TS surveillance requirements, the UFSAR, applicable licensee procedures, and that the tests demonstrated that the SSCs were capable of performing their intended safety functions. Documents reviewed are listed in the
Attachment to this report. Those tests included the following:*1-SI-MIN-061-108.0, Ice Condenser Intermediate Deck Door Weekly Inspection,Revision 2*2-SI-ICC-090-106.0, Channel Calibration of Containment Building LowerCompartment Air Monitor 2-R-90-106, Revision 9****0-SI-SXV-001-859.0, Testing and Setting of Main Steam Safety Valves, Revision 9
- 2-SI-OPS-082-026.A, Loss of Offsite Power with SI - DG 2A-A Test, Revision 35
- 0-SI-MIN-061-109.0, Ice Condenser Intermediate and Lower Inlet Doors andVent Curtains, Revision 4**2-SI-OPS-003-118.0 AFW pump and Valve Auto Actuation, Revision 18
- 2-SI-SXP-003-003-202.S, Turbine Driven Auxiliary Feedwater Pump 2A-SComprehensive Performance Test, Revision 4** *This procedure included an outage ice condenser system surveillance**This procedure included inservice testing requirements
- This procedure included a RCS leakage detection surveillance b.FindingsNo findings of significance were identified.
Cornerstone: Emergency Preparedness1EP6Drill Evaluation a.Inspection ScopeResident inspectors evaluated the conduct of a routine licensee emergency drill onOctober 3, 2006, to identify any weaknesses and deficiencies in classification,
notification, and protective action recommendation (PARs) development activities. The
inspectors observed emergency response operations in the simulated control room to
verify that event classification and notifications were done in accordance with EPIP-1,
Emergency Plan Classification Matrix, Revision 38. The inspectors also attended the
licensee critique of the drill to compare any inspector-observed weakness with those
identified by the licensee in order to verify whether the licensee was properly identifying
failures. Documents reviewed are listed in the Attachment to this report.
20Enclosure b.FindingsNo findings of significance were identified.2.RADIATION SAFETYCornerstone: Occupational Radiation Safety (OS)2OS1Access Control To Radiologically Significant Areas a.Inspection Scope
Access Control Licensee program activities for monitoring workers and controllingaccess to radiologically significant areas and tasks were inspected. The inspector
evaluated procedural guidance; directly observed implementation of administrative and
established physical controls; assessed worker exposures to radiation and radioactive
material; and appraised radiation worker and technician knowledge of, and proficiencyin, the implementation of Radiation Protection (RP) program activities.During the inspection, radiological controls for ongoing refueling activities for Unit 2 wereobserved and discussed. Reviewed tasks included steam generator non-destructive
testing, containment sump modifications, and refueling activities. In addition, licensee
controls for selected tasks scheduled and on-going during the current refueling outage
were assessed. The evaluations included, as applicable, Radiation Work Permit (RWP)
details; use and placement of dosimetry and air sampling equipment; electronic
dosimeter set-points, and monitoring and assessment of worker dose from direct
radiation and airborne radioactivity source terms. Effectiveness of established controls
was assessed against area radiation and contamination survey results, and
occupational doses received. Physical and administrative controls and their
implementation for locked high radiation areas (LHRAs) and very high radiation areaswere evaluated through discussions with cognizant licensee representatives, direct field
observations, and record reviews.Occupational workers' adherence to selected radiation work permits (RWPs) and HealthPhysics Technician proficiency in providing job coverage were evaluated through direct
observations of staff performance during job coverage and routine surveillance
activities, review of selected exposure records, and interviews with cognizant licensee
staff. Radiological postings and physical controls for access to designated high
radiation (HRA) and LHRA locations within the Unit 2 Containment, Auxiliary Building,
and Refuel Floor areas were evaluated during facility tours. In addition, the inspectors
independently measured radiation dose rates and evaluated established posting and
access controls for selected Auxiliary Building locations. Occupational exposures
associated with direct radiation and potential radioactive material intakes for were
reviewed and discussed with cognizant licensee representatives.RP program activities were evaluated against 10 CFR 19.12; 10 CFR 20, Subparts B, C,F, G, H, and J; UFSAR details in Section 12, RP; TSs Section 6.11, High Radiation
Area; and approved licensee procedures. Licensee procedures, guidance documents,
21Enclosurerecords, and data reviewed within this inspection area are listed in Section 2OS1 of theAttachment to this report.Problem Identification and Resolution Licensee Corrective Action Program documentsassociated with access control to radiologically significant areas were reviewed and
assessed. The inspectors evaluated the licensee's ability to identify, characterize,
prioritize, and resolve the identified issues in accordance with Standard Programs and
Processes procedure SPP-3.1, Corrective Action Program. Licensee self-assessments
and PER documents related to access control that were reviewed and evaluated in
detail during inspection of this program area are identified in Section 2OS1 of the
Attachment to this report.The inspector completed 21 of the required 21 samples for Inspection Procedure (IP)71121.01. All samples have now been completed for this IP. b.FindingsNo findings of significance were identified.4.OTHER ACTIVITIES
4OA2Identification and Resolution of Problems.1Daily Review
As required by Inspection Procedure 71152, Identification and Resolution of Problems,and in order to help identify repetitive equipment failures or specific human performance
issues for follow-up, the inspectors performed a daily screening of items entered into the
licensee's corrective action program. This was accomplished by reviewing the
description of each new PER and attending daily management review committee
meetings..2Semi-Annual Trend Review
a.Inspection ScopeAs required by Inspection Procedure 71152, the inspectors performed a review of thelicensee's corrective action program and associated documents to identify trends that
could indicate the existence of a more significant safety issue. The inspectors' review
was focused on procedure quality and compliance issues, but also included licensee
trending efforts and licensee human performance results. The inspectors' review
nominally considered the six-month period of July 2006 through December 2006,
although some examples expanded beyond those dates when the scope of the trend
warranted. Specifically, the inspectors consolidated the results of daily inspector screeningdiscussed in Section 4OA2.1 into a log, reviewed the log, and compared it to licensee
integrated quarterly trend reports for the period from July 2006 through September 2006
22Enclosurein order to determine the existence of any adverse trends that the licensee may nothave previously identified. b.Assessment and ObservationsThe inspectors identified issues with procedure quality and compliance over the periodof assessment. Noteworthy examples of deficient procedure quality or compliance
were:*PER 114003, Incorrect Procedure Revision used on 6.9kV Shutdown Board relay
testing*PER 115490, Inability to manually operate Appendix R valves within the requiredtime.*PER 115539, Emergency Gas Treatment System procedure cloning resulting infailure of Unit 2 Phase A testing requirements.*PER 115534, Loss of RCS inventory during Unit 2 refueling outage Mansellalignment.*PER 117008, Missed firewatch through plant areas with disabled fire detection.No findings of significance were identified. In general, the licensee had identified trendsand appropriately communicated them to plant senior management. The inspectors
evaluated the licensee trending methodology and observed that the licensee had
performed a summary review of issues which were inputs to the plant Human
Performance Index. The licensee reviewed cause codes, involved organizations, key
words, and system links to identify potential trends in the data. The inspectors
compared the licensee process results with the results of the inspectors' daily
screenings and did not identify any significant discrepancies or potential trends that the
licensee had failed to identify. The specifics surrounding PER 115490, regarding the
inability to manually operate Appendix R valves within the required time, are further
addressed in Section 1R15, Operability Evaluations..3Annual Sample Review of Problems with Plant Venting Operations a.Inspection ScopeThe inspectors reviewed licensee actions to resolve issues surrounding plant ventingoperations. This review began as a look at how the licensee addressed problems
associated with two potentially significant events that had occurred during the venting of
plant systems. These events are common to nuclear plant operations and often are
required in restoration of a system after it has been removed from service or opened for
maintenance. PER 92485 was written on November 21, 2005, and identified that
operators had discovered the collapse of the "A" Chemical Volume Control System
(CVCS) Holdup Tank (HUT) due to the lack of an adequate vent path during drain down.
