IR 05000440/2006004
| ML062840067 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 10/05/2006 |
| From: | Satorius M A Division Reactor Projects III |
| To: | Pearce L W FirstEnergy Nuclear Operating Co |
| References | |
| FOIA/PA-2010-0209 IR-06-004, IR-06-021 | |
| Download: ML062840067 (31) | |
Text
October 5, 2006
Mr. L. William PearceSite Vice President FirstEnergy Nuclear Operating Company Perry Nuclear Power Plant P. O. Box 97, 10 Center Road, A290 Perry, OH 44081-0097
SUBJECT: PERRY NUCLEAR POWER PLANT NRC INTEGRATED INSPECTIONREPORT 05000440/2006004 AND EMERGENCY PREPAREDNESS INSPECTION REPORT 05000440/2006021
Dear Mr. Pearce:
On September 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection findings which were discussed on September 28, 2006, with you and other members of your staff.The 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. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. In addition to the routine NRC inspection and assessment activities,Perry performance is being evaluated quarterly as described in the Assessment Follow-up Letter - Perry Nuclear Power Plant, dated August 12, 2004. Consistent with Inspection Manual Chapter (IMC) 0305, "Operating Reactor Assessment Program," plants in the
"Multiple/Repetitive Degraded Cornerstone" column of the NRC's Action Matrix are givenconsideration at each quarterly performance assessment review for (1) declaring plant performance to be unacceptable in accordance with the guidance in IMC 0305; (2) transferring to the IMC 0350, "Oversight of Operating Reactor Facilities in a Shutdown Condition withPerformance Problems," process; and (3) taking additional regulatory actions, as appropriate.
On August 22, 2006, the NRC reviewed Perry operational performance, inspection findings, andperformance indicators for the second quarter of 2006. Based on this review, we concluded that Perry is operating safely. We determined that no additional regulatory actions, beyond thealready increased inspection activities and management oversight, are currently warranted.Based on the results of this inspection, no findings were identified. However, onelicensee-identified violation of very low safety significance is listed in Section 4OA7 of this report. Because of the very low safety significance of this violation and because it has been entered into your corrective action program, the NRC is treating this violation as a Non-Cited Violation consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the subject or severity of this non-cited violation, you should provide aresponse 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 a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Perry Nuclear Power Plant.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of thisletter and its enclosure will be available electronically for public inspection in the NRCPublic Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS), accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,/RA/Mark A. Satorius, DirectorDivision of Reactor ProjectsDocket No. 50-440License No. NPF-58
Enclosure:
Inspection Report 05000440/2006004; 05000440/2006021
w/Attachment:
Supplemental Informationcc w/encl:G. Leidich, President and Chief Nuclear Officer - FENOCJ. Hagan, Senior Vice President of Operations and Chief Operating Officer - FENOC D. Pace, Senior Vice President, Fleet Engineering - FENOC J. Rinckel, Vice President, Fleet Oversight Director, Site Operations Director, Regulatory Affairs Manager, Fleet Licensing Manager, Site Regulatory Compliance D. Jenkins, Attorney, FirstEnergy Public Utilities Commission of Ohio Ohio State Liaison Officer R. Owen, Ohio Department of Health
SUMMARY OF FINDINGS
IR 05000440/2006004, 05000440/2006021; 07/01/2006 - 09/30/2006; Perry Nuclear PowerPlant.This report covers a 3-month period of baseline inspection. The inspection was conducted bythe resident and regional inspectors. The NRC's program for overseeing the safe operation ofcommercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process,"Revision 3, dated July 2000.A. Inspector-Identified and Self-Revealed FindingsNo findings of significance were identified.
B. Licensee-Identified Violations
A violation of very low safety significance that was identified by the licensee has beenreviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. This violation and the licensee's corrective action tracking number are listed in Section 4OA7.
2
REPORT DETAILS
Summary of Plant StatusThe plant began the inspection period at 100 percent power. On July 8, 2006, operatorsreduced power to 55 percent to conduct planned maintenance activities. On July 9, 2006, operators returned power to 100 percent. On July 17, 2006, the plant experienced hot weatherconditions and operators reduced power to 99.5 percent to maintain the main condenser operations within procedural limits. Power was returned to 100 percent on the same day.
Between July 31 and August 3, 2006, the plant experienced an extended period of hot weatherconditions. During this period, operators maneuvered power to as low as 92 percent to manage main condenser operations within procedural limits and then returned power to 100 percent.
On September 11, 2006, operators reduced power to about 80 percent in order to repair the "A" reactor turbine-driven feed pump. On September 12, 2006, operators returned power to 100 percent. On September 29, 2006, operators commenced reactor downpower maneuvers to conduct planned maintenance activities and ended the inspection period on September 30, 2006, at 82 percent power.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity andEmergency Preparedness1R01Adverse Weather Protection (71111.01)
a. Inspection Scope
During the week of August 21, 2006, the inspectors observed licensee activitiesassociated with the treatment of raw water systems to control populations of zebramussels. The inspectors observed infrequently performed test or evolution briefings, pre-shift briefings, and control room briefings to determine whether the briefings met criteria specified in the Perry Operations Section Expectations Handbook and Perry Administrative Procedure (PAP)-1121, "Conduct of Infrequently Performed Tests or Evolutions," Revision 4. The inspectors also reviewed prerequisites identified in licensee procedure PTI-GEN-P0024, "Mussel Treatment," Revision 11, to determine whether they were completed prior to the initiation of treatment on August 22, 2006. Finally, during the remainder of the inspection period, the inspectors periodically reviewed licensee activities and data collection as specified by licensee procedure PTI-GEN-P0023, "Mussel Monitoring," Revision 4, to determine whether mussel settlement was being properly monitored. This review represented one inspection sample.
b. Findings
No findings of significance were identified.
