ML060450731
| ML060450731 | |
| Person / Time | |
|---|---|
| Site: | Callaway  |
| Issue date: | 02/14/2006 |
| From: | William Jones NRC/RGN-IV/DRP/RPB-B |
| To: | Naslund C Union Electric Co |
| References | |
| IR-05-005 | |
| Download: ML060450731 (57) | |
See also: IR 05000483/2005005
Text
February 14, 2006Charles D. Naslund, Senior Vice President and Chief Nuclear Officer
Union Electric Company
P.O. Box 620
Fulton, MO 65251 SUBJECT:CALLAWAY PLANT - NRC INTEGRATED INSPECTION REPORT 05000483/2005005Dear Mr. Naslund:
On December 31, 2005, the NRC completed an inspection at your Callaway Plant. Theenclosed report documents the inspection findings which were discussed on January 6, 2006,
with you and other members of your staff.This inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.
Within these areas, the inspection consisted of selected examination of procedures and
representative records, observations of activities, and interviews with personnel.Based on the results of this inspection, the NRC has determined that one Severity Level IVviolation of NRC requirements occurred. The NRC has also identified six additional issues thatwere evaluated under the risk significance determination process as having very low safety
significance (Green). The NRC has determined that there are four violations associated withthe significance determination process issues. In addition, licensee-identified violations whichwere determined to be of very low safety significance are listed in the report. All of the
violations are being treated as noncited violations (NCVs), consistent with Section VI.A of the
Enforcement Policy. The NCVs are described in the subject inspection report. If you contest
these violations or significance of these NCVs, you should provide a response within 30 days of
the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the
Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza
Drive, Suite 400, Arlington, Texas 76011; the Director, Office of Enforcement, U.S. NuclearRegulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at theCallaway Plant facility.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 made available electronically for public inspectionin the NRC Public Document Room or from the Publicly Available Records component of
NRC'sdocument system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Union Electric Company-2-Should you have any questions concerning this inspection, we will be pleased to discuss themwith you. Sincerely, /RA/William B. Jones, ChiefProject Branch B
Division of Reactor ProjectsDocket: 50-483License: NPF-30Enclosure: NRC Inspection Report 05000483/2005005 w/attachment: Supplemental Informationcc w/enclosureProfessional Nuclear Consulting, Inc.
19041 Raines Drive
Derwood, MD 20855John O'Neill, Esq.Shaw, Pittman, Potts & Trowbridge
2300 N. Street, N.W.
Washington, DC 20037Mark A. Reidmeyer, Regional Regulatory Affairs Supervisor
Regulatory Affairs
AmerenUE
P.O. Box 620
Fulton, MO 65251Missouri Public Service CommissionGovernor's Office Building
200 Madison Street
P.O. Box 360
Jefferson City, MO 65102Mike Wells, Deputy DirectorMissouri Department of Natural Resources
P.O. Box 176
Jefferson City, MO 65102Rick A. Muench, President and Chief Executive Officer
Wolf Creek Nuclear Operating Corporation
P.O. Box 411
Burlington, KS 66839Dan I. Bolef, PresidentKay Drey, Representative
Board of Directors Coalition
for the Environment
6267 Delmar Boulevard
University City, MO 63130Les H. Kanuckel, ManagerQuality Assurance
AmerenUE
P.O. Box 620
Fulton, MO 65251Director, Missouri State Emergency Management Agency
P.O. Box 116
Jefferson City, MO 65102-0116Scott Clardy, DirectorSection for Environmental Public Health
P.O. Box 570
Jefferson City, MO 65102-0570
Union Electric Company-3-Keith D. Young, ManagerRegulatory Affairs
AmerenUE
P.O. Box 620
Fulton, MO 65251David E. Shafer Superintendent, Licensing
Regulatory Affairs
AmerenUE
P.O. Box 66149, MC 470
St. Louis, MO 63166-6149Certrec Corporation4200 South Hulen, Suite 630
Fort Worth, TX 76109Chief, Radiological Emergency Preparedness Section
Kansas City Field Office
Chemical and Nuclear Preparedness
and Protection Division
Dept. of Homeland Security
9221 Ward Parkway
Suite 300
Kansas City, MO 64114-3372
Union Electric Company-4-Electronic distribution by RIV:Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)Senior Resident Inspector (MSP)Branch Chief, DRP/B (WBJ)Senior Project Engineer, DRP/B (RAK1)Team Leader, DRP/TSS (RLN1)RITS Coordinator (KEG)Regional State Liaison Officer (WAM)DRS STA (DAP)J. Dixon-Herrity, OEDO RIV Coordinator (JLD)ROPreports
CWY Site Secretary (DVY)SUNSI Review Completed: __wbj_ADAMS: Yes G No Initials: ___wbj__ Publicly Available
G Non-Publicly Available
G Sensitive Non-SensitiveR:\_REACTORS\_CW\2005\CW2005-05RP-MSP.wpd RI:DRP/BSRI:DRP/BC:DRS/EB2C:DRS/EB1DEDumbacherMSPeckLJSmithJAClark E - WBJones E - WBJones GDReplogle for /RA/2/9/062/9/052/13/052/13/05C:DRS/PSBC:DRS/OBC:DRP/BMPShannonATGodyWBJones /RA/ /RA/ /RA/2/13/052/13/052/14/05OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
Enclosure-1-ENCLOSUREU.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket:50-483 License:NPF-30
Report No.:05000483/2005005
Licensee:Union Electric Company
Facility:Callaway Plant
Location:Junction Highway CC and Highway O Fulton, Missouri Dates:September 24 through December 31, 2005
Inspectors:M. S. Peck, Senior Resident InspectorD. E. Dumbacher, Resident Inspector
R. W. Deese, Senior Resident Inspector
B. D. Baca, Health Physicist
P. J. Elkmann, Emergency Preparedness Inspector
T. F. Stetka, Senior Operations Engineer
M. E. Murphy, Senior Operations Engineer
J. F. Drake, Operations EngineerApproved By:W. B. Jones, Chief, Project Branch B
Enclosure-2-SUMMARY OF FINDINGSIR 05000483/2005005; 09/24 - 12/31/2005; Callaway Plant: Equipment Alignment, FireProtection, Personnel Performance During Nonroutine Plant Evolutions, Permanent Plant Mods,Refueling & Outage Activities, Licensed Operator Requal Program, and Emergency Plan &
Emergency Action Level Change.
This report covered a 3-month inspection by region based reactor inspectors and resident
inspectors. One Severity Level IV noncited violation, four Green noncited violations, and two
Green findings were identified. The significance of most findings is indicated by their color
(Green, White, Yellow, Red) using Inspection Manual Chapter 0609, "Significance
Determination Process." Findings for which the significance determination process does not
apply may be Green or assigned a severity level after
NRC management review. The NRC'sprogram for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG 1649, "Reactor Oversight Process," Revision 3, dated July 2000.A. Inspector-Identified and Self-Revealing FindingsCornerstone: Initiating Events
- Green. The inspectors determined that the failure to adhere to ANSI/ANS 3.5-1998, asendorsed by Regulatory Guide 1.149, "Nuclear Power Plant Simulation Facilities for Usein Operator Training and License Examinations," Revision 3, October 2001, as
committed to in the Callaway Plant Simulation certification dated March 13, 2000, was a
finding. Specifically, the simulator performance testing did not meet the standards
specified in ANSI/ANS 3.5-1998 in that: (1) all required parameters during the simulator
test were not recorded; and (2) simulator to baseline data comparisons were
unavailable.The failure to evaluate and document simulator performance testing is more than minorbecause it affected the Operator Requalification attribute of the Mitigating Systems andInitiating Events cornerstone of reactor safety and is inconsistent with the requirements
of 10 CFR 55.46 in that simulator fidelity issues may not be identified which have the
potential of causing negative training. The finding was considered to be of very low
safety significance because the discrepancies have not yet impacted operator actions in
the plant such that safety-related equipment was made inoperable or that operatorsfailed to properly respond to plant transients. This issue is documented in the facilitylicensee's corrective action program as Callaway Action Request 200503956
(Section 1R11).Cornerstone: Mitigating Systems
- Green. The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B,Criterion V, for the failure to adequately implement work order instructions and a
procedure for the inspection of the containment recirculation sump enclosure. The
licensee's inspections failed to identify a 1.5-inch hole in the sump cover, which could
provide a path for foreign material to enter the containment sump. AmerenUE
completed a detailed inspection of the sump on April 27, 2004, in response to NRC
Enclosure-3-Bulletin 2003-01, "Potential Impact of Debris Blockage on Emergency SumpRecirculation at Pressurized-Water Reactors," but failed to identify the 1.5-inch hole. A
subsequent inspection was performed on November 8, 2005, during Refueling
Outage RF 14 that also did not identify the hole in the containment sump enclosure. This issue was entered into the corrective action program as Callaway Action
Request 200509189. This finding is greater than minor because it is associated with the mitigating systemscornerstone attribute of equipment performance and affects the associated cornerstone
objective to ensure availability and reliability of the containment recirculation sumpemergency core cooling system containment safety function. This finding is of very low
safety significance because the condition was a qualification deficiency confirmed not to
result in loss of function per Part 9900, Technical Assessment, "OperabilityDetermination Process for Operability and Functional Assessment." The cause of thisfinding is related to the crosscutting element of human performance in that personnelfailed to adequately implement a work instruction and procedure in inspecting the
containment sump configuration (Section 1R04). *Green. The inspectors identified a noncited violation of Technical Specification 5.4.1.d,"Fire Protection Program Implementation," associated with seven examples of
inadequately performed continuous fire watches. In September 2005, AmerenUE
provided verbal guidance to fire watch personnel that continuous fire watches may be
met by a 15-minute roving fire patrol. The roving patrol did not ensure adequate
compensatory action for fire areas with degraded detection or suppression capability. As a result, fire watch personnel were not available to promptly detect, report, and
extinguish a fire while still in the incipient stage. AmerenUE did not evaluate this changeto ensure no adverse affect on the ability to achieve and maintain safe shutdown in theevent of a fire. This condition was entered into the corrective action program as
Callaway Action Request 200510325. This finding is greater than minor because inadequate fire watches are associated withthe reactor safety mitigating systems cornerstone attribute to provide protection againstexternal factors and affect the associated cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events toprevent undesirable consequences. This finding is of very low safety significance
because the condition had an adverse affect on the "Fixed Fire Protection Systems"
element of fire watches posted as a compensatory measure for outages or
degradations. A low degradation rating was assigned to this finding as the provision
affected by this finding is expected to display nearly the same level of effectiveness and
reliability. The cause of this finding is related to the crosscutting element of human
performance in that the guidance provided was not adequate to ensure continuous firewatches were appropriately conducted (Section 1R05).*Green. The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B,Criteria V, "Instructions, Procedures, and Drawings," associated with an inadequate
engineering procedure used for the verification of design calculations. The inadequate
procedure resulted in a nonqualified, nonsafety-related engineering calculation used to
demonstrate that the safety-related containment recirculation sump valves were capable
Enclosure-4-of performing the safety function described in the design bases. The performancedeficiency associated with this finding involved the failure of engineering personnel to
only use qualified calculations for safety-related applications. This finding was entered
into the Corrective Action Program as Callaway Action Request 200509849.This finding is greater than minor because, if left uncorrected, this finding would becomea more significant safety concern. This finding is determined to have very low safety
significance because this finding involves a design deficiency confirmed not to result in
loss of operability per Part 9900, Technical Guidance, "Operability DeterminationProcess for Operability and Functional Assessment." The cause of this finding is relatedto the crosscutting element of human performance in that the procedure did not ensurethe calculations were qualified to support a design basis function of a safety-related
component (Section 1R17).Cornerstone: Barrier Integrity
- Green. The inspectors identified a noncited violation of Technical Specification 5.4.1.a,"Procedures," after AmerenUE Operations personnel failed to maintain the reactor
coolant system heatup and cooldown temperature limits on two occasions. OnNovember 7, 2005, plant operators decreased the reactor cool
ant system pressurizersurge line temperature 260F in a one-hour period. The operators conducted the rapidcooldown after several containment lead shield blanket polyvinylchloride covers located
on the pressurizer surge line melted. On November 8, 2005, plant operators increased
the surge line temperature about 175F in a one-hour period. Plant TechnicalSpecification 3.4.3, "RCS [reactor coolant system] Pressure and Temperature (P/T)Limits," and plant procedures required reactor coolant system component temperaturechanges (except the pressurizer) be limited to 100F in one hour. This finding wasplaced in the Corrective Action Program as Callaway Action Requests 200509487
and 200509143. This finding was greater than minor because it is associated with the reactor safetybarrier integrity cornerstone attribute of equipment performance and affects the
associated cornerstone objective to ensure reasonable assurance that the reactor
coolant system piping barrier will protect the public from radionuclide releases causedby accidents or events. This finding is determined to have very low safety significance
because an engineering evaluation concluded that the temperature transient did notsignificantly increase the likelihood of a loss of reactor coolant system inventory ordegrade the ability to terminate a leak path. The cause of this finding is related to thecrosscutting element of human performance in that the reactor coolant system
pressurizer surge line heatup and cooldown limits were exceeded (Section 1R14).Cornerstone: Emergency Preparedness
- Severity Level IV. The inspectors identified a violation of 10 CFR 50.54(q) forimplementing a change to emergency action levels which decreased the effectiveness
of the emergency plan. Emergency Implementing Plan Procedure EIP-ZZ-00101,
"Classifying the Emergency," Revision 33, limited application of emergency action
Enclosure-5-Level 3E, "Fire within Protected Area Boundary NOT Extinguished with 15 minutes ofVerification," so that fires in some plant areas which would be classified under the
previous revision may no longer be classifiable.Implementation of changes to emergency action levels which decreased theeffectiveness of the emergency plan was a performance deficiency. The finding is more
than minor because removal of a classifiable condition from licensee emergency action
levels has the potential to impact safety, and licensee implementation of a change to
their emergency plan, which decreases the effectiveness of the plan without prior NRC
approval, impacts the regulatory process. This finding is a violation of 10 CFR 50.54(q).