The licensee subsequently suspended use of the "A" CVCS HUT, performed a root
cause analysis, and implemented corrective actions to prevent a recurrence of this
activity. The inspectors reviewed the completion of required actions items spawned
from this event for timeliness, accuracy and adequacy. PER 102591 was written on
May 7, 2006, to address an event during drain down of the RCS to midloop conditions.
While making preparations for vacuum refill of the RCS, the evolution had to be
23Enclosuresuspended when it was identified that a required reactor vessel head vent path was notproperly aligned. The licensee immediately vented the RCS and verified that the RCS
was not under vacuum conditions based on no observed change in RCS level indication
when the head vent was opened. The licensee declared that the apparent cause of the
event was due to failure to follow procedure, inadequate procedural guidance, and
inadequate scheduling. The event associated with PER 102591 was dispositioned as a
licensee-identified violation in Inspection Report 05000327, 328/2006003. The
inspectors reviewed the PER action items for adequacy and the associated procedures
to ensure changes were implemented to preclude repetition of this event. The
inspectors utilized these examples during the inspection period to observe similar
activities that had the potential to degrade in risk significant systems. The inspectors
were able to observe RCS drain down and refill activities during the Unit 2 Cycle 14
refueling outage, as well as, the venting operations of support systems during
restoration to their normal mode of operation. b.Findings and ObservationsNo findings of significance were identified. The inspectors noted that the licenseeappeared to have an adequate sensitivity to operational experience, procedural
guidance, scheduling conflicts, and foreign material exclusion. The licensee was
successful in properly performing the necessary venting activities associated with the
multiple system drain and refill operations accompanying Unit 2 refueling outage
maintenance.4OA5Other Activities.1Review of the Operation of an Independent Spent Fuel Storage Installation (ISFSI)(60855.1) a.Inspection ScopeThe inspectors reviewed ISFSI document control practices to verify that changes to therequired ISFSI procedures and equipment were performed in accordance with
guidelines established in licensee procedures and 10 CFR 72.48. Documents reviewed
are listed in the Attachment to this report. b.FindingsNo findings of significance were identified..2(Open) NRC Temporary Instruction 2515/150, Rev. 2, Reactor Pressure Vessel Headand Vessel Head Penetration Nozzles (NRC Order EA-03-009) - Unit 2 a.Inspection Scope
From December 4 - 8, 2006, the inspectors reviewed the licensee's activities associatedwith the NDE of the reactor pressure vessel head (RPVH) penetration nozzles, the bare
metal visual examination of the top surface of the RPVH, and the visual examination toidentify potential boric acid leaks from pressure-retaining components above the RPVH.
24EnclosureThese activities were performed in response to NRC Bulletins 2001-01, 2002-01, 2002-02, and the first revision of NRC Order EA-03-009 Modifying Licenses dated February
20, 2004 (hereafter referred to as the NRC Order). The inspectors' review of the NDE of RPVH penetration nozzles included independentobservation and evaluation of ultrasonic testing (UT) examinations (for both data
acquisition and analysis), review of NDE procedures, personnel qualifications and
training, and NDE equipment certifications. The inspectors also held interviews with
contractor representatives (Areva) and other licensee personnel involved with the RPVH
examination. The activities were reviewed to verify licensee compliance with the NRC
Order and to gather information to help the NRC staff identify possible further regulatory
positions and generic communications.The inspectors reviewed a sample of the results from the volumetric UT examinations ofRPVH penetration nozzles. Specifically, the inspectors reviewed or observed the
following:*Observed in-process UT data acquisition scanning of RPVH penetration nozzles57 and 52 (both with thermal sleeves)*Reviewed the UT electronic data with the Level III analyst for RPVH nozzles 4,36, 43, 50, 56, 61, 69, 77, 126 and the calibration block (this included nozzles
both with and without thermal sleeves)*Reviewed the results of the UT examination performed to assess for leakage intothe annulus (interference fit zone) between the RPVH penetration nozzle and the
RPVH low-alloy steel for all penetration numbers listed in the previous bullet *Reviewed the procedures and results for the visual exam performed to identifypotential boric acid leaks from pressure-retaining components above the RPVH*Reviewed the RPVH susceptibility ranking and calculation of effectivedegradation years (EDY), including the basis for the RPVH temperature used in
the calculation b. Observations and FindingsIn accordance with the requirements of TI 2515/150, the inspectors evaluated andanswered the following questions:1) Were the examinations performed by qualified and knowledgeable personnel?
Yes. All personnel involved with the RPVH inspections were appropriately qualified inaccordance with the ASME Code, and most far exceeded the minimum requirements for
experience and training hours. The contractor (Areva) personnel responsible for
equipment manipulation, data acquisition, and data analysis frequently perform these
types of inspections nationwide.
25Enclosure2) Were the examinations performed in accordance with demonstratedprocedures?Yes. The Sequoyah Unit 2 RPVH has 57 control rod drive mechanism (CRDM) nozzleswith thermal sleeves, 13 with open housings (including 5 instrument column nozzles), 8
with part lengths, 4 upper head injection (UHI) nozzles, and 1 vent line nozzle, for a total
of 83 nozzles. All nozzles were subject to remote automated UT examination using one
of two types of probes. The blade probe was used for sleeved penetrations and the
open housing CRDMs using a dummy sleeve. The rotating probe was used for the
other open housing penetrations (UHI and instrument columns). A liquid penetrant
exam on the surface of the J-groove weld of the vent line was also performed to satisfy
the NRC Order. Procedures 54-ISI-603-002 (UT with thermal sleeves), 54-ISI-604-001 (UT of openhousings), 54-ISI-605-02 (UT of vent line), and 54-ISI-240-44 (liquid penetrant) were
implemented to complete the exams described above. Further, the inspectors verified
that the 54-ISI-603-002 and 54-ISI-604-001 procedures were used during the Areva
demonstration to EPRI's Materials Reliability Program (MRP) to show flaw detection
capability in RPVH penetrations. By letter dated October 3, 2006, from Jack Spanner of
EPRI to Joel Whitaker of TVA (the licensee), EPRI stated that Areva's demonstration of
flaw detection techniques could reliably detect flaws in CRDM penetrations.3) Was the examination able to identify, disposition, and resolve deficiencies?