31R04Equipment Alignment (71111.04).1Semi-Annual Complete System Walkdown
a. Inspection Scope
The inspectors performed a complete walkdown of accessible portions of the residualheat removal (RHR) system to determine system operability and condition during themonth of July 2006. The RHR system was selected due to its risk significance. Theinspectors used valve lineup instructions (VLIs) and system drawings to accomplish theinspection.The inspectors observed selected switch and valve positions, electrical poweravailability, system pressure and temperature indications, component labeling, andgeneral material condition. The inspectors determined whether system configurationsand operating parameters were consistent with licensee procedures and drawings. The inspectors also reviewed open system engineering issues as identified in the licensee'sQuarterly System Health Report, outstanding maintenance work requests, and a sampling of condition reports (CRs) to determine whether problems and issues were identified, and corrected, at an appropriate threshold. The documents used for the walkdown are listed in the attached List of Documents Reviewed.This review represented one semi-annual complete system walkdown.
b. Findings
No findings of significance were identified..2Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors conducted a partial walkdown of t he system trains listed below todetermine whether the systems were correctly aligned to perform their designed safetyfunction. The inspectors used VLIs and system drawings during the walkdown. Thewalkdown included selected switch and valve position c hecks, and verification ofelectrical power to critical components. Finally, the inspectors evaluated other elements, such as material condition, housekeeping, and component labeling. The documents used for the walkdown are listed in the attached List of Documents Reviewed. The inspectors reviewed the following systems:*"B" standby liquid control (SLC) system during testing of the SLC "A" system; and*"A" and "B" annulus exhaust gas treatment system (AEGTS) trains followingmaintenance on the "A" AEGTS train.This review represented two quarterly partial system walkdown samples.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05AQ)
a. Inspection Scope
The inspectors walked down the following areas to assess the overall readiness of fireprotection equipment and barriers:*Turbine Building elevations 605', 620' and 624';*Fire Zones 1CC-5A and 2CC-5A, Unit 1 and Unit 2 Control Rooms;
- Technical Support Center;
- Reactor Recirculation Pump Carbon Dioxide Drywell Fire Suppression System;
- Turbine Building Lube Oil Room;
- Fire Zone 1AB-1, Auxiliary Building Unit 1, elevation 574';*Fire Zone 1AB-3, Auxiliary Building Unit 1, elevation 620';*Turbine Power Complex Building; and
- Fire Zone 1AB-1C, reactor core isolation cooling pump room, elevation 574'.Emphasis was placed on evaluating the licensee's control of transient combustibles andignition sources, the material condition of fire protection equipment, and the material condition and operational status of fire barriers used to prevent fire damage or propagation. The inspectors utilized the general guidelines established in FireProtection Instruction (FPI)-A-A02, "Periodic Fire Inspections," Revision 3; Perry Administrative Procedure (PAP)-1910, "Fire Protection Program," Revision 11; and PAP-0204, "Housekeeping/Cleanliness Control Program," Revision 15; as well as basic National Fire Protection Association Codes, to perform the inspection and to determine whether the observed conditions were consistent with procedures and codes.The inspectors observed fire hoses, sprinklers, and portable fire extinguishers todetermine whether they were installed at their designated locations, were in satisfactory physical condition, and were unobstructed. The inspectors also evaluated the physical location and condition of fire detection devices. Additionally, passive features such as fire doors, fire dampers, and mechanical and electrical penetration seals were inspected to determine whether they were in good physical condition. The documents listed in the List of Documents Reviewed at the end of this report were used by the inspectors during the inspection of this area.These reviews represented nine quarterly inspection samples.
b. Findings
IntroductionThe inspectors identified an unresolved item (URI 05000440/2006004-01) requiringfurther inspection. The URI was associated with a longstanding degraded condition of 5the drywell reactor recirculation pump carbon dioxide (CO 2) fire suppression system thatresulted in an insufficient CO 2 tank level.DescriptionOn August 1, 2006, the inspectors observed that the CO 2 suppression tank level for thereactor recirculation pump fire suppression system was 42 percent. This was below theminimum operability limit of 45 percent. The inspectors also noted that the tank wasleaking CO
2. On further review, the inspectors determined that the tank was below theminimum level to be considered operable in March 2006, October 2005, August 2005,
June 2005, May 2005, April 2005, October 2003, September 2003, August 2002, andJuly 2001. In addition, during reviews of licensee condition reports, the inspectors determined that the inoperability of the CO 2 tank was unnecessarily extended due to thelate arrival of CO 2 delivery trucks since 2005. The inspectors observed that the CO 2delivery was also delayed following the identification of a low tank level on August 1,2006. Licensee personnel performed procedure PTI-P54-P0016, "Carbon Dioxide Storage Tank Pressure and Level Verification," Revision 4, on August 2, 2006, and recorded tank level at 37 percent. On August 8, 2006, the inspectors observed that the CO 2 tank level had decreased to 10 percent due to the delay in CO 2 delivery.Perry License Condition C(6) required that the licensee implement and maintain in effectall provisions of the approved fire protection program as described in the Perry Final Safety Analysis Report (FSAR). Section 9A.5, Position C.8 of the FSAR stated that measures had been established to ensure conditions adverse to fire protection, such as failures, malfunctions, deficiencies, deviations, defective components, uncontrolled combustible materials, and nonconformances are promptly identified, reported, and corrected. Attachment 3 of PAP-1910, "Fire Protection Program/Fire Protection Functional Specifications," Revision 12, stated that the minimum required level for the reactor recirculation pumps CO 2 system was 45 percent (2460 lbs). Because the issue was associated with a fire protection system for the drywell andrequired the development of potential fire scenarios, the issue required further inspection by regional fire protection specialists in order to determine the significance of the issue. As a result, this issue is considered an unresolved item (URI 05000440/2006004-01) pending the development of potential drywell fire scenarios and the subsequent determination of the overall issue significance.