The licensee has entered this issue into their corrective action system as Corrective
Action Report 200510162 (Section 1EP4).Cornerstone: Miscellaneous
- Green. The inspectors identified a finding after AmerenUE implemented less thanadequate risk management controls of the spent fuel pool water inventory. On
September 29, 2005, the core had been off-loaded to the spent fuel pool and thetransfer canal weir wall removed. The inspectors identified that the shutdown safety
plan did not establish specific controls for reactor refueling canal transfer tube
Valve ECV-995, which isolated the fuel transfer canal from the containment cavity or
provided for installation of the associated fuel transfer canal flange. Valve ECV-995 was
closed but was not identified in the shutdown risk management system and did not haveadministrative controls established through the shutdown risk plan. NRC InformationNotice 2005-16, "Outage Planning and Scheduling - Impacts on Risk," emphasized that
most spent fuel pool events had a common thread of human error and involved
equipment misalignment. This finding was entered into the Corrective Action Program
as Callaway Action Requests 200507593 and 200507693.
This finding is greater than minor because, if left uncorrected, it would have become a
more significant safety concern. Because Manual Chapter 0609, "Significance
Determination Process," does not specifically address findings related to the spent fuel
pool inventory, this finding is determined to have very low safety significance based on
NRC management review with input from a senior reactor analyst. The reviewconsidered that the procedure used to manipulate the valve was not in use during thisperiod and that borated water makeup capabilities were available to the spent fuel pool. No violation of regulatory requirements occurred (Section 1R20).B.Licensee-Identified ViolationsViolations of very low significance, which were identified by the licensee, have beenreviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensee's corrective action program. These violations and
corrective action tracking numbers are listed in Section 4OA7 of this report.
Enclosure-6-REPORT DETAILSSummary of Plant StatusThe Callaway Plant was shut down for Refueling Outage 14 at the beginning of the inspectionperiod. Outage work included steam generator replacement and a major turbine overhaul.
AmerenUE completed the refueling outage and synchronized the generator to the grid onNovember 19, 2005. The licensee returned to full power operations on November 23, 2005.
AmerenUE operated the plant at full power for the remainder of the inspection period. 1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection (71111.01) a.Inspection ScopeReadiness for Seasonal SusceptibilitiesThe inspectors completed a review of the licensee's readiness of seasonalsusceptibilities involving extreme low temperatures. The inspectors: (1) reviewed plant
procedures, the Final Safety Analysis Report (FSAR), and Technical Specifications (TS)
to ensure that operator actions defined in adverse weather procedures maintained the
readiness of essential systems; (2) walked down portions of the two systems listedbelow to ensure that adverse weather protection features (heat tracing, space heaters,weatherized enclosures, temporary chillers, etc.) were sufficient to support operability,including the ability to perform safe shutdown functions; (3) evaluated operator staffinglevels to ensure the licensee could maintain the readiness of essential systems requiredby plant procedures; and (4) reviewed the corrective action program to determine if the
licensee identified and corrected problems related to adverse weather conditions. *November 17, 2005: Essential service water pump house, Trains A and B
Documents reviewed by the inspectors included:
- Procedure OTS-ZZ-00007, Plant Cold Weather, Revision 10
- Procedure OTN-QJ-00003, Plant Freeze Protection Heat Tracing Procedure,Revision 3The inspectors completed one sample. b.FindingsNo findings of significance were identified.
Enclosure-7-1R04Equipment Alignment (71111.04)Partial Walkdowns a.Inspection ScopeThe inspectors: (1) walked down portions of three risk important systems and reviewedplant procedures and documents to verify that critical portions of the select ed systemswere correctly aligned; and (2) compared deficiencies identified during the walkdown to
the licensee's FSAR and corrective action program to ensure problems were being
identified and corrected. *October 17, 2005, Emergency diesel generator (EDG), Train A *November 8, 2005, Containment recirculation sump, Train A
- December 21, 2005, Centrifugal charging pump, Train A Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed three samples. b.Finding - Inadequate Inspection of the Containment Recirculation Sump
Introduction: The NRC identified a Green noncited violation (NCV) of 10 CFR Part 50,Appendix B, Criterion V, for the failure to adequately implement work order instructions
and a procedure for inspection of the containment recirculation sump enclosure. The
licensee's inspections failed to identify a 1.5-inch hole in the sump cover which could
provide a path for foreign material to enter into the containment sump emergency core
cooling system (ECCS) containment recirculation sump. Description: On November 8, 2005, the inspectors identified a 1.5-inch hole penetratingthe containment recirculation Sump A ceiling. FSAR Section 6.2.2.1.2.2 stated that "therecirculation sumps are covered with the concrete pads supporting the accumulator
tanks; thus, debris cannot fall directly upon the screening structure." FSAR
Table 6.2.2-1 established a maximum
c-inch gap for the sump screen. The screenprevents the introduction of foreign material and debris that could degrade long-term
core cooling during an ECCS recirculation mode of operation. NRC Bulletin 2003-01,"Potential Impact of Debris Blockage on Emergency Sump Recirculation at Pressurized-
Water Reactors," alerted the licensee to the susceptibility of recirculation sump failures.
AmerenUE's August 8, 2003, response to the bulletin included a commitment to inspect
the containment sumps and verify screen gap tolerances. The Callaway quality control
technicians' detailed inspection on April 27, 2004 (Work Package W229952), did not
identify the 1.5-inch hole. During Refueling Outage RF-14, AmerenUE performed
Procedure OSP-EJ-00003, "Containment Recirculation Sump Inspection," Revision 5,
that required quality control and operations personnel to verify that all sump
penetrations were sealed prior to reactor startup. This inspection performed on
November 8, 2005, did not identify the hole in the containment sump cover.
Enclosure-8-Analysis: The performance deficiency associated with this finding involved licenseepersonnel failure to effectively inspect the containment sump to assure any opening or
gaps in the sump cover were in accordance with the design basis. This finding was
greater than minor because it is associated with the mitigating systems cornerstoneattribute of equipment performance and affects the associated cornerstone objective to
ensure availability and reliability of the containment recirculation sump ECCS safetyfunction. Using the Manual Chapter 0609, "Significance Determination Process,"
Phase 1 Worksheet, this finding is determined to have very low safety significance
because the condition is a qualification deficiency confirmed not to result in loss of
operability per Part 9900, Technical Guidance, "Operability Determination Process forOperability and Functional Assessment." The cause of this finding is related to thecrosscutting element of human performance in that personnel failed to adequatelyimplement a work instruction and procedure for inspecting the containment sump
configuration. Enforcement: The inspectors identified an NCV of 10 CFR Part 50, Appendix B,Criterion V, "Instructions, Procedures, and Drawings," because AmerenUE did not
properly implement work instructions and a test procedure for inspecting the ECCS
containment sump. Contrary to verify conformance ofcontainment Sump A. The corrective actions to restore compliance included repair of
the hole and actions taken to improve inspection techniques. Because of the very low
safety significance and the licensee's action to place this issue in their corrective action
program as Callaway Action Request (CAR) 200509189, this violation is being treated
as an NCV in accordance with Section VI.A.1 of the Enforcement
Policy (NCV 05000483/2005005-01). 1R05Fire Protection (71111.05) a.Inspection ScopeQuarterly InspectionThe inspectors walked down the nine listed plant areas to assess the material conditionof active and passive fire protection features and their operational lineup and readiness.
The inspectors: (1) verified that transient combustibles and hot work activities were
controlled in accordance with plant procedures; (2) observed the condition of fire
detection devices to verify they remained functional; (3) observed fire suppression
systems to verify they remained functional and that access to manual actuators wasunobstructed; (4) verified that fire extinguishers and hose stations were provided at theirdesignated locations and that they were in a satisfactory condition; (5) verified that
passive fire protection features (electrical raceway barriers, fire doors, fire dampers,
steel fire proofing, penetration seals, and oil collection systems) were in a satisfactorymaterial condition; (6) verified that adequate compensatory measures were established
for degraded or inoperable fire protection features and that the compensatory measureswere commensurate with the significance of the deficiency; and (7) reviewed the FSAR
to determine if the licensee identified and corrected fire protection problems.
Enclosure-9-*September 25, 2005, Fire Area RB, Reactor building*November 10, 2005, Fire Area RB, Reactor building
- November 22, 2005, Fire Area A-2, ECCS, Train A
- November 22, 2005, Fire Area A-4, ECCS Rooms, Train A
- November 22, 2005, Fire Area A-9, Residual heat removal (RHR) heatexchanger room, Train A*November 22, 2005, Fire Area A-10, RHR heat exchanger room, Train B*November 30, 2005, Fire Area C-9, Switchgear room, Train A
- November 30, 2005, Fire Area C-10, Switchgear room, Train B
- November 30, 2005, Fire Area D-1, Diesel generator, Train A
Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed nine samples. b.Finding - Failure to Adequately Implement Continuous Compensatory Fire WatchesIntroduction: The inspectors identified a noncited violation of TS 5.4.1.d, "FireProtection Program Implementation," associated with seven examples of inadequatelyperformed continuous fire watches. Description: Procedure APA-ZZ-0703, "Fire Protection Operability Criteria andSurveillance Requirements," required AmerenUE to establish compensatory continuous
watches in specified fire areas as a result of degraded fire detection or suppression
capability. The continuous fire watch is an uninterrupted observation post within a singlefire area. The physical presence of fire watch personnel provides reasonable assurance
that a fire would be prevented through prompt recognition and disposition of fire
hazards. If a fire occurred, despite these efforts, fire watch personnel would promptly
detect, report, and extinguish the fire while still in the incipient st
age. Procedure SDP-KC-00001, "Requirements for and Duties of Compensatory Fire
Watches," Revision 5, required fire watches to maintain watch over the entire assigned
space with a minimum of patrolling. In September 2005, AmerenUE provided verbal guidance to fire watch personnel thatcontinuous watch requirements may be met by a 15-minute roving fire patrol. Callaway
Facility Operating License, Amendment 169 (5) (d), required that changes thatadversely affect the ability to achieve and maintain safe shutdown in the event of a firereceive prior NRC approval. The inspectors concluded that reducing continuous watchrequirements to a 15-minute roving patrol adversely affected the ability to achieve and
Enclosure-10-maintain safe shutdown in the event of a fire. The inspections identified sevenexamples of compensatory continuous fire watches where one fire watch person was
assigned simultaneously to multiple fire areas and building levels:Date Fire ImpairmentNumberContinuous Fire Areas Concurrently Watched by a Single IndividualSeptember 512260A-1, A-8, A11, A12, A-24, A-25September 612260A-1, A-8, A11, A12, A-24, A-25September 712260A-1, A-8, A11, A12, A-24, A-25September 812260A-1, A-8, A11, A12, A-24, A-25September 2512269A-1, A-8, A11, A12, A-24, A-25September 2612269A-1, A-8, A11, A12, A-24, A-25September 3012244A-1, A-13, A-14, A-15Analysis: The performance deficiency associated with this finding involved the failure ofAmerenUE to establish adequate continuous fire watches. This finding is greater than
minor because this finding was associated with the reactor safety mitigating systems
cornerstone attribute to provide protection against external factors and affects the
associated cornerstone objective to ensure the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable consequences. Theinspectors used Manual Chapter 0609, Appendix F, "Fire Protection Significance
Determination Process," to analyze this finding because the condition had an adverse
affect on the "Fixed Fire Protection Systems" element of fire watches posted as a
compensatory measure for outages or degradations. A low degradation rating was
assigned to this finding as the provision affected by this finding is expected to display
nearly the same level of effectiveness and reliability. Using Manual Chapter 0609, Appendix F, this finding is determined to have very low safety significance. The
inspectors concluded that the new guidance created situations which resulted ininadequate compensatory fire watch coverage. The cause of this finding is related to
the crosscutting element of human performance in that the guidance was not adequateto ensure continuous fire watches were appropriately implemented. Enforcement: Callaway Plant Technical Specification 5.4.1.d, "Fire Protection ProgramImplementation," required that the Fire Prevention Program be implemented andmaintained per written procedures. The Fire Prevention Program requirements for fire
watches were implemented by Procedure SDP-KC-00001, "Requirements for and Duties
of Compensatory Fire Watches," Revision 5. Procedure SDP-KC-00001 established a
requirement for compensatory continuous watches within specified fire areas as a result
of degraded fire detection or suppression capability. Contrary toProcedure SDP-KC-00001 and the fire program, AmerenUE failed to perform
compensatory continuous watches within certain specified fire areas with degraded fire
detection or suppression capability between September 5 and 30, 2005. Because thisfinding is of very low safety significance and was entered into the licensee's corrective
Enclosure-11-action program (CAR 200510325), it is being treated as an NCV, consistent withSection VI.A of the NRC Enforcement Policy (NCV 05000483/2005005-02). 1R07Heat Sink Performance (71111.07) a.Inspection ScopeThe inspectors reviewed licensee programs, verified performance against industrystandards, and reviewed critical operating parameters and maintenance records for the
containment cooler heat exchangers. The inspectors verified that: (1) performance
tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for
problems or errors; (2) the licensee utilized the periodic maintenance method outlined inElectric Power Research Institute NP-7552, "Heat Exchanger Performance Monitoring
Guidelines;" (3) the licensee properly utilized biofouling controls; (4) the licensee's
heatexchanger inspections adequately assessed the state of cleanliness of their tubes, and
(5) the heat exchanger was correctly categorized under the maintenance rule. Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample. b.Findings - Indeterminate Containment Cooler Operability and Heat Removal CapabilityIntroduction: An unresolved item was identified for containment cooler heat removalcapability. AmerenUE will provide the inspectors additional testing results to completethe inspection. This issue will remain unresolved pending additional review by theinspectors. No analysis or enforcement reviews were performed for this unresolved
item.Description: The inspectors reviewed available containment cooler testing data butwere not able to confirm that the heat exchangers were capable of the design bases
heat removal duty. FSAR Section 6.2.1.3, "Mass and Energy Release Analyses for
Postulated Loss-of-Coolant Accidents," and Section 6.2.1.4, "Mass and Energy ReleaseAnalysis for Postulated Secondary Pipe Ruptures Inside Containment," stated that acontainment cooler duty of 141 million British Thermal Units per hour, at 277F wasused in the accident analysis. TS Surveillance Bases 3.6.6.7, "Containment Spray andCooling Systems," stated that the heat removal capability of each cooler train wasverified on an 18-month frequency. TS bases, Figure B.3.6.6-1, "Containment CoolerHeat Removal Minimum Cooling Flow Rate," established the minimum heat removal
capability as a function of essential service water (ESW) flow, assuming no fouling, tomeet design bases requirements. Plant engineering monitored ESW flow but not heat
removal capability. AmerenUE committed, by letter, "Response to Generic Letter 89-13,Service Water System Problems Affecting Safety Related Equipment," January 29,
1990, to verify the heat transfer capability of all safety-related heat exchangers cooledby ESW. In addition, AmerenUE also committed to trend and compare the containment
cooler heat removal rates to the design requirements to promote identification of
degraded cooling equipment. Title 10 of the Code of Federal Regulations, Part 50,
Appendix B, "Test Control," required AmerenUE to establish a test program to assure
Enclosure-12-that the containment cooler's performance satisfactorily met acceptance limitsestablished in applicable design documents. Based on the information provided by
AmerenUE, the inspectors were not able to conclude that the containment coolers werecapable of removing design basis heat loads. AmerenUE identified high differential pressure across the ESW side of containmentCooler SGN01A on May 17, 2004 (Refueling Outage 14 Work Document P701990).