Yes. All indications of cracks or interference fit zone leakage are required to bereported for further examination and disposition. Based on observation of the
examination process, the inspectors considered deficiencies would be appropriately
identified, dispositioned, and resolved. UT indications associated with the geometry of
the examined volume were identified in several penetration tubes. None of the
indications exhibited crack-like characteristics and were appropriately dispositioned in
accordance with procedures.4) Was the examination capable of identifying the primary water stress corrosioncracking (PWSCC) and/or RPVH corrosion phenomena described in the NRC
Order?Yes. The NDE techniques employed for the examination of RPVH nozzles had beenpreviously demonstrated under the EPRI MRP/Inspection Demonstration Program as
capable of detecting PWSCC-type manufactured cracks as well as cracks from actual
samples from another site. Based on the demonstration, observation of in-process
examinations, and review of NDE data, the inspectors determined that the licensee was
capable of identifying PWSCC and/or corrosion as required by the NRC Order. 5) What was the physical condition of the RPVH (e.g. debris, insulation, dirt, boronfrom other sources, physical layout, viewing obstructions)?The licensee performed a 100% bare metal visual (BMV) inspection of the top of theRPVH, including 360 around each penetration using a remote visual robotic crawler forareas inside the lead shielding and underneath the raised insulation package. The
26Enclosuresurface sloping down from the shielding to the flange was visually inspected directly by aLevel III VT-2 examiner. The inspectors independently reviewed portions of the remoteinspection video which revealed no insulation, dirt, or other general debris that caused
viewing obstructions in the areas of interest. Some small, loose particles of debris were
easily cleared from the surface with a low-pressure air stream mounted on the remote
crawler. The inspectors determined that the physical condition of the head was
adequate to meet the inspection requirements mandated by the NRC Order.6) Could small boron deposits, as described in NRC Bulletin 2001-01, be identifiedand characterized?Yes. The BMV examination was determined by the inspectors to be capable ofidentifying and characterizing small boron deposits as described in NRC Bulletin 2001-
01. The remote exam was VT-2 qualified and able to resolve, at a minimum, the 0.105-
inch characters on an ASME IWA-2210-1 Visual Illumination Card.7) What material deficiencies (i.e., cracks, corrosion, etc.) were identified thatrequired repair?There were no identified examples of RPVH penetration cracks, leakage, materialdeficiencies, head corrosion, or other flaws that required repair. As discussed
previously, there were some UT indications at J-groove welds that were dispositioned as
metallurgical/geometric indications (not service related). One metallurgical indication on
tube 56 actually extended below the J-groove weld, and the inspector verified that
adequate coverage below this metallurgical indication was obtained. These indications
were likely due to weld repairs performed during initial RPVH fabrication.8) What, if any, impediments to effective examinations, for each of the appliedmethods, were identified (e.g., centering rings, insulation, thermal sleeves,
instrumentation, nozzle distortion)?The penetration nozzles with thermal sleeves and centering pads did not impedeeffective examination. Concerning examination coverage, the NRC Order requires that
each tube's volume is inspected from a minimum of 2 inches above the highest point of
the J-groove weld to 2 inches below the lowest point of the J-groove weld, or 1 inch with
a stress analysis. The licensee had performed a stress analysis and the inspectors
verified that the minimum examination coverages required by the NRC Order were met. 9) What was the basis for the temperature used in the susceptibility rankingcalculation? NRC Order EA-03-009 requires that licensees calculate the EDY of the RPVH todetermine its susceptibility category, which subsequently determines the scope and
frequency of required RPVH examinations. The operating temperature of the RPVH is
an input to this calculation. Therefore, an incorrect temperature input could result in
placing the RPVH in an incorrect susceptibility category. The licensee uses the cold leg
temperature in this calculation.
27EnclosureIn Supplement No. 1 to the NRC's Safety Evaluation Report (SER) dated February1980, the NRC concluded that scale model tests provided reasonable assurance that
the upper head would operate at the cold leg temperature. However, the NRC staff also
required that plant data be acquired to confirm the head temperature. This data was
acquired for Unit 1 to satisfy both units because Unit 2 is considered a sister plant. The
inspectors reviewed this data which confirmed that the head operated at approximately
cold leg temperature with some minor thermocouple variations. In addition, both units
underwent a modification since this testing to increase bypass flow to the head from 4%
to about 7%. This gives further assurance that the RPVH operates at cold leg
temperature. For these reasons, the inspectors concluded that the licensee had an
adequate basis for their temperature input to the susceptibility ranking calculation, which
results in Unit 2 being placed in the Low category.10) During non-visual examinations, was the disposition of indications consistent withthe NRC flaw evaluation guidance?There were no indications considered to be flaws found during the RPVH examination.
11) Did procedures exist to identify potential boric acid leaks from pressure-retainingcomponents above the RPVH?Yes. Procedure 0-PI-DXX-068-100.R, Monitoring of Reactor Head Canopy Seal Weldsfor Leakage, is implemented every outage and meets the requirements of the NRC
Order. However, inspection of conoseals and other bolted connections above the
RPVH, such as the RVLIS line, are covered under the Boric Acid Program. The
inspectors determined that the program and procedure implementation met the
requirements of the NRC Order, however, the licensee also initiated actions to enhance
the method in which compliance with the NRC Order is documented. The inspectors
reviewed the inspection results for this outage and found that no indications of active or
recent boric acid leakage from pressure-retaining components above the RPVH were
identified. 12)Did the licensee perform appropriate follow-on examinations for indications ofboric acid leaks from pressure-retaining components above the RPVH?Yes. The licensee identified some boric acid residue that was later determined bychemical analysis to be older than the recent operating cycle. The residue was
attributed to a conoseal leak in 2002. No other indications of boric acid leakage were
found during this outage..3(Open) Temporary Instruction (TI) 2515/166, Pressurized Water Reactor ContainmentSump Blockage (NRC Generic Letter 2004-02) - Unit 2 a.Inspection ScopeThe inspectors verified the Unit 2 implementation of the licensee's commitmentsdocumented in their September 1, 2005, response to Generic Letter 2004-02, Potential
Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents
28Enclosureat Pressurized Water Reactors. The commitments included a permanent screenassembly modification, a license amendment request to change the UFSAR description
of the sump screen analysis methodology, and submittal of a supplemental response to
GL 2004-02. This review included the sump screen assembly installation procedure,
screen assembly modification 10 CFR 50.59 evaluation, structural (debris) loading
calculation, and validation testing of the modified sump screen design. The inspectors
also reviewed the foreign materials exclusion controls and the completed Quality
Assurance/Quality Control records for the screen assembly installation. The inspectors
conducted a visual walkdown to verify the installed screen assembly configuration was
consistent with drawings and the tested configuration and verified the design criteria for
screen gap. b.Findings and ObservationsNo findings of significance were identified.
Unit 2 permanent modifications completed at the time of this inspection wereimplemented in accordance with Sequoyah Generic Letter 2004-02 response and
supporting evaluations. The license amendment request to change the UFSAR screen
analysis methodology description had been submitted and approved. No modifications
were required to address downstream effects. TI 2515/166 will remain open pending
completion and NRC review of the licensee's GL 2004-02 commitments for Unit 1 which
are scheduled for the fall 2007.