1R06 Flood Protection Measures (71111.06)
a. Inspection Scope
The inspectors performed an inspection of internal flooding vulnerabilities associatedwith the building roof drains. The inspection consisted of a review of the roof drain system design features described in the Updated Safety Analysis Report (USAR). Inaddition, the inspectors reviewed corrective action documents to determine whether previously identified deficiencies were appropriately prioritized and addressed. The inspectors walked down the roof drain system to determine whether observations were 6consistent with design. The inspectors also walked down the upper internal elevationsof major safety-related buildings for any indications of severe roof leakage problems. This review represented one inspection sample.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
a. Inspection Scope
On July 20, 2006, the resident inspectors observed licensed operator performance inthe plant simulator. The inspectors evaluated crew performance in the areas of:*clarity and formality of communication;*ability to take timely action in the safe direction;
- prioritizing, interpreting, and verifying alarms;
- correct use and implementation of procedures, including alarm responseprocedures;*timely control board operation and manipulation, including high-risk operator actions; and*group dynamics.The inspectors also observed the licensee's evaluation of crew performance todetermine whether the training staff had identified performance deficiencies and specified appropriate remedial actions. This review represented one inspection sample.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
.1Quarterly Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the licensee's implementation of the maintenance rulerequirements to determine whether component and equipment failures were identified and scoped within the maintenance rule and that select structures, systems, andcomponents (SSCs) were properly categorized and classified as (a)(1) or (a)(2) in accordance with 10 CFR 50.65. The inspectors reviewed station logs, maintenance work orders (WOs), selected surveillance test procedures, and a sample of CRs to determine whether the licensee was identifying issues related to the maintenance rule at 7an appropriate threshold and that corrective actions were appropriate. Additionally, theinspectors reviewed the licensee's performance criteria to determine whether the criteria adequately monitored equipment performance and to determine whether changes to performance criteria were reflected in the licensee's probabilistic risk assessment. During this inspection period, the inspectors reviewed the following SSCs:*containment airlock system; and*leak detection system.These reviews represented two quarterly inspection samples.
b. Findings
No findings of significance were identified.
.2 Periodic Evaluation
a. Inspection Scope
The inspectors examined the Maintenance Rule periodic evaluation report completed forthe period of May 31, 2003, through May 6, 2005. The inspectors reviewed a sample of (a)(1) Action Plans, Performance Criteria, Functional Failures, and Condition Reports to evaluate the effectiveness of (a)(1) and (a)(2) activities. These same documents were reviewed to verify that the threshold for the identification of problems was at anappropriate level and the associated corrective actions were appropriate. Also, the inspectors reviewed the maintenance rule procedures and processes. The inspectors focused the inspection on the following four systems:*high pressure core spray;*diesel generator;
- reactor recirculation; and
- plant radiation monitoring and process monitoring.The inspectors verified that the periodic evaluation was completed within thetime constraints defined in 10 CFR 50.65 (once per refueling cycl e, not to exceed24 months). The inspectors also ensured that the licensee reviewed maintenance rule goals, monitored SSC performance, reviewed industry operating experience, and made appropriate adjustments to the maintenance rule program as a result of the above activities.The inspectors verified that:
- the licensee balanced reliability and unavailability during the previous cycle,including a review of high safety significant SSCs;*(a)(1) goals were met, that corrective actions were appropriate to correct thedefective condition, including the use of industry operating experience, and that (a)(1) activities and related goals were adjusted as needed; and 8*the licensee established (a)(2) performance criteria, examined any SSCs that failedto meet their performance criteria, and reviewed any SSCs that have experienced repeated maintenance preventable functional failures including a verification that failed SSCs were considered for (a)(1).In addition, the inspectors reviewed maintenance rule self-assessments and auditreports that addressed the maintenance rule program implementation.These reviews represented four periodic inspection samples.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed the licensee's evaluation of plant risk, scheduling, configurationcontrol, and performance of maintenance associated with planned and emergent work activities to determine whether scheduled and emergent work activities were adequately managed in accordance with 10 CFR 50.65(a)(4). In particular, the inspectors reviewed the licensee's program for conducting maintenance risk assessments to determine whether the licensee's planning, risk management tools, and the assessment andmanagement of on-line risk were adequate. The inspectors also reviewed licensee actions to address increased on-line risk when equipment was out of service for maintenance, such as establishing compensatory actions, minimizing the duration of the activity, obtaining appropriate management approval, and informing appropriate plant staff, to determine whether the actions were accomplished when on-line risk was increased due to maintenance on risk-significant SSCs. The following assessments and/or activities were reviewed:*licensee's management of risk and work control during a period of elevated electricalpower grid risk during the weeks of July 24 and July 31, 2006;*licensee's management of risk and work control associated with maintenance on thecommon emergency diesel generator (EDG) exhaust hallway modification during theweek of August 14, 2006;*licensee's management of risk and work control associated with maintenance on theemergency service water intake structure during the week of August 28, 2006;*licensee's management of risk and work control associated with the replacement ofa containment isolation valve for the condensate storage and transfer system duringthe week of September 4, 2006;*licensee's management of risk and work control associated with maintenance onboth Division 1 EDG ventilation fans during the week of September 4, 2006;*licensee's management of risk and work control associated with the repair of the "A"turbine-driven reactor feed pump during the week of September 11, 2006; and*licensee's management of risk and work control associated with repairs to the "A"control complex chiller during the week of September 18, 2006.
9These reviews represented seven inspection samples.
b. Findings
No findings of significance were identified.
1R14 Operator Performance During Non-Routine Evolutions and Events
During the inspection period, this Inspection Procedure was deleted and activitiesperformed prior to deletion are now documented in Section 71153.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors selected CRs related to potential operability issues for risk-significantcomponents and systems. These CRs were evaluated to determine whether theoperability of the com ponents and systems was justified. The inspectors compared theoperability and design criteria in the appropriate sections of the Technical Specification(TS) and USAR to the licensee's evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintainoperability, the inspectors determined whether the measures were in place, wouldfunction as intended, and were properly controlled. Additionally, the inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. The inspectors reviewed the following issues:*an operability evaluation associated with the seismic qualification of the Division 1and Division 2 EDG flywheel covers on July 13, 2006;*an operability evaluation associated with a latent calculation error for a fire protectioncarbon dioxide system thermal relief valve affecting the primary containment systemon August 4, 2006;*an operability evaluation associated with the flooding analysis for a moderate energywater line break affecting the control complex switchgear rooms during the week of August 7, 2006;*an operability evaluation associated with the ASME (American Society of MechanicalEngineers) qualification of the relief valve for the suppression pool ma keup systemheat exchanger on July 14, 2006;*an operability evaluation associated with the inadvertent addition of ultra low sulfurfuel oil to the Division 3 EDG fuel oil storage tank on September 8, 2006; and*an operability evaluation associated with high particulate and acidity levels found in areactor core isolation cooling turbine oil sample on September 21, 2006.These reviews represented six inspection samples.
b. Findings
No findings of significance were identified.