The high differential pressure was indicative of heat exchanger degradation due to
macrofouling. AmerenUE restarted and operated the plant until September 17, 2005,without adequately assessing the affect of fouling on heat exchanger performance.
AmerenUE cleaned the heat exchanger during Refueling Outage 14. AmerenUE did not
perform testing prior to the cleaning to determine if any additional degradation had
occurred during the 18-month operating cycle. The inspectors were not able to verify,based on the documentation reviewed, that the heat exchanger was capable ofperforming the design bases function during Cycle 14. This issue is considered
unresolved pending additional NRC review of AmerenUE containment cooler testing(Unresolved Item 05000483/2005005-03). 1R11Licensed Operator Requalification Program (71111.11Q and 71111.11B) .1Quarterly Inspections a.Inspection ScopeThe inspectors observed testing and training of senior reactor operators and reactoroperators to identify deficiencies and discrepancies in the training, to assess operator
performance, and to assess the postexercise critique. The inspectors observed a "Just
In-Time Reactor Startup" training scenario conducted on November 13, 2005. Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample. b.FindingsNo findings of significance were identified. .2Biennial Inspection a.Inspection ScopeTo assess the performance effectiveness of the licensed operator requalificationprogram, the inspectors conducted both on-site and in-office reviews involving personnel
interviews, operating and written examinations, and operating examination activities. During the on-site review, the inspectors interviewed five licensee personnel, consistingof three instructors, one operator and a training supervisor, to determine their
understanding of the policies and practices for administering requalification
Enclosure-13-examinations. The inspectors also reviewed operator performance on the written andoperating examinations. These reviews included observations of portions of the
operating examination by the inspectors. The operating examinations observed
included job performance measures and four scenarios that were used in the current
biennial requalification cycle. These observations allowed the inspectors to
assess thelicensee's effectiveness in conducting the operating test to ensure operator mastery of
the training program content. The results of these examinations were reviewed to determine the effectiveness of thelicensee's appraisal of operator performance and to determine if feedback of
performance analysis into the requalification training program was being accomplished.
The inspectors interviewed members of the training department and reviewed minutes
of training review group meetings to assess the responsiveness of the licensed operator
requalification program in incorporating the lessons learned from both plant and industry
events. Examination results were also assessed to determine if they were consistent
with the guidance contained in NUREG 1021, "Operator Licensing ExaminationStandards for Power Reactors," Revision 9, and NRC Manual Chapter 0609, Appendix I,"Operator Requalification Human Performance Significance Determination Process."Additionally, the inspectors assessed the Callaway Plant-referenced simulator forcompliance with 10 CFR 55.46, "Simulator Facilities." This assessment incl
uded theadequacy of the licensee's simulation facility for use in operator licensing examinationsand for satisfying experience requirements as prescribed by 10 CFR 55.46. In addition,
the inspectors reviewed selected applicant personnel qualitative statements (NRC
Form 398) to verify their accuracy. During the Form 398 reviews, the inspectors noted
that several applicants were given credit for reactivity and control manipulations on the
simulator instead of on the actual plant. While this simulator usage is permitted by
10 CFR 55.46, the simulator must meet the standards of fidelity as required by
10 CFR 55.46(c)(2). Based on this observation and the requirements of 10 CFR 55.46,
the inspectors expanded their review of the simulator testing. This review expansion
included a review of the simulator annual performance test book. The inspectors
reviewed a sample of simulator performance test records (transient tests, surveillance
tests, and malfunction tests), simulator deficiency report records, and processes for
ensuring simulator fidelity commensurate with 10 CFR 55.46. The inspectors reviewed
selected simulator deficiency reports generated by the licensee that did not result in
changes to the configuration of the simulator to assess the responsiveness of the
licensee's simulator configuration management program. The inspectors also
interviewed members of the licensee's simulator configuration control group as part of
this review. During the in-office review, the inspectors evaluated whether the written examinationwas developed and administered in accordance with the standards described in
NUREG 1021 and evaluated any issues identified in accordance with NRC M anualChapter 0609, Appendix I. The written examination review was focused on quality
aspects of the examination, such as discrimination validity, examination question
psychometric quality, and examination integrity.
Enclosure-14- b.Findings 1.Evaluation of the Written ExaminationAs a result of the review of the written requalification examinations, the inspectorsidentified that the quality of the examinations developed by the licensee appeared to notmeet the guidance set forth in NUREG 1021, ES-602, Attachment 1, Section B, "Open-Reference Guidelines." The term "open reference" means that the candidates are
allowed to use any reference to assist them when taking the examination.Since the operators are allowed to use examination question references while taking theexamination, test questions should be developed that do more than test for mere recall
and/or memorization. Open-reference questions should have the operators
demonstrate an understanding of an issue by using their knowledge to address real-life
situations and problems. The NUREG further states with regard to direct look upquestions that removing from the stem of the question any information that cues the
operator to the answer's location does not make the question acceptable. With regard to the open-reference questions, the NUREG also addresses "DirectLookup" questions. Direct lookup questions only test memory because the information
is readily available. This is a less valid means of testing candidate knowledge and only
demonstrates that a candidate knows where to find information. Therefore, the
discrimination validity of the question is critical to differentiate the safe operator from the
unsafe operator.Additionally, other than demonstrating that a candidate knows where to find information,the licensee's biennial requalification examinations appeared to not test the
understanding or analysis of the information that would be applied on the job. These
issues will be reviewed as Unresolved Item (URI)05000483/2005005-04, Adequacy ofthe Biennial Requalification Written Examination (CAR 200600528). 2.Simulation Facility PerformanceIntroduction: During a review of the simulator annual performance test book, the inspectors identified a Green finding for the failure to conduct simulator performance
testing in accordance with ANSI/ANS 3.5, "Nuclear Power Plant Simulators for use in
Operator Training and Examination," 1998. Description: A review of the Steady State and Normal Evolution tests contained in theannual performance test book for the simulator revealed that the licensee did not
compare all of the required parameters listed in ANSI 3.5-1998 to actual plant data; specifically, Thot, Tcold, core megawatt thermal, steam flow, feed flow, letdown flow,
charging flow, and turbine first stage pressure. In lieu of this comparison, the licensee
utilized an "expert panel review" to determine if the simulator operation mimics theactual plant. When the inspectors requested the baseline data to support the analysis
documentation, the licensee was unable to provide the data. The licensee stated thatthe analysis was done by a panel of experts and that the signature on the meetingminutes constituted the required analysis and baseline data. The 1998 version of
Enclosure-15-ANSI/ANS 3.5, requires that the annual simulator performance tests be conducted suchthat the key parameters listed in Appendix B of this standard are recorded and thatthese records be compared to actual or reference plant data (if available) or engineering
data from the FSAR. If such engineering data is not available in the FSAR, the standard
permits the use of data from subject matter expert estimates to determine acceptability
of the test. Analysis: The inspectors determined that the failure to adhere to ANSI/ANS 3.5-1998,as endorsed by Regulatory Guide 1.149, "Nuclear Power Plant Simulation Facilities forUse in Operator Training and License Examinations," Revision 3, October 2001, as
committed to in the Callaway Plant Simulation certification dated March 13, 2000, was a
performance deficiency. Specifically, the simulator performance testing did not meet the
standards specified in ANSI/ANS 3.5-1998 in that: (1) all required parameters during
the simulator test were not recorded; and (2) simulator to baseline data comparisons
were unavailable.The NRC has determined that traditional enforcement does not apply because the issuedid not have any actual safety consequence or potential for affecting the
NRC'sregulatory function and did not result in any willful violation of NRC requirements orlicensee procedures. The performance deficiency is more than minor because it
affected the ability of the simulator transient tests to detect fidelity issues with the
simulator and affects the Human Performance (Human Error) attribute of the Initiating
Events and Mitigating Systems cornerstones. Enforcement: No violation of regulatory requirements occurred. The examinersdetermined that the finding did not represent a noncompliance because Callaway Plantperformed some testing even though the testing was not sufficient in scope and
because no actual events have occurred that could be attributed to a lack of simulator
fidelity testing: Finding (FIN)05000483/2005005-05, Failure to Conduct Simulator
Testing in Accordance with ANSI/ANS 3.5-1998 (CAR 200600527). 3.Adequacy of Plant-Referenced Simulator to Conform with Simulator Requirements forReactivity and Control Manipulation CreditsAs the result of reviewing NRC Form 398, the inspectors noted that the licenseeused the simulator to meet reactivity and control manipulation experience requirements
for initial operator and senior operator license applicants in accordance with
10 CFR 55.46(c)(2)(ii). For the manipulations, the licensee used a single page "sign-off"
sheet for documentation. To use the simulator for reactivity and control manipulationcredit, the regulation requires that significant control manipulations are completedwithout procedural exceptions, simulator performance exceptions, or deviation from the
approved training scenario sequence. Furthermore, the ANSI standard requires that
these items be performed without offsets in the simulator and without time-compression
techniques that expected alarms are generated as required in real time with no
unexpected alarms generated during the scenario sequence. The documentationprovided could not be used to verify each of the requirements as specified in the
regulations and standards.
Enclosure-16-The safety significance of this issue could be more than minor due to the apparentfailure to meet the requirements of 10 CFR 55.46(c)(2)(ii) with regard to assuring
maintenance of the plant referenced simulator fidelity. Accordingly, a URI was opened
pending further review of the simulator in subsequent inspections. The licensee entered
this issue into their corrective action program as CAR 200600529: URI 05000483/
200505-06, Adequacy of Plant-Referenced Simulator to Conform with Simulator
Requirements for Reactivity and Control Manipulation Credits.1R12Maintenance Effectiveness (71111.12Q) a.Inspection ScopeThe inspectors reviewed the two listed maintenance activities to: (1) verify theappropriate handling of structures, systems, and components (SSC) performance orcondition problems; (2) verify the appropriate handling of degraded SSC functional
performance; (3) evaluate the role of work practices and common cause problems; and
(4) evaluate the handling of SSC issues reviewed under the requirements of the
maintenance rule, 10 CFR Part 50, Appendix B, and the TSs. *September 30, 2005, CAR 200507636, Missing spring in ventilation doorsolenoid lock assembly*August 2, 2005, CAR 200505344, Fuel building roll-up door
Documents reviewed by the inspectors included:
- Procedure EDP-ZZ-01128, Maintenance Rule Program, Revision 6
- Maintenance Rule Program
The inspectors completed two samples. b.FindingsNo findings of significance were identified.1R13Maintenance Risk Assessments and Emergent Work Evaluation (71111.13) a.Inspection Scope
Risk Assessment and Management of Risk
The inspectors reviewed the three listed assessment activities to verify: (1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and
licensee procedures prior to changes in plant configuration for maintenance activities
and plant operations; (2) the accuracy, adequacy, and completeness of the information
considered in the risk assessment; (3) that the licensee recognizes, and/or enters as
Enclosure-17-applicable, the appropriate licensee-established risk category according to the riskassessment results and licensee procedures; and (4) the licensee identified and
corrected problems related to maintenance risk assessments.*October 17, 2005, Essential power, Train B, planned outage, in-office review
- October 31, 2005, Spent fuel pool time-to-boil method, in-office review
- November 21, 2005, Unplanned emergent maintenance on ESW inlet isolationValve EFHV52, in-office reviewDocuments reviewed by the inspectors included:
- Procedure EDP-ZZ-01128, Maintenance Rule Program, Revision 6
- Procedure EDP-ZZ-01129, Callaway Plant Risk Assessment, Revision 8
- Procedure ODP ZZ 00001, Operations Department - Code of Conduct,Revision 23The inspectors completed three samples.