.4(Closed) NRC Temporary Instruction (TI) 2515/169, Mitigating Systems PerformanceIndex (MSPI) Verification a.Inspection ScopeDuring this inspection period, the inspectors completed a review of the licensee's
implementation of the Mitigating Systems Performance Index (MSPI) guidance for
reporting unavailability and unreliability of monitored safety systems in accordance with
TI 2515/169. The inspectors examined surveillances that the licensee determined would not renderthe train unavailable for greater than 15 minutes or during which the system could be
promptly restored through operator action and therefore, are not included in
unavailability calculations. As part of this review, the recovery actions were verified to
be uncomplicated and contained in written procedures.On a sample basis, the inspectors reviewed operating logs, work history information,maintenance rule information, corrective action program documents, and surveillance
procedures to determine the actual time periods the MSPI systems were not available
due to planned and unplanned activities. The results were then compared to the
baseline planned unavailability and actual planned and unplanned unavailability
determined by the licensee to ensure the data's accuracy and completeness. Likewise,
these documents were reviewed to ensure MSPI component unreliability data
determined by the licensee identified and properly characterized all failures of monitored
components. The unavailability and unreliability data were then compared with
29Enclosureperformance indicator data submitted to the NRC to ensure it accurately reflected theperformance history of these systems. b.Findings and ObservationsNo findings of significance were identified. The licensee accurately documented thebaseline planned unavailability hours, the actual unavailability hours and the actual
unreliability information for the MSPI systems. No significant errors in the reported data
were identified, which resulted in a change to the indicated index color. No significant
discrepancies were identified in the MSPI basis document which resulted in: (1) a
change to the system boundary, (2) an addition of a monitored component, or (3) a
change in the reported index color..5Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review a.Inspection ScopeThe inspectors reviewed the interim report for the INPO plant assessment report ofSequoyah conducted in July 2006. The inspectors reviewed the report to ensure that
issues identified were consistent with the NRC perspectives of licensee performance
and if any significant safety issues were identified that required further NRC follow-up. b. FindingsNo findings of significance were identified.
4OA6Meetings, Including Exit.1Exit Meeting SummaryOn January 3, 2007, the resident inspectors presented the inspection results to
Mr. R. Douet and other members of his staff, who acknowledged the findings. The
inspectors asked the licensee whether any of the material examined during the
inspection should be considered proprietary. No proprietary information was identified.4OA7 Licensee-Identified ViolationsThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of NRC requirements which meet the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.*TS 6.8.1 requires that written procedures shall be established, implemented, andmaintained covering the activities recommended in Appendix "A" of Regulatory
Guide 1.33, Revision 2, February 1978. Contrary to this, on November 28, 2006,
an AUO improperly implemented 0-GO-13,Reactor Coolant System Drain and
Fill Operations, Revision 54, Appendix AC by mispositioning an RCS loop 4 drainvalve. This revealed itself through the subsequent transfer of RCS inventory to
the Reactor Coolant Drain Tank and lowering of RCS pressurizer level. The
30Enclosureerror was promptly corrected by operations staff and the event was identified inthe licensee's corrective action program as PER 115534. This finding is of very
low safety significance because it did not challenge RCS inventory control by
exceeding available makeup capacity.ATTACHMENT: SUPPLEMENTAL INFORMATION
AttachmentSUPPLEMENTAL INFORMATIONKEY POINTS OF CONTACTLicensee personnel
J. Adams, Boric AcidD. Bodine, Chemistry/Environmental Manager
R. Bruno, Training Manager
R. Douet, Site Vice President
B. Dungan, Outage and Site Scheduling Manager
J. Epperson, Licensed Operator Requal Lead
J. Goulart, ISI
K. Jones, Site Engineering Manager
Z. Kitts, Licensing Engineer
D. Kulisek, Plant Manager
G. Morris, Licensing and Industry Affairs Manager
T. Niessen, Site Quality Manager
M. A. Palmer, Radiation Protection Manager
M. H. Palmer, Operations Manager
K. Parker, Maintenance and Modifications Manager
J. Proffitt, (Acting) Site Licensing Supervisor
J. Reisenbuechler, Operations Training Manager
R. Reynolds, Site Security Manager
N. Thomas, Licensing Engineer
S. Tuthill, Chemistry Operations Manager
J. Whitaker, ISI
K. Wilkes, Emergency Preparedness ManagerNRC personnel
- R. Bernhard, Region II, Senior Reactor AnalystD. Pickett, Project Manager, Office of Nuclear Reactor RegulationLIST OF ITEMS OPENED, CLOSED, AND DISCUSSEDOpened and Closed05000327,328/2006005-01NCVFailure to Certify Qualifications and Statusof Licensed Operators Were Current and
Valid (Section 1R11.3)Opened05000328/2006005-02URIAppendix R Manual Isolation Valve Failureto Close Within the Required Time text
(Section 1R15)
Closed05000327,328/2515/169TIMitigating Systems Performance IndexVerification (Section 4OA5.4)
A-2Attachment
Discussed05000327, 328/2515/150TIReactor Pressure Vessel Head and VesselHead Penetration Nozzles (NRC Order EA-
03-009) - Unit 2 (Section 4OA5.2)05000327, 328/2515/166 TIPressurized Water Reactor ContainmentSump Blockage (NRC Generic Letter 2004-
02) - Unit 2 Section 4OA5.3)
AttachmentLIST OF DOCUMENTS REVIEWEDSection 1R01: Adverse Weather ProtectionSPP-10.14, Freeze Protection, Revision 0M&AI-27, Freeze Protection, Revision 12
0-PI-OPS-000-006.0, Freeze Protection, Revision 45
1-PI-EFT-234-706.0, Freeze Protection Heat Trace Functional Test, Revision 30 Section 1R02: Evaluation of Changes, Tests, or ExperimentsFull Evaluations:DCN D21640A, Radiation Monitors Are Being Deleted/Abandoned On Unit 1.DCN D21641A, Radiation Monitors Are Being Deleted/Abandoned On Unit 2.
DCN D21854A, DG Starting Air PCV Modification.
DCN D21247A, Replace The Existing Electrotechnical Controls For The MCR And EBR A/C
Condensing Units With Digital Controls.
DCN D21248A, Replace The Existing Electrotechnical Controls For The MCR And EBR A/C
Condensing Units with Digital Controls.
FSAR Section 15.2.10, Revision to Section 15.2.10 of the FSAR containing the transientanalysis for feed water malfunction event.
TACF 1-05-013-R1, Temporary configuration change involving installation of non-nuclear safety
low volume high pressure pump into the SI System.
TACF 1-05-002-063, R1, Temporary installation of TVA Class B piping/tubing and check valve
downstream of 1-VLV-63-834 to provide RHRS pressure relief leakage.
FSAR Section 10.4.7 and 10.4.8, Proposed FSAR change to allow Steam Generator Blowdown
to remain in service for various reasons.