101R19Post-Maintenance Testing (71111.19)
a. Inspection Scope
The inspectors evaluated the following post-maintenance testing (PMT) activities for risk-significant systems to ensure the following (as applicable): the effect of testing onthe plant had been adequately addressed; testing was adequate for the maintenanceperformed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written; and equipment was returned to its operational status following testing. The inspectors evaluated the activities against TS, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications. In addition, the inspectors reviewed CRsassociated with PMTs to determine whether the licensee was identifying problems and entering them in the corrective action program. The specific procedures and CRs reviewed are listed in the attached List of Documents Reviewed. The following post-maintenance activities were reviewed:*testing of the containment lower airlock inner door after maintenance that wasconducted on June 21, 2006;*testing of the electric motor-driven fire pump that was conducted on July 31, 2006;
- testing of the main generator hydrogen oil extractor pump that was conducted onJuly 21,2006;*testing of the reactor core isolation cooling system following maintenance on August 11, 2006;*testing of the average power range monitor channel "G" that was conducted onAugust 25, 2006;*testing of the reactor feed pump turbine "A" thrust bearing wear detection and tripsystem after repair on September 12, 2006;*testing of the reactor water cleanup leak detecti on system after repair on September 20, 2006; and*testing of a fuel pool cooling and cl eanup system motor-operated valve followingmaintenance on September 26, 2006.These reviews represented eight inspection samples.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed surveillance testing or reviewed test data for risk-significantsystems or components to assess compliance with TS, 10 CFR 50, Appendix B, andlicensee procedure requirements. The testing was also evaluated for consistency with the USAR. The inspectors verified that the testing demonstrated that the systems wereready to perform their intended safety functions. The inspectors determined whether 11test control was properly coordinated with the control room and performed in thesequence specified in the surveillance instruction (SVI), and if test equipment wasproperly calibrated and installed to support the surveillance tests. The proceduresreviewed are listed in the attached List of Documents Reviewed. The surveillanceactivities assessed were:*low pressure core spray system pump and valve in-service testing conducted onJuly 12, 2006;*high pressure core spray system essential service water pump and valve in-servicetesting on July 26, 2006;*Division 2 EDG monthly routine testing on August 15, 2006;
- SLC "B" system quarterly pump and valve in-service testing on August 17, 2006;*oscillation power range monitor "G" routine functional testing on August 21, 2006; and*containment isolation local leak rate test in-service testing on August 29, 2006.These reviews represented four in-service inspection samples and two routine testinginspection samples.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed documentation for a ventilation system modification to provideadditional air cooling for the auxiliary building during the week of July 24, 2006.The inspectors assessed the acceptability of this temporary configuration c hange bycomparing the 10 CFR 50.59 screening and evaluation information against the design basis, the Updated Final Safety Analysis Report (UFSAR), and the TS as applicable.
The comparisons were performed to ensure that the new configurations remained consistent with design basis information. The inspectors, as applicable, performed field verifications to ensure that the modifications were installed as directed; the modifications operated as expected; modification testing adequately demonstrated conti nued systemoperability, availability, and reliability; and that operation of the modifications did notimpact the operability of any interfacing systems. This review represented one inspection sample.
b. Findings
No findings of significance were identified.
121EP6Drill Evaluation (71114.06)
a. Inspection Scope
The inspectors observed activities in the simulator control room, the Technical SupportCenter, the Emergency Operations Facility, and Operations Support Center during anemergency preparedness dr ill conducted on September 16, 2006. The inspectionfocused on the ability of the licensee to appropriately classify emergency conditions,complete timely notifications, and implement appropriate protective action recommendations in accordance with approved procedures.This review represented one inspection sample.
b. Findings
No findings of significance were identified.4.
OTHER ACTIVITIES
4OA2 Identification and Resolution of Problems
.1Routine Review of Identification and Resolution of Problems
a. Inspection Scope
As discussed in previous sections of this report, the inspectors routinely reviewed issuesduring baseline inspection activities and plant status reviews to determine whether they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and thatadverse trends were identified and addressed.This is not an inspection sample.
b. Findings
No findings of significance were identified.
.2 Annual Sample Review
a. Inspection Scope
The inspectors selected the licensee's root cause evaluation associated with thelicensee's excursion from the maximum extended operating domain (MEOD) boundary during reactor power ascension on July 9, 2006. The inspectors selected this issue for detailed review because the issue was associated with the cross-cutting area of human performance. The inspectors reviewed the corrective actions associated with the event and reviewed the licensee's evaluation to determine whether licensing or design limits were exceeded.
13This review represented one inspection sample.
b. Findings and Observations
As a result of the root cause evaluation, the licensee identified three root causes:(1) weaknesses in the management, implementation, and oversight of the reactivity management program;
- (2) weaknesses in procedure use and adherence, and evolution control and monitoring, that led to inappropriate decisions; and
- (3) lack of organizational engagement. The licensee evaluated the MEOD boundary excursion for normal and limiting postulated transients and concluded that design and licensing limits were not exceeded. Licensee corrective actions included: a site-wide human performance stand-down, additional oversight expectations for reactivity management plans, added simulator training and training program changes for operations and reactor engineering personnel, and changes to the work management process. While not a finding, the inspectors noted that the licensee had previously identifiedweaknesses in the reactivity management process in May 2006. The inspectors also noted that the MEOD boundary was exceeded after operators made a decision to exceed a procedural administrative limit that was put in place to provide margin to the MEOD boundary and that this procedure allowed the limit to be exceeded in certain cases with the operations shift manager's approval. The inspectors determined that the operations and reactor engineering personnel were not aware that the MEOD limit had been exceeded until after the event had occurred.