Emergent Work Control
The inspectors: (1) verified that the licensee performed actions to minimize theprobability of initiating events and maintained the functional capability of mitigatingsystems and barrier integrity systems; (2) verified that emergent work-related activitiessuch as troubleshooting, work planning/scheduling, establishing plant conditions,
aligning equipment, tagging, temporary modifications (TMs), and equipment restoration
did not place the plant in an unacceptable configuration; and (3) reviewed the FSAR todetermine if the licensee identified and corrected risk assessment and emergent work
control problems. *October 17, 2005, Essential power, Train B, planned outage. The inspectorsobserved compensatory risk mitigation actions from the control building and
completed an in-office review.*November 21, 2005, ESW inlet isolation Valve EFHV52. The inspectorsobserved compensatory risk mitigation actions from the control building and
completed an in-office review.Documents reviewed by the inspectors included:
- Nuclear Management and Resource Council 93-01, Industry Guidelines forMonitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 3 *Procedure EDP-ZZ-01129, Callaway Plant Risk Assessment, Revision 9
Enclosure-18-The inspectors completed two samples. b.FindingsNo findings of significance were identified.1R14Personnel Performance During Nonroutine Plant Evolutions (71111.14) a.Inspection ScopeThe inspectors: (1) reviewed operator logs, plant computer data, and/or strip charts forthe below listed evolutions to evaluate operator performance in coping with nonroutineevents and transients; (2) verified that operator actions were in accordance with the
response required by plant procedures and training; (3) attended and/or reviewed
postevent critic meetings; and (4) verified that the licensee has identified and
implemented appropriate corrective actions associated with personnel performance
problems that occurred during the nonroutine evolutions sampled. *November 7, 2005, CAR 200509143, Rapid pressurizer surge line cooldown dueto melting lead blankets*November 8, 2005, CAR 200509191, Pressurizer surge line heatup rateexceeded*November 14, 2005, CAR 200509345, Unplanned securing of the steam dumpsand subsequent reactor coolant system (RCS) heatup with initiating RCStemperature at 340F*November 15, 2005, Plant cooldown to remove a shim on Steam Generator D
Documents reviewed by the inspectors included:
- Procedure OTG-ZZ-00001, Plant Heatup, Cold Shutdown to Hot Standby,Revision 46*Procedure APA-ZZ-00500, Corrective Action Program, Revision 38
- Procedure OSP-BB-00007, RCS Heatup and Cooldown Limitations, Revision 9
The inspectors completed four samples.
Enclosure-19- b.FindingFailure to Follow Procedures Resulted in Violation of RCS Cooldown and Heatup RateLimitsIntroduction. The inspectors identified a Green NCV of TS 5.4.1.a, "Procedures," afterAmerenUE operations personnel failed to maintain the RCS temperature limits on two
occasions. Description. On November 7, 2005, plant operators terminated a plant heatup anddecreased the RCS pressurizer surge line temperature 260F in one hour. Theoperators initiated the rapid cooldown by isolating pressurizer auxiliary spray, resulting inan in-surge of cooler RCS water. The operators conducted the rapid cooldown after
several containment lead shield blanket polyvinylchloride covers in containment
unexpectedly melted. The shield blankets had not been removed from the uninsulatedpressurizer surge line prior to plant heatup due to a work scheduling error. The licensee
identified a second example of excessive surge line temperature on November 8, 2005.
Plant operators increased the surge line temperature about 175F in one hour during aplant heatup. TS 3.4.3, "RCS Pressure and Temperature (P/T) Limits," required temperature changesof all RCS components (except the pressurizer) be limited to 100F in one hour. TheTS Bases defined the surge line as part of the RCS. General Operating
Procedure OTG-ZZ-00001, "Plant Heatup, Cold Shutdown to Hot Standby," required
operating personnel maintain greater than 5 gpm auxiliary spray and a pressurizeroutsurge. Procedure OSP-BB-00007, "RCS Heatup and Cooldown Limitations,"
required that RCS temperature changes not exceed 100F in one hour duringcooldown/heatup evolutions. The inspectors identified that operations personnel failedto recognize the applicability of the TS and apply the appropriate TS action statement. Analysis: The performance deficiency associated with this finding involved failure ofoperations personnel to follow established procedures and recognize the appropriate TS
action. This finding was greater than minor because it is associated with the reactor
safety barrier integrity cornerstone attribute of equipment performance and affects the
associated cornerstone objective to ensure reasonable assurance that the RCS piping
barrier will protect the public from radionuclide releases caused by accidents or events. Using Manual Chapter 0609, "Significance Determination Process," Appendix G,
"Shutdown Operations," this finding was determined to have very low safety significance
because, based on the engineering evaluation of RCS thermal stress resulting from the
temperature transients, the condition did not significantly increase the likelihood of a
loss of RCS inventory and did not degrade the licensee's ability to terminate a leak path.The cause of this finding is related to the crosscutting element of human performance
because of personnel failure to follow procedures. Enforcement: TS 5.4.1.a, "Procedures," required that written procedures beestablished, implemented, and maintained covering the activities specified in
Appendix A, "Typical Procedures for Pressurized Water Reactors," of Regulatory
Guide 1.33, "Quality Assurance Program Requirements (Operation)," February 1978.
Enclosure-20-Regulatory Guide 1.33, Appendix A, Section 2a, required general plant operatingprocedures for cold shutdown to hot standby to be implemented. Entry into TS 3.4.3,
"RCS Pressure and Temperature (P/T) Limits," action was required when an RCS
component temperature transient exceeded 100F cooldown and or heatup limit within aone-hour period. Callaway Procedure OSP-BB-00007, "RCS Heatup and Cooldown
Limitations," required that RCS temperature changes shall not exceed 100F in onehour during cooldown or during heatup evolutions. Contrary to these requirements, on
November 7 and 8, 2005, operations personnel did not maintain the RCS temperature
rate less than 100F within one hour. Because of the very low safety significance andthe licensee's action to place this issue in their corrective action program as
CARs 200509487 and 200509143, this violation is being treated as an NCV in
accordance with Section VI.A.1 of the Enforcement Policy (NCV 50-483/2005005-07).1R15Operability Evaluations (71111.15) a.Inspection ScopeThe inspectors: (1) reviewed plant status documents such as operator shift logs,emergent work documentation, deferred modifications, and standing orders to
determine if an operability evaluation was warranted for degraded components;(2) referred to the FSAR and design basis documents to review the technical adequacy
of licensee operability evaluations; (3) evaluated compensatory measures associatedwith operability evaluations; (4) determined degraded component impact on any TSs;(5) used the significance determination process to evaluate the risk significance of
degraded or inoperable equipment; and (6) verified that the licensee has identified and
implemented appropriate corrective actions associated with degraded components. *Operability Determination 200509277, Overpressurization of the turbine-drivenauxiliary feedwater pump (TDAFP) during the backleakage test of its dischargecheck valve*Operability Determination 200509374, Pressurizer power-operated relief valvestroke time basis*Operability Determination 200509368, Excessive stroke time of feedwaterisolation Valve AEFV0040*Operability Determination 200505062, Insufficient time to transfer ECCS andcontainment spray to cold leg recirculation*Operability Determination 2005003773, Degraded containment cooler heatremoval capabilityThe inspectors completed five samples. b.FindingsNo findings of significance were identified.
Enclosure-21-1R16Operator Workarounds (71111.16) a.Inspection ScopeSelected Operator WorkaroundsThe inspectors reviewed the two listed operator workarounds to: (1) determine if thefunctional capability of the system or human reliability in responding to an initiating eventis affected; (2) evaluate the effect of the operator workaround on the operator's ability toimplement abnormal or emergency operating procedures; and (3) verify that the
licensee has identified and implemented appropriate corrective actions associated with
operator workarounds. *November 23, 2005, In-office review of the degradation of main steam line Monitor 16*November 23, 2005, Maintenance repair of Bistable SB069 and permissiveindicating panelDocuments reviewed by the inspectors included:
- December 2005, Operator Work Around and Burdens list
- Procedure APA-ZZ-00018, Conduct of Operations - Quality Control, Revision 7
- Procedure ODP-ZZ-00001, Operations Department - Code of Conduct,Revision 25The inspectors completed two samples.
Cumulative Review of the Effects of Operator Workarounds
The inspectors reviewed the cumulative effects of operator workarounds to determine: (1) the reliability, availability, and potential for misoperation of a system; (2) if multiplemitigating systems could be affected; (3) the ability of operators to respond in a correctand timely manner to plant transients and accidents; and (4) if the licensee has
identified and implemented appropriate corrective actions associated with operator
workarounds. The inspectors reviewed the Operator Workaround and Burdens List.
The inspectors completed one sample. b.FindingsNo findings of significance were identified.
Enclosure-22-1R17Permanent Plant Modifications (71111.17) a.Inspection ScopeAnnual ReviewThe inspectors reviewed key affected parameters associated with energy needs,materials/replacement components, timing, heat removal, control signals, equipment
protection from hazards, operations, flowpaths, pressure boundary, ventilation
boundary, structural, process medium properties, licensing basis, and failure modes for
the modification listed below. The inspectors verified that: (1) modification preparation,
staging, and implementation did not impair emergency/abnormal operating procedure
actions, key safety functions, or operator response to loss of key safety functions;
(2) postmodification testing maintained the plant in a safe configuration during testing by
verifying that unintended system interactions will not occur, SSC performancecharacteristics still meet the design basis, the appropriateness of modification designassumptions, and the modification test acceptance criteria has been met; and (3) the
licensee has identified and implemented appropriate corrective actions associated with
permanent plant modifications. *November 1, 2005, Modification MP 05-3051, Containment SumpValves EJHV8811A and EJHV8811B. The inspectors performed an in-office
review and performed a walkdown of the affected equipment in the auxiliarybuilding.Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample. b.Findings - Use of a Nonqualified Calculation in a Safety Related ModificationIntroduction. The NRC identified a Green NCV of 10 CFR Part 50, Appendix B,Criteria V, "Instructions, Procedures, and Drawings," associated with an inadequate
engineering procedure used to verify calculations. The inadequate procedure resulted
in the use of a nonqualified, nonsafety-related engineering calculation to demonstratethe safety function of the containment recirculation sump valves following a modification. Description: AmerenUE failed to ensure a nonsafety-related vendor supplied calculationwas qualified before use to demonstrate the design bases function of safety-related
components after a modification. AmerenUE identified that maximum postaccident
differential pressure assumed between the containment recirculation sump and RHRsystem was incorrect. Based on industry operational experience (OE), engineeringdetermined the maximum design differential pressure the containment sump valveoperators would have to open against increased from 53 pounds per square inch
differential (psid) to 468 psid. The Engineering Department generated Modification
MP 05-3051, Containment Sump Valves EJHV8811A and EJHV8811B, to increase
valve operator opening torque. To support the modification, AmerenUE purchased
nonsafety-related Calculation KCI 330-001-DC1, Revision 0, October 18, 2005, from a
Enclosure-23-vendor. The calculation used a new, realistic approach to establish the maximum valveoperator torque. Plant engineering used the operator torque developed from this
calculation to ensure the sump valves would open against the higher differential
pressure after modification. Engineering personnel used Procedure EDP-ZZ-04023,
"Calculations," Revision 17, to qualify the vendor supplied calculation before approved
use in the safety-related application. Procedure EDP-ZZ-04023 provided insufficient
detail to enable engineering personnel to verify the design by either an alternate method
or suitable test program to qualify the nonsafety-related calculation. Analysis: The performance deficiency associated with this finding involved the failure ofengineering personnel to only use qualified calculations for safety-related modifications.