ES-1.3, R12, Revised ES-1.3 to modify guidance on stopping and restarting SI pump (PER 04-
000344-000). Screened Out Items:1-SI-OPS-000-003.M R32, Add Glycol Valves In Accordance With 06-NSS-061-035.TI-28 REV 198, Procedure Revision On Unit 1 NIS Power Range Calibration Data
0-SI-OPS-068-137.0, Added Precaution And Limitation G To Section 3.2.
0-SO-14-4 Rev 10, Added Section 8.5 To Provide Instructions For Manual Operation Of
Temporary Sump Pump.
0-SO-77-11 R15, Revised To Add A Precaution To Monitor Waste Gas Vent Header
Frequently.
1-SO-63-1, Rev. 45, Revised section 8.1 step 6 of procedure to make the step conditional.
2-SI-OPS-000-003.M, Rev. 26, Added note 5 to exempt monthly valve stroke of the glycol valve
when the valve was stroked in the previous 7 days.
0-GO-14-4, R12, Revised to incorporate changes in accordance with NB 060785.
0-GO-5, Rev. 47, Revised step in section 5.4 concerning control rods, ref. NB 060297; added
step to section 5.1 concerning MFPT master controller output, ref. PER 100196-03.
1-AR-M1-A, Rev. 38, Revised in response to 060738 which provided additional information
regarding the inputs for Window A-5.
DCN D20960A, Sequoyah Independent Spent Fuel Storage Installation, (ISFSI).
0-SO-30-10, R31, Revised section 8.15 to provide guidance for Auxiliary Building Chill Water
Feed and Bleed when system is set up for winter operation.
A-4Attachment2-SI-TDC-068-254, Rev. 5, Surveillance instruction is being changed from 18 months toconditional.
0-SO-70-1, R34, Added a step and caution to sections 8.5.2 and 8.5.4 to initiate a Work Order
to backfill affected flow transmitter following restoration of CCCS HX. 0B1 or 0B2 after
maintenance.
0-SO-77-1, Rev.40, Revised to provide guidance on the transfer of the Laundry and Hot
Shower Tank to the CDCT; moved guidance on re-circulation of the CDCT to new appendix E.
1-SI-OPS-000-003.M, R33, Revise note 18 in Appendix A of surveillance instruction to show
allowable channel deviation of less than or equal to 5%. Problem Evaluation Reports (PERs):84897, 0-PI-ECC-313-595.0 Cannot Be Performed As Currently Written31739, Westinghouse Advisory Letter NASL-02-3 Describes A Process Measurement Uncertain
99597, Water In Waste Gas Vent Header During Resin Transfer
64337, DG 2-PCV-082-262 Blow Down
98255, MCR B Chiller Oil Temperature Swinging
65752, Specified Post Maintenance Testing Deficiencies
76900, S/G Blowdown Isolation of AFWP Start.
20195, ES 1.3, Transfer to RHR Containment Sump requires stopping the SI Pumps if RCS
pressure is greater than 1500 psig. Work Orders:6-771849-000, Check TE Accuracy, if unsatisfactory, Then Replace the TE 6-771384-000, Replace the Oil Cooler TCV for the B MCR ChillerProcedures:TI-28, Rev. 198, Curve Book0-SI-OPS-068-137.0, Rev. 19, Reactor Coolant System Water Inventory
1-SI-OPS-000-003.M, Rev. 32, Monthly Shift Log
1-SI-OPS-000-003.W, Rev. 37, Weekly Shift Log
0-SO-14-4, Rev. 10, Condensate Demineralizer waste Disposal
0-SO-77-11, Rev. 15, Waste Gas Compressor Operation
0-PI-ECC-313-595.0, Rev. 4, Periodic Calibration of Auxiliary Building Heating, Ventilating and
Air Conditioning
SPP - 9.4, 10 CFR 50.59 Evaluations of Changes, Tests and Experiments, Revision 7.
EN-1-102, 10 CFR 50.59 / 10 CFR 72.48, Reviews, Revision 7.Miscellaneous Documents:PMTI-SQN-21854, DG 1A-A Starting Air 5 Start Capacity VerificationSSD 1- L - 68-325, Low RCS Pressurizer Level
SSD 1 L - 68-326, High RCS Pressurizer Level.
SSD 2 -L -68-325, Low RCS Pressurizer Level
SSD 2- L - 68-326, High RCS Pressurizer Level.
NEI 96-07, Nuclear Energy Institute, Guidelines for 10 CFR 50.59 Implementation, Revision 1.
Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59 Changes, Tests and
Experiments, November 2000.
A-5AttachmentSection 1R04: Equipment Alignment1,2-47W810-1, Flow Diagram - Residual Heat Removal System, Revision 472-47W811-1, Flow Diagram - SI System, Revision 57Section 1R05: Fire ProtectionSQN Drawing 1,2-47W494-6 Fire Protection Compartmentation-Fire Cells Plan El. 669' & 685'SQN Fire Protection Report Part II - Fire Protection Plan, Revision 20
SQN-26-D054/EPM-ABB-IMPFHA, SQN Fire Hazards Analysis Calculation, Appendix A
Spp-10.10, Control of Transient Combustibles, Revision 4Section 1R07: Heat Sink PerformancePER 116021, Containment Spray Heat Exchangers Not in Chemical LayupTVA Letter S64 950922 800, Program Update Regarding NRC GL 89-13 dated September 22,
1995
1,2-47W812-1, Flow Diagram Containment Spray System, Revision 42Section 1R08: Inservice Inspection Activities
Programs/Procedures/Reports2-SI-SXI-068-114.3, Steam Generator Tubing Inservice Inspection and Augmented Inspections,Revision 2
Degradation Assessment for Sequoyah Unit 2 Cycle 14
Operational Assessment Report for Unit 2 Cycle 13 Refueling Outage
Self Assessment CRP-ENG-009 SQN ASME Section XI Program
Self Assessment 06SQN-12-ENG-XI ASME Section XI Inservice Inspection (ISI) Program
SQN-ENG-03-007 Boric Acid Program Effectiveness Assessment
SPP-9.7, Corrosion Control Program, Rev. 13
Technical Instruction 0-TI-DXX-000-097.1, Rev. 01, Boric Acid Corrosion Control Program
BP-257, Rev. 5, TVA Business Practice, Integrated Material Issues Management Plan,
Appendix A
Proc. No. N-UT-76, Rev. 6, Generic Procedure for Ultrasonic Examination of Ferritic Pipe
Proc. No. N-UT-64, Rev. 9, Generic Procedure For The UT Examination of Austenitic Pipe
Proc. No. N-VT-1, Visual Examination Procedure for ASME Section XI Preservice and Inservice
Proc. No. N-VT-15, Rev. 5, Visual Examination of Class MC and Metallic Liners of Class CC
Components of Light-Water Cooled Plants
SQN Unit 2 Examination Schedule 0-SI-DXI-115.3, Att.5Design Change Package 22061, Pressurizer Safe End Weld Overlays
WO # 06-775288-002, Pressurizer Safe End Weld Overlays
Vendor Instruction 0-VI-MOD-068-001
Welding Services Traveler 103804-001
A-6AttachmentCorrective Action (PERS)03-017128-000, NRC inspectors concern that a "GAP" between the support steel and the pipeindicated that the dead weight was not being supported.