4OA3 Event Followup
.1 Notification of Unusual Event
a. Inspection Scope
On June 20, 2006, a minor earthquake occurred that was centered about 3 milesnorthwest of Perry. The inspectors responded to the control room and observed the licensee's declaration of a Notice of Unusual Event and operator performance associated with the event. The licensee's actions included plant walkdowns to inspect for damage and ground water sampling to inspect for leaks. The licensee identified no adverse affects resulting from the earthquake. The inspectors conducted confirmatory walkdowns of safety significant areas of the plant and reviewed the licensee's actions to determine whether the actions were consistent with procedures and TS requirements.
b. Findings
No findings of significance were identified.This review represented the first of six inspection samples.
14.2LER 05000440/2006-003-00 Incorrect Wiring in the Division 1 Emergency DieselGenerator Results in a Fire Protection Program Violation. A discussion of this event, and an associated licensee-identified NCV, is contained inSection
4OA7 of this report.This review represented the second of six inspection samples..3Reactor Recirculation System Vortex and Reactivity Event
a. Inspection Scope
On July 6, 2006, control room operators responded to unexpected local power rangemonitor and rod block alarms that immediately reset. Operators determined that areactor recirculation system vortex shedding ev ent had occurred, which caused a briefneutron flux spike. The inspectors reviewed the operator performance associated with the reactivity event. The inspectors reviewed the licensee's actions to determine whether the actions were consistent with procedures and TS requirements.This review represented the third of six samples for this inspection procedure.
b. Findings
No findings of significance were identified.
.4 Reactor Downpower and Rod Control and Indication System (RCIS) Failure
a. Inspection Scope
On July 8, 2006, control room operators reduced reactor power to about 61 percent toconduct planned maintenance. Subsequently, a failure occurred in the RCIS that prevented rod withdrawal. The inspectors observed the operator performance associated with the power maneuvers and the operator response to the failure of RCIS. The inspectors reviewed the licensee's actions to determine whether the actions were consistent with procedures and TS requirements.This review represented the fourth of six samples for this inspection procedure.
b. Findings
No findings of significance were identified.
.5 Maximum Extended Operating Domain Boundary Excursion During Power Ascension
a. Inspection Scope
On July 9, 2006, control room operators conducted a reactor power ascension to100 percent power. While withdrawing rods, control room operators exceeded an 15administrative power to flow operating limit and questioned whether the plant remainedwithin the maximum extended operating domain boundary limit. On July 10, 2006, licensee personnel determined that the maximum extended operating domain boundaryline of the power to flow map was exceeded during the power ascension. The inspectors reviewed the operator performance associated with the power ascension that contributed to the domain boundary excursion. The inspectors reviewed the licensee's actions to determine whether the actions were consistent with procedures and TS requirements.This review represented the fifth of six samples for this inspection procedure.
b. Findings
No findings of significance were identified.
.6 Reactor Downpower for "A" Reactor Turbine-Driven Feed Pump Emergent Maintenance
a. Inspection Scope
On September 11, 2006, control room operators conducted a reactor power reduction to 80 percent power in order to troubleshoot an emergent thrust bearing wear indication system alarm on the "A" reactor turbine-driven feed pump. Operators started themotor-driven feed pump prior to the power reduction and then secured the "A" reactor turbine-driven feed pump after reaching 80 percent power. The inspectors observed the operator performance associated with the power reduction and the manipulation of the reactor feed system. The inspectors reviewed the licensee's actions to determinewhether the actions were consistent with procedures and TS requirements.This review represented the sixth of six samples for this inspection procedure.
b. Findings
No findings of significance were identified.
4OA5 Other Activities.1Review of World Association of Nuclear Operators (WANO) ReportThe inspectors completed a review of the interim report for the WANO May 2006 PeerReview, dated June 27, 2006. No additional followup is planned..2Licensee Strike Contingency Plans
a. Inspection Scope
The inspectors completed an evaluation of the adequacy of strike contingency plans andimplementation associated with the transition to the licensee's new contract with the labor union. The inspectors reviewed the adequacy of qualified personnel staffing, 16maintenance of reactor operation and facility security, and determined whether the planwas in compliance with TS and the CFR.