This finding is greater than minor because, if left uncorrected, this finding would become
a more significant safety concern affecting other safety-related modifications. This
finding affected the mitigating systems cornerstone. Using the Manual Chapter 0609,"Significance Determination Process," Phase 1 Worksheet, this finding is determined to
have very low safety significance because this finding involves a design deficiency
confirmed not to result in loss of operability per Part 9900, Technical Guidance,"Operability Determination Process for Operability and Functional Assessment." Thecause of this finding is related to the crosscutting element of human performance in that
the procedure did not ensure the calculations were qualified to support a design basis
function of a safety-related component. Enforcement: Title 10 of the Code of Federal Regulations, Part 50, Appendix B,Criterion V, "Instructions, Procedures, and Drawings," required that activities affecting
quality be prescribed by documented instructions or procedures appropriate to the
circumstances. Contrary to this, Procedure EDP-ZZ-04023, required for an activity
affecting quality, was not appropriate to the circumstances. Specifically, on October 28,
2005, Procedure EDP-ZZ-04023 was not adequate to ensure the qualification of
nonsafety-related Calculation KCI 330-001-DC1, Revision 0, before use in
Calculation EJ-42, Revision 0, an activity affecting quality. Because this finding is of
very low safety significance and was entered into AmerenUE's Corrective Action
Program (CAR 200509849), this violation is being treated as an NCV, consistent with
Section VI.A of the NRC Enforcement Policy (NCV 05000483/2005005-08).1R19Postmaintenance Testing (71111.19) a.Inspection ScopeThe inspectors selected the six listed postmaintenance test (PMT) activities of risksignificant systems or components. For each item, the inspectors: (1) reviewed theapplicable licensing-basis and/or design-basis documents to determine the safety
functions; (2) evaluated the safety functions that may have been affected by the
maintenance activity; and (3) reviewed the test procedure to ensure it adequately tested
the safety function that may have been affected. The inspectors either witnessed or
reviewed test data to verify that acceptance criteria were met, plant impacts were
evaluated, test equipment was calibrated, procedures were followed, jumpers were
properly controlled, the test data results were complete and accurate, the test
equipment was removed, the system was properly re-aligned, and deficiencies during
Enclosure-24-testing were documented. The inspectors also reviewed the FSAR to determine if thelicensee identified and corrected problems related to postmaintenance testing. *September 29, 2005, PMT W236012/920, Containment cooler train. Theinspectors observed the PMT from the reactor building and the control room and
performed an in-office review.*October 12, 13, and 14, 2005, PMTs 222071/912, and W715936/900, ESWTrain A, motor and pump replacement. The inspectors observed the PMT from
the ESW pump room and the control room and performed an in-office review.*October 12, 2005, PMTs W236513/900, W236509/940, and P711090/900, EDGTrain A, major overhaul. The inspectors observed the PMT from the EDG room
and the control room and performed an in-office review.*November 22, 2005, PMTs 05110929/200 and 05110929/910, TDAFP dischargeCheck Valve ALHV0054. The inspectors observed the PMT from the auxiliarybuilding and the control room and performed an in-office review.*November 1, 2005, PMT P721574/910, Overhaul of NN Inverter 14. Theinspectors performed an in-office review.*December 28, 2005, PMT 05112449/900, Ultimate heat sink electrical room fan. The inspectors performed an in-office review.Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed six samples. b.FindingsNo findings of significance were identified.1R20Refueling and Outage Activities (71111.20) a.Inspection ScopeThe inspectors reviewed the following risk significant refueling items or outage activitiesto verify defense-in-depth commensurate with the outage risk control plan, compliancewith the TSs, and adherence to commitments in response to Generic Letter 88-17, "Loss
of Decay Heat Removal": (1) the risk control plan; (2) tagging/clearance activities;
(3) RCS instrumentation; (4) electrical power; (5) decay heat removal; (6) spent fuel pool
cooling; (7) inventory control; (8) reactivity control; (9) containment closure; (10) reducedinventory or midloop conditions; (11) refueling activities; (12) heatup and cooldown
activities; (13) restart activities; and (14) licensee identification and implementation of
appropriate corrective actions associated with refueling and outage activities. The
Enclosure-25-inspectors' containment inspections included observations of the containment sump fordamage and debris, and supports, braces, and snubbers for evidence of excessive
stress, water hammer, or aging. *October 29, 2005, Precore alterations verifications
- October 30, 2005, ECCS full flow test, from control room
- October 31, 2005, Fuel handling from the reactor building and control room
- October 31, 2005, Spent fuel pool time-to-boil method, in-office review
- November 13, 2005, Containment closure walkdown
- November 17, 2005, Reactor startup from the control room and the outagecontrol centerDocuments reviewed by the inspectors are listed in the attachment.
The inspectors completed one sample. b.Findings - Less Than Adequate Spent Fuel Pool Water Inventory Risk ControlsIntroduction
The inspectors identified a Green finding after AmerenUE implemented less thanadequate risk management controls of the spent fuel pool water inventory following
reactor core offload.Description: The inspectors identified that AmerenUE had not implemented shutdownrisk administrative controls on the fuel transfer tube gate valve and the associatedflange during the period the fuel was offloaded to the spent fuel pool. On
September 29, 2005, the core had been off-loaded to the spent fuel pool and thetransfer canal weir gate was removed. In this configuration, the fuel transfer tube valve,
if opened, would provide a drain path from the spent fuel pool through an open weir wall.
Valve ECV-995 was closed but not identified in the shutdown risk managem
ent systemand did not have administrative controls to protect against misalignment. The licensee
provided the inspectors a calculation during the inspection that demonstrated thatValve ECV-995 could be opened during the period of concern. AmerenUE's risk
guidelines, specified in Procedure APA-ZZ-00150, Appendix H, "Project Risk
Management Guidelines," provided for measures to be in place to avoid risk. This
finding was entered into the Corrective Action Program as CARs 200507593
and 200507693. Analysis: The performance deficiency associated with this finding involved failure of thelicensee to identify and implement inventory risk controls associated with the spent fuelpool. This finding is greater than minor because, if left uncorrected, this condition could
become a more significant safety concern. NRC Information Notice 2005-16, "Outage
Enclosure-26-Planning and Scheduling - Impacts on Risk," described operating experience related torefueling risk management. Information Notice 2005-16 emphasized that most spent
fuel pool events had a common thread of human error and involved equipment
misalignment. NRC Manual Chapter 0609, "Significance Determination Process," doesnot specifically address findings related to the spent fuel pool inventory. Therefore, this
issue was evaluated by NRC management with input from a senior reactor analyst. Thisfinding was determined to be of very low safety significance based on the fact that the
procedure used to manipulate the valve was not in use during this period and that
borated water makeup capabilities were available to the spent fuel pool. Enforcement: No violation of regulatory requirements occurred. The inspectorsdetermined that this finding did not represent a noncompliance because it did not involvea safety-related or TS required procedure (FIN 05000483/2005005-09).1R22Surveillance Testing (71111.22) a.Inspection ScopeThe inspectors reviewed the FSAR, procedure requirements, and TSs to ensure that theseven listed surveillance activities demonstrated that the SSCs tested were capable of
performing their intended safety functions. The inspectors either witnessed or reviewed
test data to verify that the following significant surveillance test attributes were
adequate: (1) preconditioning; (2) evaluation of testing impact on the plant;
(3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead
controls; (7) test data; (8) testing frequency and method demonstrated TS operability;(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment ofAmerican Society of Mechanical Engineers code requirements; (12) updating of
performance indicator data; (13) engineering evaluations, root causes, and bases for
returning tested SSCs not meeting the test acceptance criteria were correct;
(14) reference setting data; and (15) annunciators and alarms setpoints. The inspectors
also verified that the licensee identified and implemented any needed corrective actions
associated with the surveillance testing. *September 28, 2005, Surveillance S724682, Boric acid walkdown. Theinspectors observed portions of the walkdown in the reactor building and
completed an in-office review of the completed test documentation.*October 30, 2005, Surveillance S72279, ECCS check valve flow test. Theinspectors observed portions of the test from the reactor building and the control
room and completed an in-office review of the completed surveillance testpackage.*November 1, 2005, Surveillance S05514649, RCS flow test. The inspectorsobserved portions of the test from the control room and completed an in-office
review of the completed test documentation.
Enclosure-27-*November 16, 2005, Surveillance 05513671/500, TDAFP inservice test. Theinspectors observed portions of the testing in the auxiliary building and
completed an in-office review of the test documentation.*November 17, 2005, Surveillance 05511199, Estimated critical rod position. Theinspectors observed portions of the testing from the control room and completed
an in-office review of the test documentation.*November 17, 2005, Surveillance 726457, Low power physics test program withdynamic rod worth measurement. The inspectors observed portions of the
testing from the control room and completed an in-office review of the test
documentation.*November 25, 2005, Surveillance 05101397, Feedwater isolation valve tests. The inspectors observed portions of the testing from the control room and
auxiliary building and completed an in-office review of the test documentation.Documents reviewed by the inspectors are listed in the attachment.
The inspectors completed seven samples. b.Findings
No findings of significance were identified. 1R23Temporary Plant Modifications (71111.23) a.Inspection ScopeThe inspectors reviewed the FSAR, plant drawings, procedure requirements, and TSs toensure that the three below listed TMs were properly implemented. The inspectors:
(1) verified that the modifications did not have an affe
ct on system operability/availability;(2) verified that the installation was consistent with modification documents; (3) ensured
that the postinstallation test results were satisfactory and that the impact of the
temporary modifications on permanently installed SSCs were supported by the test;
(4) verified that the modifications were identified on control room drawings and that
appropriate identification tags were placed on the affected drawings; and (5) verified that
appropriate safety evaluations were completed. The inspectors verified that licensee
identified and implemented any needed corrective actions associated with temporary
modifications. *November 15, 16, and 17, 2005, TM 05-0021, Reactor coolant pump vibrationcircuit. The inspectors walked down portions of the TM in the control building
and completed an in-office review.*November 15, 16, and 17, 2005, TM ETP-SE-ST003, Reactivity computer for lowpower physics testing. The inspectors walked down portions of the TM located
in the control building and completed an in-office review.
Enclosure-28-*November 15, 16, and 17, 2005, TM ET-SE-ST003, Nuclear instrument channeltrip setpoints. The inspectors walked down portions of the TM located in the
control building and completed an in-office review.Documents reviewed by the inspectors included:
- Procedure ETP-SE-ST003, Precritical alignment/hookup of advanced digitalreactivity computer, Revision 6*Administrative Procedure APA-ZZ-00605, Temporary system modifications,Revision 18The inspectors completed three samples. b.Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness1EP4Emergency Action Level (EAL) and Emergency Plan Changes (71114.04) a.Inspection ScopeThe inspectors performed in-office reviews of Revision 27 to the Callaway PlantRadiological Emergency Response Plan, and Revision 33 to Procedure EIP-ZZ-00101,
"Classification of Emergencies." These revisions were compared to their previous
revisions, to the criteria of NUREG-0654, "Criteria for Preparation and Evaluation ofRadiological Emergency Response Plans and Preparedness in Support of Nuclear
Power Plants," Revision 1; to NEI 99-01, "Methodology for Development of Emergency
Action Levels," Revision 2; and to the requirements of 10 CFR 50.47(b)(4) and 50.54(q)
to determine if the revisions decreased the effectiveness of the plan. These revisions:*Made minor administrative updates and corrections and updated titles
- Clarified steam generator leakage terminology for a loss of containment inEAL 2, Indicator 3b*Clarified verification of an earthquake in EAL 3H, Indicator 1c
- Clarified the timeliness of classification with regard to validation of alarms
- Clarified the definitions of steam generator leakage and faulted steam generatoras applied to fission product barriers*Revised the reactor coolant temperature threshold for a potential loss ofcontainment in EAL 2, Indicator 7b, based on updated engineering calculations
Enclosure-29-*Revised the reactor vessel level threshold for potential loss of fuel cladding inEAL 2, Indicator 6b, based on revised emergency operating procedures*Revised the description of telephone systems used in emergency responsefacilities based on replacement of some
phones*Added shelter as an option for recommendations of protective actions for thegeneral public*Added five special needs facilities in the emergency planning zone*Added descriptions of a safety significance fire to EAL 3E, and defined the time afire is outThe inspectors completed two samples during this inspection. b.FindingsIntroduction: A violation of 10 CFR 50.54(q) was identified for implementation of adecrease of effectiveness in the licensee's emergency plan. The licensee implemented
a change to EAL 3E (Notification of Unusual Event) which defined a fire as having safety
significance only when it was located within 50 feet of vital areas, unless the smoke or
water stream from fighting the fire directly impacted listed safety-related equipment.Description: The NRC identified that on June 8, 2005, the licensee implemented achange to its EAL bases, which was an apparent decrease in effectiveness of the
licensee's emergency plan, because it restricted applicability of EAL 3E, "Fire within
Protected Area Boundary NOT Extinguished with 15 minutes of Verification."
Specifically, the revised bases clearly limited a plant fire adjacent to a vital area as one
that is within 50 feet of a vital area, except in cases where smoke or water from fighting
the fire directly affected safety-related equipment. The inspector determined that fires in
some plant areas, such as areas of the turbine building, which were classifiable under
EIP-ZZ-00101, Revision 32, may not have been classifiable using the revised EAL
bases.Analysis: Implementation of changes to emergency action levels which decreased theeffectiveness of the emergency plan, was a performance deficiency. The finding had a
credible impact on the emergency preparedness cornerstone objective because a
licensee is less capable of implementing adequate measures to protect the health and
safety of the public during a radiological emergency if initiating conditions are removed
from licensee emergency action levels. This finding is more than minor because:
(1) restricting or limiting a classifiable condition in the licensee EALs has the potential to
impact safety; and (2) licensee implementation of a change to their emergency plan
which decreases the effectiveness of the plan without prior
NRC approval impacts theregulatory process. The finding also involves a violation of
NRC requirements, subjectto enforcement action under the terms of the NRC Enforcement Policy.