20732, NRC inspector expressed concern that the NDE procedure N-VT-1 does not address
"GAPS" observed during hanger inspections.
107387, Borated Water Leak on lower flange of 20LCV-62-1`8, Boron is dry
100794, 2A Containment Spray Pump outboard Seal leak.
106740, Boric Acid Corrosion on support for SQN-2-VLV-063-0578
90714, 2-FCV-63-156 packing leak
81632, Leakage observed on pressurizer safe-ends RCW-25-SE and RCW-26-SE.Section 1R11: Licensed Operator RequalificationQuarterly ReviewAOP-I.08, Turbine Impulse Pressure Instrument Malfunction, Revision 8FR-S.1, Function Restoration Procedure - Nuclear power Generation/ATWS, Revision 20
E-0, Reactor Trip or SI, Revision 27
ES-0.1, Reactor Trip Response, Revision 30Biennial ReviewProcedures and RecordsTRN 11.4 "Continuing Training For Licensed Personnel, Rev. 11.TRN 1 Administering Training, Rev 17.
OPDP-1 Conduct of Operations, Appendix 0, License Status-Active/Inactive License, Rev. 6.
Operations Directive Manual, Appendix B-Qualifications Tracking Requirements, Rev. 2.
Badge Access Transaction Reports
Licensed Operator Medical Records
Remedial Training Records
Written Exams: A3 RO Exam and A3 SRO Exam.
Simulator Work Request - PR4542
LER 2005-001-00 Units 1 and 2
LER 2005-002-00 Unit 2
LER 2006-001-00 Units 1and 2Job Performance MeasuresJPM 163 "Steam line Pressure Transmitter fails low".JPM 33AP "Manual Control of AFW Following a Reactor Trip".
JPM 12 "Pressurizer Level Control Malfunction".
JPM 59 "Establish Excess Letdown".
JPM 80" Local Control of Charging Flow".
JPM 61A2 "Transfer 480V SD Board 2A1-A From Normal to Alternate Supply".
JPM 72 "Local Alignment of 1-RM-90-112 to Lower Containment".
JPM 32AP "Local Manual Control of S/G PORV".
JPM 6 "Perform Boration of the RCS From Outside the Main Control Room".
JPM 78 AP "Respond to an ATWS Trip the Reactor Locally".
A-7AttachmentSimulator Scenarios:S-13 Uncontrolled Depressurization of All Steam Generators. Rev 12.S-7 Pressurizer Vapor Space Accident. Rev 15.
S-11 LOCA with Loss of RHR Recirculation. Rev 13.Simulator Malfunction Tests:ED15 Loss of 250VDC Battery Board.IA03
FW23
FW20
ED08
ED10 Transient Tests:#2 Both Main Feedwater Pumps Trip , AFW fails to start.#5 Trip of Any Single Reactor Coolant Pump.
- 8 Loop 2 Cold-Leg Large Break LOCA with Loss of Offsite Power.
- 9 Main Steam Line Break Inside Containment.
- 10 Slow RCS Depressurization to Saturation.Normal Tests:2005 Steady State Operation Drift Test2005 Steady State Operation Static Test for 100%, 66%, and 44% power.Section 1R12: Maintenance EffectivenessTI-4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting - 10 CFR50.65, Revision 19Section 1R13: Maintenance Risk Assessments and Emergent Work EvaluationSentinel Run, October 23 to November 12, 2006SQN Plan-of-the-Day, October 26, 2006
SQN MSS-OPS Daily Schedule Report 24 Hour Look-Ahead, October 25, 2006
Sentinel Risk Assessment for Failed EDG 2B-BSection 1R15: Operability Evaluations0-SI-SFT-311-001.A, Control Room Air-Conditioning System Train A, Revision 1UFSAR Section 6.4, Habitability Systems
UFSAR Section 9.4, Heating, Ventilating, and Air-Conditioning
FE 41643, Observed Air Flow Above Design Flow For MCR 'A" Air Handling Unit
1,2-47W866-4, Flow Diagram Heating, Ventilation and Air-Conditioning - Control Building,
Revision 3
1,2-47W867-2, Mechanical Air-Conditioning Control Diagram - Control Building, Revision 12
B87 951205 003, ERCW Screen Wash System Hydraulic Analysis, Revisions 2 and 3
0-SI-SXP-067-202.B, ERCW Traveling Screen Wash Pump B-B Performance Test, Revision 8
A-8Attachment0-SO-67-1, Essential Raw Cooling Water, Revision 631,2-45N765-1, Wiring Diagram 6900V Shutdown Aux Power Schematic Diagram SH-1,
Revision 14
1,2-45N765-2, Wiring Diagram 6900V Shutdown Aux Power Schematic Diagram SH-2,
Revision 20
WO 04-774974-000, Replace Emergency Diesel Generator 2B-B Breaker
1,2-47W809-1, Flow Diagram Chemical & Volume Control System
1-108D273-18, Process Control Block Diagram Turbine Impulse Pressure Protection Sets I and
II, Revision 0Section 1R17: Permanent Plant ModificationsProblem Evaluation Reports (PERs):31739, Westinghouse Advisory Letter NASL-02-3 Describes A Process Measurement Uncertain65752, Specified Post Maintenance Testing Deficiencies
84070, Diesel Generator 1A-A cable testing.
103766, Main Bank Transformer 1B Hot Spots
104337, Main Bank Transformer 1B Hot SpotCalculations:Calculation No. SQN- APS - 042, 480 V Turbine Building Common Board Load Coordination,Short Circuit, Circuit Protection and Voltage Drop Analysis, Revision 4.
Calculation No. SQN-APS-041, 480 VAC Unit Board Load Coordination Study, Revision 4.Work Orders:6-771849-000, Check TE Accuracy, if unsatisfactory, Then Replace the TE 2-002298-000, Westinghouse Advisory Letter NSAL-02-3
03-012340-001, Replace degraded portion of 6900 V Diesel Generator 1A-A power cable
PP351A between Unit 1 Additional Equip. Bldg. And D/G exciter cubicle. 03-012340-002, Install section of new replacement cable PP351A from AEB-1 to MH-14 via
existing conduit. Miscellaneous Documents:Westinghouse Advisory Letter NSAL-03-9ABB Power T&D- Sequoyah Nuclear Plant Final Report "Main Generator Transformer Life
Assessment". Drawings:Drawing No. 1, 2-3591A28, Breaker Setting Sheet 480 V Unit Board 1A, Revision 5Drawing No. 1, 2-3591A30, Breaker Setting Sheet 480 V Unit Board 1B, Revision 6.
Drawing No. 1, 2-3591A32, Breaker Setting Sheet 480 V Unit Board 2A, Revision 6.
Drawing No. 1, 2-3591A34, Breaker Setting Sheet 480 V Unit Board 2B, Revision 5
Drawing No. 1, 2-3591A36, Breaker Setting Sheet 480 V Turb. Building Common Board,
Revision 9 Drawing No. 1, 2-15E500-1, Key Diagram Station Auxiliary Power, Revision 25
Drawing No. 1, 2-15E500-3, Transformer Taps and Voltage Limits - Auxiliary Power System,
Revision 16.