b. Findings
No findings of significance were identified.4OA6Meetings.1Exit MeetingOn September 28, 2006, the resident inspectors presented the inspection results toMr. L. Pearce, Site Vice President, and other members of his staff who acknowledged the findings. The inspectors asked the licensee whether any materials examined during theinspection should be considered proprietary. No proprietary information was identified..2Interim Exit MeetingAn interim exit meeting was conducted for:
- Maintenance Effectiveness Periodic Evaluation with Mr. J. Shaw, EngineeringDirector, on September 14, 2006.4OA7Licensee-Identified ViolationsThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of NRC requirements which meets the criteria of Section VI ofthe NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV. Cornerstone: Mitigating Systems*License Condition C(6), "Fire Protection," required the licensee to implement andmaintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report, as amended. The Updated Final Safety Analysis Report, Revision 12, Section 9A.6 Response L, "Fire Protection of Safe Shutdown Capability," referred to USAR Section 7.4.1.4, "Remote Shutdown System." USARSection 7.4.1.4 stated that the "Division 1 remote shutdown capability is desi gned tocontrol the required shutdown systems from outside the control room irrespective ofshorts, opens or grounds in the control circuit in the control room that may have resulted from an event causing an evacuation." Contrary to this requirement, on May 4, 2006, licensee personnel identified that the Division 1 EDG control room"pull-to-lock" control switch was not designed to isolate the control room from the local Division 1 EDG controls in the event of a control room fire and that a potentialfire induced hot short in the EDG logic circuit could have resulted in a failure to start or a spurious trip of the EDG even if control was transferred to local. The licensee implemented procedure changes to address the issue and entered the issue into 17their corrective action program as CR 06-01930, "Additional Fire ProtectionEvaluation Needed For EDG Circuit," dated May 2, 2006. The Region III SeniorReactor Analysts (SRAs) performed a Phase 3 SDP evaluation of the issue because Inspection Manual Chapter (IMC) 0609, Appendix F, "Fire Protection SDP," does not address control room evacuation scenarios. Based on information from the licensee's Individual Plant Examination for External Events (IPEEE), the control room panel fire scenario that could result in a fire-induced hot short and the unavailability of the Division 1 EDG does not result in a loss of offsite power. Additionally, fire spread from the Division 1 EDG control panel to the control room panels for offsite power controls was unlikely to occur because of the construction of the control panels and the separation of the panels. Therefore, a fire that wouldcause a loss of offsite power and result in the postulated hot short was not a credible fire. The SRAs determined that the finding was of very low safety significance (Green) due to the low likelihood of the postulated fire concurrent with a non-fire induced loss of power to Division 1 offsite power.ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- L. Pearce, Vice President-Nuclear
- F. von Ahn, General Manager, Nuclear Power Plant Department
- R. D. Gray, Maintenance Rule Program Engineer
- J. Lausberg, Manager, Regulatory Compliance
- G. Halnon, Director, Performance Improvement Initiative
- J. Messina, Manager, Operations
- M. Wayland, Director, Maintenance
- J. Shaw, Director, Nuclear Engineering
- S. Thomas, Manager, Radiation Protection
- K. Russell, Regulatory Affairs
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000440/2006004-01URIFailure to Promptly Correct Degraded Condition of theReactor Recirculation Pump CO
Fire Suppression System(Section 1R05 )
Closed
- 05000440/LER-2006-003-00LERIncorrect Wiring in the Division 1 Emergency DieselGenerator Results in a Fire Protection Program Violation
(Section 71153)
- 2
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection.
- Inclusion on this list doesnot imply that the NRC inspectors reviewed the documents in their entirety, but rather that selected sections of portions of the documents were evaluated as part of the overall inspection effort.
- Inclusion of a document on this list does not imply NRC acceptance of the document orany part of it, unless this is stated in the body of the inspection report.Section 1R01 Adverse Weather ProtectionPAP-1121; Conduct of Infrequently Performed Tests or Evolutions; Revision 4PTI-GEN-P0023; Mussel Monitoring; Revision 4
- PTI-GEN-P0024; Mussel Treatment; Revision 11
- CR 06-03857; Delays Encountered During Performance of the Zebra Mussel Treatment; dated August 22, 2006Section 1R04 Equipment AlignmentVLI-E12; Residual Heat Removal System Valve Lineup Instruction; Revision 6; datedAugust 12, 2005
- CR 05-05994; Potential Preconditioning During RHR Valve Stroke SVI; dated August 12, 2005CR 05-06551; PCR [Procedure Change request]
- SVI-E12-T2003 Errors in Procedure; dated September 12, 2005
- CR 06-01063; Inoperability Time for RHR Pump B Due to Momentary Low Discharge Pressure;dated March 4, 2006
- CR 06-02390; Agastat Relay Installed in Incorrect Orientation; dated May 26, 2006
- CR 06-03287; NRC Identified - 1E12F0547C Leaking by; dated July 24, 2006VLI-C41; Standby Liquid Control System Valve Lineup Instruction; Revision 8; dated September 6, 2005
- CR 06-01076; SLC [Standby Liquid Control] Pump A Oil Leak Due to Being Overfilled; datedMarch 2, 2006
- CR 06-01147; Results of Plant Walkdown Reported to the Control Room by the NRC Resi dent;dated March 9, 2006