Enclosure-30-Enforcement: Licensee implementation, without prior
NRC approval, of an EAL changewhich decreases the effectiveness of the emergency plan is a violation of
10 CFR 50.54(q), which states, in part, "A licensee authorized to possess and operate a
nuclear power reactor shall follow and maintain in effect emergency plans that meet the
standards in §50.47(b) and the requirements in Appendix E of this part . . . The nuclear
power reactor licensee may make changes to these plans without Commission approval
only if the changes do not decrease the effectiveness of the plans and the plans, as
changed, continue to meet the standards of §50.47(b) and the requirements ofAppendix E to this part."In accordance with Manual Chapter 0609, Appendix B, §2.2(e) and §4.4, the inspectorevaluated the significance of the finding using the "General Statement of Policy andProcedure for NRC Enforcement Actions" (Enforcement Policy),Section IV,"Significance of Violations." The finding was determined to be a Severity Level IV
violation because: (1) a single EAL at the Notification of Unusual Event classification
level was affected, and (2) the violation was determined not to be a licensee failure to
meet or implement one emergency planning standard involving assessment or
notification.Because this performance deficiency is of very low safety significance and has beenentered into the licensee's corrective acti
on system (CAR 200510162), this violation isbeing treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:
NCV 05000483/2005005-10 (Change in Emergency Action Level 3E decreased the
effectiveness of the Emergency Plan).2.RADIATION SAFETYCornerstone: Occupational Radiation Safety2OS2ALARA Planning and Controls (71121.02) a.Inspection ScopeThe inspector assessed licensee performance with respect to maintaining individual andcollective radiation exposures as low as is reasonably achievable (ALARA). The
inspector used the requirements in 10 CFR Part 20 and the licensee's procedures
required by Technical Specifications as criteria for determining compliance. The
inspector interviewed licensee personnel and reviewed:*Current 3-year rolling average collective exposure
- Eight outage work activities scheduled during the inspection period andassociated work activity exposure estimates which were likely to result in the
highest personnel collective exposures. *Site-specific trends in collective exposures, plant historical data, and source-termmeasurements
Enclosure-31-*Site-specific ALARA procedures*Eight work activities of highest exposure significance completed during the last
outage.*ALARA work activity evaluations, exposure estimates, and exposure mitigationrequirements*Intended versus actual work activity doses and the reasons for anyinconsistencies *Interfaces between operations, radiation protection, maintenance, maintenanceplanning, scheduling, and engineering groups*Person-hour estimates provided by maintenance planning and other groups tothe radiation protection group with the actual work activity time requirements *Dose rate reduction activities in work planning
- Assumptions and basis for the current annual collective exposure estimate, themethodology for estimating work activity exposures, the intended dose outcome,
and the accuracy of dose rate and man-hour estimates* Method for adjusting exposure estimates, or replanning work, when unexpectedchanges in scope or emergent work were encountered*Use of engineering controls to achieve dose reductions and dose reductionbenefits afforded by shielding*Exposures of individuals from selected work groups
- Source-term control strategy
- Declared pregnant workers during the current assessment period, monitoringcontrols, and the exposure results*Self-assessments, audits, and special reports related to the ALARA programsince the last inspection*Corrective action documents related to the ALARA program and follow-upactivities such as initial problem identification, characterization, and tracking *Effectiveness of self-assessment activities with respect to identifying andaddressing repetitive deficiencies or significant individual deficiencies Either because the conditions did not exist or an event had not occurred, noopportunities were available to review the following items:
Enclosure-32-*Records detailing the historical trends and current status of tracked plant sourceterms and contingency plans for expected changes in the source term due to
changes in plant fuel performance issues or changes in plant primary chemistry *Radiation worker and radiation protection technician performance during workactivities in radiation areas, airborne radioactivity areas, or high radiation areas The inspector completed 15 of the required 15 samples and 6 of the optional samples. b.FindingsNo findings of significance were identified.4OA2Identification and Resolution of Problems (71152) .1Routine Review of Identification and Resolution of ProblemsThe inspectors performed a daily screening of items entered into the licensee'scorrective action program. This assessment was accomplished by reviewing the daily
CAR Screening Report, Control Room Logs, and attending selected Corrective Action
Review Board and work control meetings. The inspectors: (1) verified that equipment,
human performance, and program issues were being identified by the licensee at an
appropriate threshold and that the issues were entered into the corrective action
program; (2) verified that corrective actions were commensurate with the significance of
the issue; and (3) identified conditions that might warrant additional follow-up throughother baseline inspection procedures.
.2Selected Issue Follow-up InspectionIn addition to the routine review, the inspectors selected the two below listed issues for a
more in-depth review. The inspectors considered the following during the review of the
licensee's actions: (1) complete and accurate identification of the problem in a timely
manner; (2) evaluation and disposition of operability/reportability issues;(3) consideration of extent of condition, generic implications, common cause, and
previous occurrences; (4) classification and prioritization of the resolution of the
problem; (5) identification of root and contributing causes of the problem;(6) identification of corrective actions; and (7) completion of corrective actions in a timely
manner. *October 19, 2005, CAR 200508393, Tin whiskers: untimely corrective actions for10 CFR Part 21*November 11, 2005, CAR 200509277, Unplanned pressurization and failure ofthe TDAFP lube oil coolerThe inspectors completed two samples.
Enclosure-33- .3Exposure Tracking, Higher than Planned Exposure Levels, and Radiation WorkerPracticesSection 2OS2 evaluated the effectiveness of the licensee's problem identification andresolution processes regarding exposure tracking, higher than planned exposure levels,
and radiation worker practices. The inspectors reviewed the corrective action
documents listed in the attachment against the licensee's problem identification andresolution program requirements. .4Semiannual Trend Review a.Inspection ScopeThe inspectors completed a semiannual trend review of repetitive or closely relatedissues that were documented in plant trend reports, problem lists, performance
indicators, system health reports, QA audit reports, corrective action documents, andcorrective maintenance documents to identify trends that might indicate the existence ofmore safety significant issues. The inspectors' review consisted of the 6-month period
of July through December 2005. When warranted, some of the samples expanded
beyond those dates to fully assess the issue. The inspectors also reviewed corrective
action program items listed in the attachment. The inspectors compared and contrasted
their results with the results contained in the licensee's quarterly trend reports.
Corrective actions associated with a sample of the issues identified in the licensee's
trend report were reviewed for adequacy. Documents reviewed by the inspectors are listed in the attachment. b.Findings and Observations
1.Adverse Trend in Human Performance The NRC identified an adverse human performance trend in December 2004 (InspectionReport 05000483/2004005). The NRC subsequently identified a substantivecrosscutting issue in the area of human performance during the 2004 end-of-cycleassessment. The substantive crosscutting issue was based on seven NRC findings
specifically related to personnel errors that occurred during 2004 and affected the
initiating events, mitigating systems, and barrier integrity cornerstones. AmerenUEcompleted a stream analysis of the human performance events to identify commonality
and root causes in April 2005. In June 2005, the
NRC and AmerenUE concluded thatthe adverse trend continued during the first two calendar quarters in 2005 (NRC
Inspection Report 05000483/2005003). AmerenUE implemented the following
corrective actions in August 2005 to address the root causes of poor human
performance (CAR 200501425):*Established the Event Prevention Steering Committee
- Enhanced the plant observation process by establishing metrics andaccountability
Enclosure-34-*Identified and addressed deficiencies in the station root cause analysisprocesses*Implemented a station focus of defense-in-depth error prevention tool/activities
The inspectors concluded that the adverse human performance trend continued duringthe third and fourth quarters 2005. On November 28, 2005, the Callaway Event
Prevention Steering Committee also identified an adverse trend associated with stationnoncompliance with written instructions (CAR 200509697). Examples used by the
licensee to identify the trend included:*CAR 200507092, September 20, 2005, Valve repositioned without theappropriate procedure*CAR 200507699, October 2, 2005, 28 wire strand jack cables dropped from thecontainment polar crane to the cavity deck *CAR 200508510, October 22, 2005, Failure to re-terminate 480 volt energizedleads *CAR 200508753, October 28, 2005, Adverse trend of falling objects*CAR 200509404, November 15, 2005, Partial reactor trip due to failure to followlock and tag notes 2.Adverse Trend in Corrective Action The inspectors identified an adverse trend associated with ineffective corrective actions. The inspectors considered the following examples of corrective actions that failed to
prevent recurrence of previously identified problems. The inspectors screened the
examples using Manual Chapter 0612, Appendix B, "Issue Screening," and concluded
each example had only minor safety significance:*CAR 200509345, Unplanned main steam dump closure during reactor tripbreaker testing *CAR 200509474, Removal of the reactivity computer test leads out of sequencecaused a false pressurizer low level signal and charging system flow reduction*CAR 2005007860, Condensate storage tank wiper seal repeat cracking
- CAR 200207808, Inadequate procedure resulted in the overpressurization of theTDAFP suction piping and lube oil cooler On December 1, 2005, AmerenUE also identified an adverse trend in corrective actionsresulting in a "Red" corrective action program system health indicator.
Enclosure-35-4OA5Other Activities .1Temporary Instruction 2515/160, "Pressurizer Penetration Nozzles and Steam SpacePiping Connections in U.S. Pressurized Water Reactors (NRC Bulletin 2004-01) a. Inspection ScopeIndustry OE has demonstrated that Alloy 82/182/600 materials exposed to primarycoolant water (or steam) at the normal operating conditions of pressurized water reactor
plants have cracked due to primary water stress corrosion cracking. The NRC issuedBulletin 2004-01, "Inspection of Alloy 82/182/600 Materials Used in the Fabrication of
Pressurizer Penetrations and Steam Space Piping Connections at Pressurized-water
Reactors," was issued to alert licensee's to the susceptibility of Alloy 82/
182/600materials to cracking. The Callaway RCS has five pressurizer connections that were
applicable to the vulnerabilities described in NRC Bulletin 2004-01. The inspectorscompared the AmerenUE examinations of these five Alloy 82/182/600 pressurizer piping
connections with the licensee's commitments documented in UL
NRC-05031, "Responseto NRC Bulletin 2004-01, Inspection of Alloy 82/182/600 Materials used in theFabrication of Pressurizer Penetrations and Steam Space Piping Connections at
Pressurized-Water Reactors," July 27, 2004. The inspectors performed this comparison
to verify that the examinations were consistent with the AmerenUE response to thebulletin. The inspectors reviewed records and examination procedures for visual examinations(listed in the attachment) conducted during Refueling Outage 13 (Spring 2004) and
Refueling Outage 14 (Fall 2005). The inspectors performed this review to verify that the
bare metal examinations were adequate to detect the presence of boric acid crystals.
The inspectors used the guidance in Inspection Procedure 57050, "Visual Testing
Examination," as acceptance criteria for this review. The inspectors reviewed volumetric
examinations conducted during 1992 and 1996. The inspectors used the guidance in
Inspection Procedure 57080, "Ultrasonic Testing Examination," as acceptance criteria
for this review. The inspectors also reviewed the qualifications and certifications of the
personnel performing the examination and assessed the techniques used to detect
small boric acid deposits on the subject locations. b.FindingsNo findings of significance were identified. The inspectors concluded that theinspections conducted by AmerenUE were consistent with the licensee's response to
NRC Bulletin 2004-01. The inspectors concluded:
- Personnel performing the examination were qualified, knowledgeable, andcertified as visual examination Level 2 inspectors. Each inspector also received
additional training for identification of boric acid deposits.*The examinations were performed in accordance with station procedures andwere capable of identifying leakage in pressurizer penetration nozzle or steam
space piping components, as discussed in NRC Bulletin 2004-01.
Enclosure-36-*The inspectors reviewed the photographic record of the examination and verifiedthat the physical condition of the penetration nozzles and steam space piping
components were good, without debris, insulation, dirt, or boron from other
sources during the visual examination. *The visual examination covered a 360° circumference of all the affected nozzles. *The examination was sufficient to identify and characterize small boron deposits,as described in NRC Bulletin 2004-01. AmerenUE did not identify any material deficiencies, cracks, or corrosion. Noindications of boric acid leaks from pressure-retaining components were identified
during the examinations and volumetric or surface examination techniques were not
used to augment the inspections. .2(Closed Unresolved Item 05000483/2005004-03) Potential Failure of the RHRContainment Recirculation Sump Valves During Certain Design Bases EventsAmerenUE evaluated the containment recirculation sump valve operator torque neededto open against the maximum calculated differential pressure that could be experienced
across the valve. AmerenUE determined that the valves were required to operateagainst a 53 psid (Calculation RFR 05353, Revision F, October 31, 1989). AmerenUE
evaluated OE from the Catawba and McGuire plants (CAR 200504370) during
June 2005. This OE alerted the industry to the potential of higher than previouslyconsidered differential pressure across the RHR sump valves. In response to the OE,AmerenUE operated the RHR pumps for 30 minutes in the minimum flow configurationand observed 189 psid across the sump valve. AmerenUE concluded that the maximum
differential pressure the valve actuator would be required to open against was 189 psid.
Engineering personnel concluded valve operability based on a linear extrapolation of theactuator torque to the new conditions. Subsequently, AmerenUE evaluated additional OE from the Wolf Creek plant onSeptember 21, 2005 (CAR 200507150). This OE alerted the industry to the potential ofadditional differential pressure that could develop across the RHR sump valves while inthe minimum flow mode. AmerenUE reevaluated the RHR valves and determined thatthe maximum differential pressure the valves had to open against could be 468 psid.
AmerenUE verified past sump valve operability using actual valve factors and a realisticlock-rotor valve operator torque. AmerenUE modified the operators to provide higher
opening torque to ensure future RHR valve operability. The failure of Ameren to ensuresuitability of the RHR containment suction valves' function to open under all safety-related design bases conditions was a licensee-identified violation of 10 CFR Part 50,
Appendix B, Criteria III, "Design Control." The enforcement aspects of this violation arediscussed in Section 4OA7 of this report.