Drawing No. 1-45N1504, Wiring Diagrams - Main Single Line 500 KV Switchyard, Revision 29
A-9AttachmentDrawing No. 1-45W1541, Wiring Diagrams AC Schematic Unit 1 Generator & transformerCircuits, Revision 14Procedures:TI-28, Rev. 198, Curve Book
PER Written Because of Inspection Finding114743, Superseded ARP revision found in ACR Section 1R19: Post Maintenance TestingPER 115780, 2-FCV-74-28 Did Not Appear To Fully Open2-SI-SXP-074-202.A, RHR Pump 2A-A Performance and Discharge Check Valve Test,
Revision 0
WO 06-780773-000, Calibrate 2-FCV-74-28 and Limit SwitchesSection 1R20: Refueling and Outage Activities0-GO-6, Power Reduction from 30& Reactor Power to Hot Standby, Revision 320-GO-7, Unit Shutdown From Hot Standby to Cold Shutdown, Revision 47
0-GO-15, Containment Closure Control, Revision 21
DVD Recording of U2C14 Core Load Verification
1,2-47W812-1, Flow Diagram Containment Spray System, Revision 42
Tagout Clearance 2-72-2406-RFO, Motor Operated Valve Maintenance on 2-FCV-72-21
0-GO-13, Reactor Coolant System Drain and Fill Operations, Revision 54
Sequoyah Nuclear Plant Unit 2 Cycle 15 Core Operating Limits ReportSection 1R22: Surveillance TestingSPP-8.1 Conduct of Testing, Rev 4
Section 1EP6: Drill EvaluationNEI 99-02 Rev 0, March 2000Emergency Plan Implementing Procedure (EPIP) - 1, Emergency Plan Classification Matrix,
Rev 37
EPIP-3, Alert, Rev 29
EPIP-4, Site Area Emergency, Rev 29
EPIP-5, General Emergency, Rev 36
EPIP-6, Technical Support Center, Rev 41
EPIP-7, Operations Support Center, Rev 25Section 2OS1: Access Control To Radiologically Significant AreasProcedures, Instructions, Guidance Documents, and Operating ManualsANSI/ANS 3.1-1987, Selection, Qualification, and Training of Personnel for Nuclear PowerPlants
Tennessee Valley Authority (TVA), TVA Nuclear (TVAN), Standard Programs and
A-10AttachmentProcesses (SPP) - 3.1, Corrective Action Program, Rev. 11Active Radiation Work Permits (RWPs) List, dated 12/11/2006
RP Personnel Identification by Craft Report, dated 12/14/2006
Task Qualification List (selected individuals), dated December 14, 2006
LHRA Key Control Log Sheets (several pages)
TVA, TVAN, TRN-20, Health Physics Technician Training, Rev. 13
High Radiation Areas at Sequoyah List, document not dated
SNP RP Organizational Chart (current and proposed changes), document not dated.
TVAN Radiation Protection Peer Team Challenge Update (MS
Power Point presentation),dated 12/13/2006
TVA, TVAN, SPP-5.2, ALARA Program, Rev. 3
RWP 06027010, Rev. 0, Routine Plant Maintenance-Lower Containment All Areas
RWP 06027035, Rev. 0, Routine Plant Maintenance-Inside Polar Crane All Areas
RWP 06027390, Rev. 1, Routine Plant Maintenance-Accumulator 1-4
RWP 06037020, Rev. 0, Inservice Inspection-Steam Generator Primary Side 1-4
RWP 06047141, Rev. 0, Refueling-U-2 Reactor Cavity
TVA, Sequoyah Nuclear Plant (SNP), Radiological Control Instruction (RCI)-01, RadiationProtection Program
TVA, SNP, RCI-01, Training and Qualification of Health Physics Technicians-RadiationOperations Technicians, effective date 02/24/05
TVA, SNP, RCI-14, Radiation Work Permit (RWP) Program, Rev. 37
TVA, SNP, RCI-15, Radiological Postings, Rev. 15
TVA, SNP, RCI-24, Control of Very High Radiation Areas, Rev. 7
TVA, SNP, RCI-28, Control of Locked High Radiation Areas, Rev. 5
TVA, SNP, RCI-29, Control of Radiation Protection Keys, Rev. 4Records and Data ReviewedSNS VSDS Survey Nos. 120506-2, 120606-8, 120506-15, 120606-10, 120606-7, 120706-2,120106-10, 120606-6, and 120306-4
Air Sample Survey Nos. 120406018, 120506021, 120506024, 120506034, 120506037,
120506045, 120506048, 120506053, 120606020, 120706010,120406024, 120606028,
120506012, and 120606043Corrective Action Program DocumentsNuclear Assurance (NA) - TVAN-Wide - Audit Report No. SSA0502 - Radiological Protectionand Control Audit, dated January 19, 2006
SQN-RP-05-001, Self-Assessment Report, dated 12/22/04
SQN-RP-05-003, Self-Assessment Report, dated 7/29/05
Problem Evaluation Report (PER) 82569, Presently U-1 Lower Containment Has a Ladder.
PER 115944, The Total Nozzle Dam Jumpers Dose Was Greater than the ALARA estimate
PER 101211, Posting and Control of Filter Cubicles...