- CR 06-01737; Standby Liquid Control Injection Pump Leaking Oil; dated April 18, 2006CR 06-01776; Performance Vibration Monitoring of 1C41C0001A Not on PWIS; dated April 21, 2005
- CR 06-02597; SLC A Pump Sightglass Weepage; dated June 7, 2006
- CR 05-07658; Filter Plenum Door Not Properly Dogged for 1M15D0001B; dated November 17,
- 2005
- CR 06-6379; 1M15C0001A Low Flow Alarm Being Received with Fan Normal Operation; dated September 15, 2006
- VLI-M15; Annulus Exhaust Gas Treatment System (Unit 1); Revision 4
- System Description Manual; Annulus Exhaust Treatment System; Revision 4
- 3Section 1R05 Fire ProtectionFPI-TB; Turbine Building; Revision 2FPI-0CC; Control Complex; Revision 5
- PAP-1910, Fire Protection Program; Revision 12
- WO 200213008; Carbon Dioxide Storage Tank Pressure and Capacity Verification; dated August 2, 2006
- PTI-P54-P0016; Carbon Dioxide Storage Tank Pressure and Level Verification; Revision 4
- CR 03-05887; Continual Degradation of the Fire Protection Carbon Dioxide Storage Tanks;dated October 23, 2003
- CR 06-02577; Notification Generated for CO2 Tank A006; dated June 3, 2006CR 06-02453; CO2 Tank #6 Compressor Not Maintaining Pressure; dated May 31, 2006
- CR 06-01440; Unplanned Impairment for Drywell CO2 System; dated March 29, 2006
- CR 06-00794; CO2 Storage Tank Bleeder Valve; dated February 16, 2006
- CR 05-07988; CO2 Tank #6 (PY-1P54A0006) Has Had a Long History of Losing Pressure;
dated December 9, 2005
- CR 05-07112; Unplanned Impairment for Reactor Recirculation CO2 System; dated October 12, 2005
- CR 05-06249; Unplanned Fire Impairment for Reactor Recirculation Pumps CO2 system; datedAugust 24, 2005
- FPI-1AB; Auxiliary Building, Revision 2
- CR 06-6349; Building Roof Repairs Inadvertently Covered Parapet Wall Scuppers; dated September 14, 2006
- CR 06-6866; NRC Resident Noted RCIC [Reactor Core Isolation Cooling] Pump OutboardBearing Trico Oiler Rotated; dated September 26, 2006CR 06-6892; NRC Resident Noted RCIC Pump Outboard Bearing to Trico Oiler Pipe is Sloped;dated September 27, 2006
- FPI-1AB; Unit 1 - RCIC System Pump Room; Revision 2Section 1R06 Flood ProtectionCalculation 50:26.000; Evaluation of Roof Drain Capacity; dated May 13, 2005CR 04-04300; Roof Drain Calculations Can Not be Found; dated August 13, 2004
- CR 04-06761; Numerous Leaks from Various Plant Roofs; dated December 23, 2004
- CR 05-05415; Roof Leaks Continue to Pose a Threat to Vital Plant Equipment; dated July 16, 2005
- USAR Section 2.4.2.3; Effects of Local Intense Precipitation; Revision 12Section 1R11 Licensed Operator Requalification
- OTLC-3058200609_PY_SGD; Simulator Guide; dated July 3, 2006; Revision 0
- Section 1R12 Maintenance Effectiveness Maintenance Rule Monitor; P53 Containment Airlock System; dated August 1, 2006CR 06-00523; Leakage in Excess of Allowable for 8 Hour Duration Test Per SVI-P53-T7312;
dated February 2, 2006
- 4CR 06-01386; Apparent Cause CRCAS to Track Orders to Completions Accepted but NeverScheduled; dated March 22, 2006
- CR 06-02019; Upper Airlock Outer Door Declared Inoperable Due to Faulty Pressure Switch;
dated May 7, 2006
- CR 06-02047; Drywell Airlock Inner Door Mechanism Binding; dated May 9, 2006
- CR 06-02023; FME [Foreign Material Exclusion] Discovered in Upper Containment Pressure Switch Tubing (1P53N702A); dated May 7, 2006
- CR 06-02083; Precurser [sic] to a Missed Surveillance; dated May 10, 2006CR 06-02230; ECP Revision Required Due to Drawing Changes; dated May 16, 2006
- CR 06-02470; Upper Air Lock Hinge Door Will Not Receive Grease; dated May 31, 2006CR 06-02703; Lower Containment Airlock Inner Door Large Seal; dated June 13, 2006
- CR 06-02681; Lower Containment Outer Door Unsafe Light Lit; dated June 14, 2006
- CR 06-02730; Unplanned Inoperability for Lower Containment Airlock Inner Door; datedJune 16, 2006
- CR 06-02887; Loss of Power to Lower Containment Airlock Panel; dated June 28, 2006
- CR 06-02691; Bent Valve Stem - Lower Containment Lock; dated June 14, 2006CR 06-03244; Elevated Turbine Building (East) Area Temperatures; dated July 21, 2006
- CR 06-00292; NRC Pre-Inspection ID - Steam Tunnel Temperature Design Information; datedJanuary 19, 2006
- CR 06-01715; E31-R613C Reading is Not Consistent with Local Indication; dated April 15, 2006CR 05-07643; Drywell FDS [Floor Drain Sump] Recorder Failed. Possible Repeat Maintenance Item; dated November 17, 2005
- CR 05-01031; 1E31N692 for RPV [Reactor Pressure Vessel] Head Flange Pressure Slowly Trending Up; dated February 12, 2005
- CR 04-0426; Audit
- PY-C-04-03, RCS [Reactor Coolant System] Leakage Detection Instrumentation TS 3.4.7 Compliance; dated September 3, 2004PAP-1125; Monitoring the Effectiveness of the Maintenance Program Plan; Revision 7
- PYBP-PES--0001; Maintenance Rule Reference Guide; Revision 13
- Periodic Assessment of Maintenance Rule Program - Perry Nuclear Power Plant; Cycle 10;
- May 31, 2003 through May 6, 2005; dated June 30, 2006
- Maintenance Rule Program Self Assessment; dated June 10, 2005
- Plant System Health Report; E22 - High Pressure Core Spray System; 2003 to 2006
- Plant System Health Report; B33 - Reactor Recirculation System; 2003 to 2006
- Plant System Health Report; R43 - Division 1 & 2 Diesel Generator System; 2003 to 2006
- Plant System Health Report; D17 - Plant Radiation Monitoring & Process Monitoring; 2003 to
- 2006
- Maintenance Rule (a)(1) Goal Setting & Goal Monitoring; Reactor Recirculation; datedJanuary 6, 2005
- Maintenance Rule (a)(1) Goal Setting & Goal Monitoring; Plant Radiation Monitoring; datedJuly 20, 2004
- Maintenance Rule (a)(1) Goal Setting & Goal Monitoring; Diesel Generator; dated July 20, 2004Maintenance Rule (a)(1) Goal Setting & Goal Monitoring; HPCS; dated October 23, 2002