Enclosure-37- .3(Closed Apparent Violation 05000483/2005004-01) Failure to Maintain ColdOverpressure Mitigation Measures as Required by TSs a. Inspection ScopeA senior reactor analyst performed a Phase 3 significance determination of apparentviolation 05000483/2005004-01. The inspectors evaluated this finding using the
guidance in Manual Chapter 0612, Power Reactor Inspection Reports, dated
September 30, 2005, for determining whether a violation is licensee-identified becausethis finding had not been closed prior to the revised guidance being issued. This
apparent violation is closed as a licensee-identified violation of very low safety
significance. The violation is documented in Section 4OA7 of this report. b.FindingsIntroduction: The senior reactor analysts completed the significance determination ofthe apparent violation documented in NRC Inspection Report 05000483/2005004. Theapparent violation involved the failure of AmerenUE operations personnel to ensure no
more than one centrifugal charging pump was capable of injecting into the reactor
vessel while in Mode 5, as required by TS 3.4.12.Analysis: The performance deficiency associated with this finding involved thelicensee's failure to establish and follow adequate procedures. This finding is greater
than minor because it would have become more significant, if left uncorrected, in that
inadvertent starting of the charging pump could have challenged the piping integrity of
the RCS system. The inspectors used Appendix G, "Shutdown Operations SignificanceDetermination Process," of Manual Chapter 0609, "Significance Determination Process,"
to determine the significance of this finding. Unplanned entry into cold
overpressurization conditions represented additional risk incurred above the planned
outage risk. The additional risk associated with the ability of the centrifugal chargingpump to inject into the RCS constituted additional risk above the planned outage risk.
Phase 1 screening of this finding was performed using Appendix G and the
Attachment 1 checklists. Management review determined that significance
determination process Phase 3 analysis was needed for this finding.The senior reactor analysts' review of the Callaway cold overpressure mitigation(COMS) precursor involved having both centrifugal charging pumps capable of RCS
injection. This condition lasted approximately 20 minutes.The following conditions existed at the time of the event:
- Pressurizer level was at 5 percent
- There was a high pressurizer level alarm at 90 percent
- There was an alarm at 5 percent level above program increase
- RCS level was not being changed at the time of the event
Enclosure-38-*No testing was being performed on or in systems connected to the RCS thatcould perturb RCS level*No work was being performed on RCS level indication other than adding anadditional, alternate reactor vessel level indication with separate tap locations*The safety injection pumps were in pull-to-lock
- The accumulators were isolated and vented
- Each RHR train had a suction relief valve with a lift setpoint of 450 pounds persquare inch gauge (psig) (986 gpm discharge capacity)*Both trains of RHR were aligned to the RCS with one train providing decay heatremoval. Therefore, both RHR suction relief valves were available to relieve a
postulated cold overpressure challenge*Two power-operated relief valves were available for COMS, the low power-operated relief valve setpoint was at 500 psig, the high power-operated reliefvalve setpoint was at 525 psig*The pressurizer was vented to atmosphere (via a 3/4-inch manual vent valve)
To assess the risk of the event required an estimate of the likelihood that the operatorswould have initiated RCS injection, resulting in a solid RCS. Based on the above
information, it appears that no plant operations were being performed at the time thathad the potential to trigger the operators to initiate RCS injection. Additionally, the alarmindicating 5 percent above program level provides additional assurance that the
likelihood of overfilling the RCS during the 20-minute time period was small. If a postulated RCS pressure challenge were to occur, the dominant core damagescenario involves both RHR suction relief valves failing to reseat after an RCS pressurechallenge. In this design, the RHR suction relief valves have a lower relief setpoint thanthe pressure-operated relief valves. Should one RHR relief valve fail to reseat, theoperators could isolate the valve and use the alternate train of RHR for decay
heatremoval. If both relief valves were to fail to reseat, the operators would be directed to
increase charging and isolate the leak. In this plant condition, steam generator cooling
is not anticipated to match decay heat; therefore, the RCS may re-pressurize until steam
generator cooling can remove decay heat. For this situation, both pressure-operated
relief valves would be available should RCS pressure increase to the COMS setpoint.In summary, combining the small likelihood of having an RCS pressure challenge duringthe 20-minute period, the likelihood of having both RHR relief valves stick open after achallenge, and the failure of both pressure-operated relief valves to relieve pressure, the
core damage frequency delta for this finding is estimated to be less than 1E-6.
Therefore, this finding can be characterized in the significance determination process as
Enclosure-39-Green. It is important to note that the licensee's robust COMS mitigation capability (theavailability of both RHR suction relief valves and the pressure-operated relief valves)was significant in reducing the risk of this finding.The review of the licensee's analysis only considered the likelihood of the COMS systemfailing to provide RCS pressure relief following a demand. The licensee did not consider
that an RCS pressure demand may result in the RHR suction relief valve lifting
and notreseating. This scenario results in a loss of coolant accident in the RHR system asdescribed above.This finding affected the barrier integrity cornerstone and the configuration control,procedure quality, and human performance attributes of maintaining functionality of the
RCS. The senior reactor analyst determined that this finding is only of very low
significance. Enforcement: The enforcement aspects of this finding are discussed in Section 4OA7 ofthis report.4OA6Management MeetingsExit Meeting SummaryOn December 14, 2005, the health physics inspector presented the ALARA inspectionresults to Mr. A. Heflin, Vice President, and other members of his staff who
acknowledged the findings. On January 6, 2006, the resident inspectors presented their inspection results toMr. C. Naslund, Senior Vice President and Chief Nuclear Officer, and other members of
his staff who acknowledged the findings. The emergency preparedness inspector conducted a telephonic exit interview onJanuary 12, 2006, to present the inspection results to Mr. M. Reidmeyer, Supervisor,
Regional Regulatory Affairs, and other members of his staff who acknowledged the
findings. The operations branch inspectors conducted an exit meeting on June 9, 2005, regardingthe on-site portion of the inspection with Mr. R. Roselius and other members of the
licensee's staff. On December 15, 2005, the inspectors discussed biennial written
requalification examination issues with the licensee. After
NRC management review ofthe biennial written requalification examination observations, the inspectors again
discussed the unresolved item identified during the review of the written biennial
requalification exams with the licensee during a teleconference on January 23, 2006.The inspectors verified that no proprietary information was provided during theinspection.
Enclosure-40-4OA7Licensee-Identified ViolationsThe following violations of very low safety significance (Green) were identified by thelicensee and are violations of
NRC requirements which meet the criteria of Section VI ofthe NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.*Title 10 CFR Part 50, Appendix B, Criteria III, "Design Control," required that measuresbe established for the selection and suitability of application of equipment essential tothe safety-related functions of the SSCs. Contrary to this, on October 31, 1989, and
October 5, 2005, the selection and suitability of application for the RHR containmentsump valve operators was inadequate to ensure all safety-related functions. AmerenUE
had established an insufficient maximum differential pressure design that the sumpvalves would have to open against during certain design bases events. This was
identified in the licensee's corrective action program as CAR 200504370. This finding is
of very low safety significance because it does not represent a design or qualification
deficiency confirmed not to result in loss of operability per Part 9900, TechnicalGuidance, "Operability Determination Process for Operability and FunctionalAssessment."*Title 10 CFR 55.49 requires examination integrity to be maintained. The regulationfurther defines an examination compromise as any activity, regardless of intent, that
affected or could have affected the equitable and consistent administration of an
examination.During a review of CARs, the inspectors noted that two events occurred that had thepotential to effect the integrity of the requalification examinations. The first eventoccurred on May 26, 2005, and involved leaving data on the simulator's "white board"
from the previous scenario training crew. The data displayed provided information that
could be used by the oncoming training crew to assist them with the scenario (since the
same scenario was to be run). This compromise was identified by the licensee's
oncoming training crew. As a result, the oncoming crew was given a different scenario.The second event occurred on June 8, 2005, and involved the accidental observation ofsome pages out of a written examination by a candidate assigned to the training staff.
This candidate was scheduled to take the same specific examination. When the
licensee identified this compromise, the candidate was rescheduled to take a different
written examination.These findings are greater than minor because a compromise of the integrity of theannual requalification examinations could lead to operators (who would normally have
failed the examination) with deficient knowledge and skills to remain on shift. Allowingoperators with deficient knowledge and skills to remain on shift increases the likeli
hoodthat a human performance error could initiate a reactor safety event or inhibit the
appropriate mitigating response to such an event. Contrary to the above, the licensee
failed to adequately assure that examination security was maintained during the
administration of examinations. The finding is of very low safety significance because
Enclosure-41-the potential for examination compromise was extremely low. These findings have beenentered into the corrective action program as CARs 200503988 and 200503985,
respectively.*TS 5.4.1.a, "Procedures," and Regulatory Guide 1.33, Appendix A, required proceduresfor shutdown to be implemented. Procedure OSP-BG-00002, "Verify One CentrifugalCharging Pump Incapable of Injection into RCS," required the licensee to ensure only
one centrifugal charging pump was capable of injecting to the RCS during Mode 5
operations with limited RCS vent path. Contrary to the above, on September 20, 2005,the licensee failed to ensure only one centrifugal charging pump was capable of
injecting to the RCS. This finding is greater than minor because it would have become
more significant, if left uncorrected, in that inadvertent starting of the charging pump
could have challenged the piping integrity of the RCS system. This finding wasdetermined to be very low significance after completion of a Phase 3 SDP by the senior
reactor analyst as documented in Section 40A5 of this report. This finding was identified
in the licensee's corrective action program as CAR 200507092.