PER 113913, Lock Box for Lifting Device Control
PER 109603, Radiation Posting
PER 109604, Radcon Use of Industry Information
PER 87610, Key Taken Home
PER 82027, High Radiation Readings on Valve
PER 82643, Unexpected Radiation Level Change
A-11AttachmentPER 84532, VHRA Key InventoryPER 99226, Locked High Radiation Door Locks StickingSection 4OA5: Other Activities - Operation of ISFSINEI 96-07, Guidelines for 10 CFR 72.48 Implementation, Appendix BSPP-9.9, 10 CFR 72.48 Evaluations of Changes, Tests, and Experiments for Independent
Spent Fuel Storage Installation, Revision 1
Regulatory Guide 3.72 - Guidance for Implementation of 10 CFR 72.48, Changes, Tests and
Experiments
PER 95624, MPC-0011 Lid Did Not Fully Seat Due to Upper Fuel Spacers Not Vertical or
Plumb
10 CFR 48 Evaluation, Response to NRC IN 2003-16
10 CFR 48 Procedure Change Evaluation, Revision of NFTP-100, Fuel Selection for Dry MPC
Storage
10 CFR 48 Screening, Auxiliary Building Crane Truck Repairs
10 CFR 48 Screening, Auxiliary Building Crane Truck Replacements
10 CFR 48 Screening, Revision to Welding Procedures
10 CFR 48 Screening, Procedure Change to Fuel Handling Instruction FHI-14
10 CFR 48 Screening, Procedure Change to Fuel Handling Instruction FHI-3Section 4OA5: Other Activities - TI 2515/150Procedures0-PI-DXX-068-100.R, Monitoring of Reactor Head Canopy Seal Welds For Leakage, Rev. 154-ISI-603-002, Automated Ultrasonic Examination of RPV Closure Head Penetrations
Containing Thermal Sleeves
54-ISI-604-001, Automated Ultrasonic Examination of Open Tube RPV Closure Head
54-ISI-605-02, Automated Ultrasonic Examination of RPV Closure Head Small Bore
54-ISI-240-44, Visible Solvent Removable Liquid Penetrant Examination Procedure
N-VT-17, Visual Examination for Leakage of PWR Reactor Head Penetrations, Rev. 4
SPP-9.7, Corrosion Control Program, Appendix D, Technical Requirements for the Boric Acid
Corrosion Control Program, Rev. 13Records/Reports/Engineering DocumentsEquipment Certification Records for the following NDE Equipment:Blade Probes: S1035 NL, S5002 NL, and S5001 NL
Ultrasonic Transducers: 21GB-06001 and 2078-06001Engineering Information Record 51-9027415-000, RPV Head Penetration Inspection Plan and
Coverage Assessment for Sequoyah Units 1 and 2
Calculation C-3217-00-02, Sequoyah 1 and 2 CRDM and Instrument Column Nozzle Stress
Analysis
Letter L44 030227 801, Response to issuance of NRC Order
A-12AttachmentCorrective Action DocumentsPER 115561, Evidence of leakage during canopy seal weld inspectionPER 116540*, EDY calculation not performed every outage
PER 116165*, Transducer frequencies documented incorrectly
- Problem Evaluation Reports generated as a result of this inspectionSection 4OA5: Other Activities - TI 2515/166 Surveillance Instruction 2-SI-SIN-063-009-02, Containment Sump Inspection, dated 11/08/06DCN 22023, Modify Containment Sump Screens as required by NEI Methodology, dated
11/22/06
Amendment to Facility Operating License No. 302, DPR-79, Revised Transport Analysis
Methodology for Containment Debris Transport, dated 11/07/06
TVA letter to NRC, Sequoyah Response to GL 2004-02. dated 9/01/05
AREVA document No. 51-9008500-003, Test Report for Sure-Flow strainer (Prototype)
Headloss Evaluation for Sequoyah 1 & 2 ECCS Containment Sumps, dated 7/26/06
AREVA document No. 51-9008506-001, Sequoyah Advanced Design Reactor Building Sump
Strainer Test Results Summary, Units 1 & 2, dated 1/31/06
GL 2004-02 Supplemental Response, Sequoyah Nuclear Plant Units 1 & 2, - NRC GL 2004-02,
Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis
Accidents at PWRs (Draft dated 12/15/06)
Calculation ALION-CAL-TVA-2740-05, SQN Units 1 & 2 Containment Sump Debris
Accumulation and Head Loss, dated 6/28/05
Calculation TDI-6009-02, SFS Surface Area Flow Volume - TVA/Sequoyah 1 & 2, dated
9/21/06
MDQ0072980034, "CCP, SIP, CSP, and RHR Pump NPSH Evaluation", Rev 1, 11/19/2006
DCN # D22023, "Modify Containment Sump Screens as Required by NEI Methodology", Rev A,
11/22/2006
Calculation TDI-6009-004, "Module Debris Weight - TVA/Sequoyah -
1/2", Rev 2, 10/13/2006Calculation PCI-5465-S01, "Structural Evaluation of Advanced Design Containment Building
Sump Strainers", Rev 0, 10/20/2006
Routine Work Order 06-774811-000, "Containment RHR Sump 48N919", Rev 5
FME Accountability Log, SPP 6.5.1Section 4OA5: Other Activities - TI 2515/169Procedures, Manuals, and Guidance DocumentsNEI 99-02, Mitigating System Performance Index (MSPI) Basis Document, Revision 1Selected System Status Reports
0-SI-SXV-063-266.0, ASME Section XI Valve Testing
1,2-SI-SXV-000-201.0, Full Stroking of Category "A" and "B" Valves During Operation
0-SI-SXV-074-266.0, ASME Section XI Valve Testing
1,2-SI-OPS-074-128.0, RHR Discharge Piping Vent
1-SI-SXP-074-074-201.B, RHR Pump 1B-B Performance Test
2-SI-SXP-074-074-201.B, RHR Pump 1B-B Performance Test
0-SI-SXV-000-221.0, Full Stroking of the Common ERCW and CCS Category "A" and "B"
Valves During Operation
A-13Attachment0-SI-OPS-067-682.Q, ERCW Non-Safety Related Flow Balance Valve Position Verification0-SI-SXP-067-202.B, ERCW Traveling Screen Wash Pump B-B Performance Test
2-SI-OPS-070-32.A, Component Cooling Water Valves Position Verification Train "A"Records and DataSelected Control Room Logs, January 2004 through December 2006EDG NRC Performance Indicators, 2002 - 2005
AFW NRC Performance Indicators, 2002 - 2005
HPSI NRC Performance Indicators, 2002 - 2005
RHR NRC Performance Indicators, 2002 - 2005
Consolidated Data Entry MSPI Derivation Reports Generated November 2006
MSPI Equipment Functional Failure Data Sheets
Maintenance Rule Unavailability Data Sheets, 2002-2006
Maintenance Rule Unreliability Data Sheets, 2002-2006Corrective Action Program DocumentsSelected Corrective Action Reports, 2005-2006
AttachmentLIST OF ACRONYMS AFWauxiliary feedwaterANSIAmerican National Standards Institute
AOPabnormal operating procedures
ARCalternate repair criteria
ASMEAmerican Society of Mechanical Engineers
ATWSanticipated transient without scram
AUOauxiliary unit operator
BACCboric acid corrosion control
BMVbare metal visual
CCPcooling charging pump
CCPITcooling charging pump injection tank
CFRCode of Federal Regulations
CRcondition report
CRDMcontrol rod drive mechanism
CVCSchemical volume control system
DCNdesign change notice
ECCSemergency core cooling system
ECTeddy current testing
EDYeffective degradation years
ERCWessential raw cooling water
ETSSexamination technique specifications sheet
FCVflow control valve
FEfunctional evaluation
FMEforeign material exclusion
FOSARforeign object search and recovery
HRhigh radiation
HUTholdup tank
INPOInstitute of Nuclear power Operations
ISFSIindependent spent fuel storage installation
ISIinservice inspection
LHRAlocked high radiation area
MRPmaterials reliability program
MSPImitigating systems performance index
NCVnon-cited violation
NDEnon-destructive examination
NRCU.S. Nuclear Regulatory Commission
ODSCCouter diameter stress corrosion cracking
OPDPoperations department procedure
PARpublically available records
PERproblem evaluation report
PERprotective action recommendation
PORVpower-operated relief valve
PWSCCprimary water stress corrosion cracking
RCPreactor coolant pump
RHRresidual heat removal
RPradiation protection
A-15AttachmentRPVHreactor pressure vessel headRTPrated thermal power
RWPradiation work permit
RWSTrefueling water storage tank
SDPsignificance determination process
SERsafety evaluation report
SGsteam generator
SIsafety injection
SIsurveillance instructions
SSCstructure, system, or component
TDAFPturbine driven auxiliary feedwater pump
TItemporary instruction
TStechnical specification
TVATennessee Valley Authority
UFSARupdated final safety analysis report
UHIupper head injection
URIunresolved item
UTultrasonic testing
WOswork orders