A-1AttachmentSUPPLEMENTAL INFORMATIONKEY POINTS OF CONTACTLicenseeW. Arbour, Senior Operations Training SupervisorS. Aufdemberge, Operating Supervisor
K. Bruckerhoff, Supervisor, Emergency Preparedness
F. Diya, Manager, Engineering Services
R. Farnam, General Supervisor, Radiation Protection
S. Ganz, Operating Supervisor
J. Geyer, Health Physicist, Radiation Protection
K. Gilliam, ALARA Coordinator, Radiation Protection
S. Halverson, General Supervisor, Simulator
A. Heflin, Site Vice President
T. Herrmann, Vice President, Engineering
J. Hiller, Regulatory Affairs, EngineerG. Hurla, Supervisor, Radiation Protection
M. Jennings, Operating Supervisor
L. Kanuckel, Manager, Quality Assurance
S. Kochert, Operating Supervisor
V. Miller, ALARA Specialist, Radiation Protection
R. Moody, Operating Supervisor
T. Moser, Manager, Plant Engineering
C. Naslund, Senior Vice President and Chief Nuclear Officer
R. Nelson, Shift Supervisor
D. Neterer, Manager, Operations
M. Reidmeyer, Supervisor, Regional Regulatory Affairs
R. Roselius, Superintendent, Training
K. Young, Manager, Regulatory AffairsLIST OF ITEMS OPENED AND CLOSED
Opened05000483/2005005-03URIIndeterminate Containment Cooler Operability and HeatRemoval Capability (Section 1R07)05000483/2005005-04URI Adequacy of the Biennial Requalification WrittenExamination (Section 1R11)05000483/2005005-06URIAdequacy of Plant-Referenced Simulator to Conform withSimulator Requirements for Reactivity and Control
Manipulation Credits (Section 1R11)
A-2AttachmentOpened and Closed05000483/2005005-01NCVMinimum gap size exceeded for containment recirculationsump (Section 1R04)NCVSeven examples of inadequately performed continuous firewatches (Section 1R05)05000483/2005005-05FINFailure to Conduct Simulator Testing in Accordance withANSI/ANS 3.5-1998 (Section 1R11)05000483/2005005-07 NCV Failure to Follow Procedures Resulted in Violation of RCS Cooldown and Heatup Rate Limits (Section 1R14)05000483/2005005-08NCV Use of a Nonqualified Calculation in a Safety-RelatedModification (Section 1R17)05000483/2005005-09FIN Less Than Adequate Spent Fuel Pool Water InventoryRisk Controls (Section 1R20)05000483/2005005-10NCVChange in EAL 3E decreased the effectiveness of theEmergency Plan (Section 1EP4)Closed05000483/2005004-03URIPotential Failure of the RHR Containment Suction ValvesDuring Certain Design Bases Events (Section 4OA5)05000483/2005004-01AVFailure to Maintain Cold Overpressure Mitigation Measuresas Required by TSs (Section 4OA5)DOCUMENTS REVIEWEDSection 1R04: Equipment AlignmentDrawingsE-23KJ01A, Revision 14, Diesel General KKJ01 Engine Control (Start / Stop) CircuitM22-BG03, Chemical and Volume Control System
M22-BG05, Chemical and Volume Control System
M22-EJ01, Residual Heat Removal SystemMiscellaneousCallaway Action Request 200509189
Procedure OSP-EJ-00003, Containment Recirculation Sump Inspection, Revision 5
A-3AttachmentFSAR Table 6.2.2-1, Comparison of the Recirculation Sump Design with each of the Positionsof Regulatory 1.82NRC Bulletin 2003-01, Potential Impact of Debris Blockage on Emergency Sump Recirculationat Pressurized-Water ReactorsWork package W229952, Recirculation Sump Inspection
ULNRC-04966, Callaway Plant, Union Electric Co. Supplement to Response to NRCBulletin 2003-01, Potential Impact of Debris Blockage on Emergency Sump Recirculation at
Pressurized Water ReactorsSection 1R05: Fire Protection
ProceduresAPA-ZZ-00743, Fire Team Organization and Duties, Revision 18EIP-ZZ-00226, Fire Response Procedure for Callaway Plant, Revision 11
SDP-KC-00001, Requirements for and Duties of Compensatory Fire Watches, Revision 5Requests for ResolutionRFR 15704, Electrical Safety Equipment Lockers, Revisions A and BRFR 18572, Allowed Storage of D/G Tool Boxes and Barring Device, Revision A
RFR 3487, Breaker Test Area in NB01 Switchgear Room 3301, Revision BMiscellaneousInformation Notice 97-48, Inadequate or Inappropriate Interim Fire Protection CompensatoryMeasuresSection 1R07: Heat Sink PerformanceCallaway Action RequestsCAR 200503773, Containment cooler heat removal surveillance requirementsCAR 200502534, Incorrect component cooling water heat exchanger indicationDrawingsM-22EF02, Essential Service Water System M-22EF08, Essential Service Water Containment Air Coolers ProceduresESP-EF-002A, Essential Service Water Train A Flow Verification, Revision 0OSP-EF-P001A, ESW Train A Inservice Test, Revision 43
A-4AttachmentMiscellaneousSGN01A ETP-ZZ-03001, Heat Exchange Inspection Report, Revision 5, completed onSeptember 23, 2005Surveillance 05515092, Essential Service Water, performed on October 12, 2005
Work Package W 236012/920, Containment Cooler Unit A PMTSection 1R11: Licensed Operator RequalificationProceduresTDP-IS-00002, Simulator Configuration Management, Revision 4TDP-IS-00001, Simulator Operation and Maintenance, Revision 3JPMsSRO-RER02C113J(TC), Emergency Event Classification, Revision 20040710
URO-SEG02C21J, Shift Non-essential CCW Supply Loops, Revision 20050604
URO-AEO05045J, Locally Close Valves for a CIS [Containment Isolation Signal]-B,Revision 20050508URO-SGN02C27J, Secure D Containment Cooler Fan, Revision 20050421
URO-AEO15016J, Local Manual Start of NE02, Revision 20050422
URO-SBB04C67J(A), Pressurizer Level Channel Failure, Revision 20050421
SRO-RER02C143J(TC), Emergency Event Classification, Revision 20050413
URO-SAB04C61J(A), Place Steam Dumps in Steam Pressure Mode, Revision 20050413
URO-SEF02C03J, Manually Operate an ESW Train, Revision 20050413
EOP-SBG06014J, Shift and Vent CVCS Seal Water Injection Filters, Revision 20050314
URO-AEO05001j(A), Locally Start (NE01) Emergency Diesel, Revision 20050413
URO-SBG02C04J, Swap From B CCP to NCP, Revision 20050413
SRO-RER02C118(TC), Emergency Event Classification, Revision 20050323
URO-SGN04C71J(A), Start A Containment Cooler Fan, Revision 20050820
EOS-SNN03011J, Shift an Instrument Bus to Backup Power Supply, Revision 20050323
A-5AttachmentURO-Paralleling Diesel Generator A to XNB01, Revision 20050625URO-SSF01C05J, Perform Control Rod Partial Movement Test, Revision 20050215
URO-AEO05PA023J, Locally Close Valves for a CIS-A, Revision 20050323
URO-SSP03C15J, Radiation Monitors Source Check, Revision 20050328
URO-AEO15029J, Locally Isolate a MSIV, Revision 20050314
URO-SBG02C01J, Placing Excess Letdown in Service, Revision 20050314
SRO-RER02C45J, Emergency Event Classification, Revision 20050414
URO-AEO01C151J(A), Emergency Boration Per /ES-0.1/Addendum 4, Revision 20050502
EOS-SNK01051J, Place NK22 in Service to Bus NK02, Revision 20050314
ScenariosDS-07, Small Break LOCA With Failure of CPIS [Containment Purge Isolation System] andCCP [Component Cooling Pump]/Loss of NB01, Revision 20050520DS-32, Faulted-Ruptured S/G, Revision 20050520
DS-14, Separate Faulted and Ruptured S/Gs, Revision 20050310
DS-24, Loss of Letdown, ATWS with Stuck Open Pressurizer Safety Valve, Revision 20050311
DS-15, Load Increase with Multiple Rod Drop/Pressurizer Steam Space Leak,Revision 20050507DS-40, Faulted/Ruptured S/G, Revision 20050507
DS-04, Loss of Heat Sink without Bleed and Feed Required, Revision 20050514
DS-05, Faulted/Ruptured S/G, Revision 20050514
DS-01, ATWS, Revision 20050308
DS-26, Large LOCA and Transfer to Cold Leg Recirculation, Revision 20050310
DS-08, Feedline Break Inside Containment with CCP and SLIS Failures, Revision 20050414
DS-37, Station Blackout due to Seismic Conditions, Revision 20050329
DS-18, SGTR Without Pressurizer Pressure Control, Revision 20050422
A-6AttachmentDS-19, Turbine Trip Failure with Loss of Heat Sink, Revision 20050422 Written ExaminationsT61.0810 8, LOCT Cycle 05-4 Biennial Exam, SRO Week 1
T61.0810 8, LOCT Cycle 05-4 Biennial Exam, URO Week 2
Miscellaneous2003-2005 Continuing Sample Plan
Job-Duty-Task by Job for URO [Unit Reactor Operator] dated 3/17/05
Job-Duty-Task by Job for SRO dated 4/14/05
Written Summary of Simulator Testing Topic Public Meeting with Industry Focus Group (FG) onOperator Licensing Issues (DRAFT)Response to April 7, 2004 Public Meeting Minutes Attachment 6
Callaway Plant Simulator White Paper showing how all parameters are demonstrated, June 8, 2005Simulator Annual Performance Test Book
Simulator "Differences" List, May 16, 2005Section 1R17: Permanent Plant ModificationsCalculations330-001-DC1, Motor terminal voltage and nominal torque output, Revision 0EJ-42, MOV sizing for EJHV8811A and EJHV8811B, Revision 0
Westinghouse Calculation SCP-05-69, Valve Factors for Valve Location 8811A and 8811B,October 28, 2005Callaway Action Requests
200507150 200509849
200505194MiscellaneousPredictive Performance Report, E170.0197, CA 1527, May 10, 1990
A-7AttachmentModification MP 05-3051Section 1R19: Postmaintenance TestingProceduresOSP-SF-00005, Estimated Critical Rod Position Calculation ST-13002, Revision 16ETP-ZZ-ST010, Low Power Physics Test Program with Dynamic Rod Worth Measurement,Revision 8OSP-BG-0001A, Boron Injection Flowpaths, Revision 14
APA-ZZ-00500, Corrective Action Program, Revision 38
OSP-AL-P0002, Turbine-Driven Auxiliary Feedwater Pump Inservice Test, Revision 49MiscellaneousPM0826213, Overhaul of NN Inverter, PMB Charging-1-5.2-4, Revision 0Section 1R20: Refueling and Outage ActivitiesProceduresAPA-ZZ-00150, Outage Preparation and Execution, Revision 12EDP-ZZ-1129, Callaway Plant Risk Assessment, Revision 8
OSP-SF-00003, Pre-Core Alteration Verifications, Revision 12
OSP-SF-00003, Pre-Core Alterations Verifications, Revision 15
OSP-ZZ-00001, Control Room Shift and Daily Log Readings and Channel Checks, Revision 39OTG-ZZ-00001, Plant Heatup Cold Shutdown to Hot Standby, Revision 45
OTG-ZZ-00006, Plant Cooldown Hot Standby to Cold Shutdown, Revision 6
OTO-KE-00001, Fuel Handling Accident, Revision 7
QCP-ZZ-05048, Boric Acid Walkdown for RCS Pressure Boundary, Revision 2MiscellaneousCurve Book, Figure 8-6, RCS Pressure-Temperature Limitations
Nuclear Utility Management and Resource Council 91-06, Guidelines for Industry Actions toAssess Shutdown Management Quality Assurance Surveillance ReportsSP05-028, December 12, 2005, Assess lifting, removal and placement of the reactor vesselhead and upper internals
A-8AttachmentSP05-047, December 9, 2005, Reduced inventory control, risk assessment, outage technicalspecificationsCallaway Action Requests
200002070 200202540
200302806
200307232
200307247
200307844
200402256
200500720
200500756
200501092 200501407 200501837
200501990
200502420
200502438
200502548
200503439
200503622
200503773
200504591 200504950 200505062
200505368
200505716
200506244
200507150
200507278
200508169
200507593
200507693 Section 1R22: Surveillance TestingProceduresOSP-EM-V0003, ECCS Check Valve Inservice Test IPTE, Revision 21OSP-BB-00006, Reactor Coolant Circulation, Revision 7
OSP-BG-0001A "Boron Injection Flowpaths modes 4 through 8Audits and Self-AssessmentsQuality Assurance Surveillance Report SP05-027, November 6, 2005, Assess effectiveness offuel movement, compliance to TSs and procedures applicable to fuel movementQuality Assurance Surveillance Report SP05-037, November 18, 2005, Assess implementationof the steam generator replacement projectSection 71152: Identification and Resolution of ProblemsProceduresAPA-ZZ-00500, Corrective Action Program, Revision 38Callaway Action Requests
200507092 200507699
200508510
200508753
200509404
A-9AttachmentMiscellaneousCallaway Plant Quarterly Performance Analysis Report Third QuarterEvent Review Team Meeting SummariesAUCA 05-040, October 2, 2005, Strand wires were dropped from the TLD on the polar crane tothe cavity deckAUCA 05-047, October 15, 2005, Corrosion discovered on the new B low pressure turbine rotor
AUCA 05-049, October 17, 2005, Employee falls in containment while wearing fall protectionAUCA 05-050, October 19, 2005, Pit at VBS checkpoint lowered prematurelyAUCA 05-057, October 29, 2005, Leaking head gaskets during KKJ01B maintenance run
Surveillance ReportsSP05-034, September 24, 2005, Postmodification test planning for CMP 03-1014 - EP8818A-Dvalve replacementsSP05-045, September 29, 2005, Bottom mounted instrumentation inspection and cleaningSP05-026, September 30, 2005, Assess various areas during plant shutdownSP05-061, October 28, 2005, Refuel 14 worker practices
SP05-070, November 5, 2005, QA walkdowns to assure appropriate combustible loadings andhousekeeping, and operable fire doors and halon systemsSP05-074, November 15, 2005, Assess interim compensatory actions in response to NRCBulletin 20003-1 and Generic Letter 2004-2SP05-044, November 23, 2005, Refuel 14 work activities on the TDAFP
SP05-056, November 29, 2005, Review of the tin whisker inspections
SP05-068, November 30, 2005, Assessment of Operating License Amendment 1248`SP05-029, December 6, 2005, Assess effectiveness of control room personnel from Mode 3ascending to Mode 1SP05-058, December 14, 2005, QA assessment of Refueling Outage 14 mode changerestraintsSP05-063, December 15, 2005, ESW strainer replacement activities
A-10AttachmentSP05-071, December 8, 2005, Review control logs and verify CARs were written whenappropriateSP05-078, November 30, 2005, Main feedwater regulation valve and bypass regulation valvetesting in Refuel 14Callaway Plant Quarterly Performance Analysis Report First Quarter
Callaway Plant Quarterly Performance Analysis Report Second Quarter
Quality Assurance AuditsAP05-010, October 5, 2005, Problem resolution, adverse trends, OQAM auditrequirements/other commitments, review of self-assessments, organization, special nuclear
material program, special nuclear material inventory, source control, and software managementSection 4OA5: Other ActivitiesSurveillancesS724682, Task 150, Inspection of pressurizer surge nozzle welds for boronS724682, Leakage examination of the RCS, September 25, 2005
S714761, Leakage examination of the RCS, April 29, 2004ProceduresQCP-ZZ-05048, Boric Acid Walkdown for RCS Pressure Boundary, Revision 2QCP-ZZ-05048, Boric Acid Walkdown for RCS Pressure Boundary, Revision 1MiscellaneousLetter to the NRC from AmerenUE, ULNRC-05031, July 27, 2004, "Response to NRC Bulletin2004-01, "Inspection of Alloy 82/182/600 Materials Used in the Fabrication of Pressurizer
Penetrations and Steam Space Piping Connections at Pressurized Water Reactors" UT Data Sheet 1021-02, Examination BB 2TBB03-1-w, April 18, 1992
UT Data Sheet 1021-01, Examination BB 2TBB03-2-w, April 17, 1992
UT Data Sheet 6276-95-01, Examination BB 2TBB03-3-A-w, October 30, 1996
UT Data Sheet 6276-95-02, Examination BB 2TBB03-3-B-w, October 30, 1996
UT Data Sheet 6276-001, Examination BB 2TBB03-3-C-w, October 27, 1996
UT Data Sheet 6276-002, Examination BB 2TBB03-4-w, October 27, 1996
CAR 200507515, Boric acid walkdown for Refuel 14
A-11AttachmentLIST OF ACRONYMSALARAas low as is reasonably achievableCARCallaway Action Request
COMScold overpressure mitigation
EALemergency action level
EDGemergency diesel generator
ESWessential service water
FINfinding
FSARFinal Safety Analysis Report
NCVnoncited violation
OEoperational experience
psidpounds per square inch differential
psigpounds per square inch gauge
PMTpostmaintenance test
RHRresidual heat removal
SSCstructures, systems, and componentsTDAFPturbine-driven auxiliary feedwater pumpTMstemporary modifications
TSsTechnical Specifications
URIunresolved item