- CR 04-03757; The Offgas Pipe Monitor Indicated Off Scale High; dated July 20, 2004CR 04-06649; During Operability Test HPCS Waterleg Pump Discharge Low Alarm Locked In;dated December 17, 2004
- CR 05-04114; During Test Water Was Found Leaking From Division 2 EDG Crankcase Exhaust; dated May 6, 2005
- 5CR 06-02024; Received B Reactor Recirculation Hydraulic Power Unit Low Tank Oil Alarm;dated May 8, 2006
- Maintenance Rule Expert Panel Meeting No. 237; dated August 11, 2005Section 1R13
- Maintenance Risk Assessments and Emergent Work ControlPerry Work Implementation Schedule; Week 04, Period 6Perry Work Implementation Schedule; Week 05, Period 6
- NOP-OP-1007; Grid Risk Determination; Revision 2
- Perry Work Implementation Schedule; Weeks 08/09, Period 6
- Maintenance Risk Evaluation; Week 10, Period 6; Revision 1
- Perry Work Implementation Schedule; Week 10, Period 6
- Perry Work Implementation Schedule; Week 12, Period 6
- Maintenance Risk Evaluation; Week 12, Period 6; Revision 1Section 1R15 Operability EvaluationsCR 06-03071; EDG Flywheel Coverguard is Not Seismically Qualified for the Division 1 & 2EDGs; dated July 11, 2006
- CR 06-03357; Latent Issue Error Found in Calculation P54-026 R/0; dated July 27, 2006CR 06-03505; Pipe Cracks and Resultant Flood 620'-6" Control Complex; dated August 3, 2006
- CR 06-03105; Relief Valve Has Not Been Tested Within Required Frequency; dated July 13,
- 2006
- Operability Determination; Ultra Low Sulfur #2 Fuel Inadvertently Added to Division 3 DieselGenerator Fuel Oil Storage Tank; dated September 8, 2006CR 06-06557; Lube Oil Analysis Indicates Expedited Maintenance on RCIC Turbine; datedSeptember 21, 2006Section 1R19 Post-Maintenance TestingGMI-176; Containment Airlock Door Maintenance; Revision 4CR 06-02730; Unplanned Inoperability for Lower Containment Airlock Inner DoorCR 06-02801; Airlock Lower Inner Door 3-Way Valve (1P53F0578B) Found Not Assembled Correctly; dated June 21, 2006
- WO 200202745; Electric and Diesel Fire Pump Functional Test; dated July 31, 2006
- WO 200199809; Generator Hydrogen Seal Oil Vacuum Pump; dated February 14, 2006WO
- 200172077; RCIC Pump and Valve Operability Test; dated August 14, 2006WO
- 200222604; APRM [Average power Range Monitor] G Channel Calibration; dated August 25, 2006
- WO 200226624; Troubleshoot and Repair RFPT [Reactor Feed Pump Turbine] "A" Thrust Bearing Wear Detector Alarm; dated September 9, 2006
- SOI-N27; Feedwater System; Revision 29
- WO 200227613; RWCU [Reactor Water Cleanup] Flow Dynamic Compensator; dated September 20, 2006
- SVI-G41-T2001; Fuel Pool Cooling and Cleanup System Pump and Valve Operability Test;Revision 8
- 6PMI-0030; Maintenance of Limitorque Valve Operators; Revision 13
- WO 200138838; Containment Pool Influent Isolation Valve; dated September 26, 2006Section 1R22 Surveillance TestingNOP-WM-2003; Work Management Surveillance Process; Revision 0SVI-E21-T2001; Low Pressure Core Spray System Pump and Valve Operability Test; Revision 19
- CR 06-00359; LPCS Suppression Pool Suction Valve Undersized Fuses; dated January 24, 2006
- CR 06-00460; Calculation E21-014, R/3 Has an Apparent Error in its Methodology; datedJanuary 31, 2006
- WO 200172082; Low Pressure Core Spray Pump and Valve Operability Test; dated July 13, 2006
- SVI-P45-T2003; High Pressure Core Spray Essential Service Water Pump and Valve Operability Test; Revision 12
- CR 06-03322;
- SVI-P45-T2003 Procedure Change Request; dated July 26, 2006
- CR 06-03341; Unsat Observation -
- CR 06-03358; Non-consequential Rounding Error in
- SVI-P45-T2003; dated July 26, 2006
- CR 06-03310; Inability to Meet Hourly Adherence PWIS Activity (SVI-P45-T2003); datedJuly 26, 2006
- CR 06-03408; NRC Identified Issue - Recording/Rounding Practices During SurveillanceTesting; dated July 28, 2006
- SVI-R43-T1318; Diesel Generator Start and Load Division 2; Revision 10
- CR 06-03707; SOI [System Operating Instruction] Step Inappropriately NA'd; dated August 15, 2006
- CR 06-03200; Division 2 DG Flywheel Cover Fasteners Missing; dated July 19, 2006
- CR 06-03156; PM [Preventative Maintenance] Past Its Overdue Without an Approved Deferral;dated July 17, 2006
- SVI-C41-T2001-B; Standby Liquid Control B Pump and Valve Operability Test; Revision 9CR 06-02784; Particulate Counts Increasing to Unacceptable Range; dated July 20, 2006CR 06-02596; SLC "B" Coupling Oil Separating from the Grease; dated June 7, 2006WO
- 200164637; Standby Liquid Control B Pump and Valve Operability Test; dated August 18, 2006
- SVI-C41-T2001-B; Standby Liquid Control B Pump and Valve Operability Test; Revision 9WO200171463; OPRM [Oscillating Power Range Monitor] Channel G Functional for1C51-K603G; dated August 21, 2006
- SVI-M14T9313; Type C Local Leak Rate Test of 1M14 Penetration V313; dated August 28, 2006
- SVI-M14T9314; Type C Local Leak Rate Test of 1M14 Penetration V314; dated August 28, 2006Section 1R23 Temporary Plant ModificationsTM 06-0011; M38 Auxiliary Building Ventilation Intake on the Auxiliary Building Roof; datedJuly 31, 2006
- 7Section 1EP6 Drill EvaluationEmergency Plan Drill Guidebook; Training Drill September 16, 2006CR 06-6259; ERO [Emergency response Organization] Training Drill PAR [Protective ActionRecommendation] Incorrect; dated September 12, 2006
- CR 06-6310; ERO Training Drill Incorrect EAL [Emergency Action Level] Declaration; datedSeptember 13, 2006Section 4OA2 Identification and Resolution of Problems
- CR 06-03047; MEOD Boundary Line Exceeded During Power Ascension on July 9
th; dated July 10, 2006
- CR 06-03902; CNRB [Company Nuclear Review Board] - Additional Interim InterventionMeasures For Operation Above MEOD Limit; dated August 28, 2006
- Control Room Operator Logs; dated July 9-11, 2006Section 4OA3 Event Followup and Notices of Enforcement DiscretionControl Room Logs; dated July 6, 2006IOI-3; Power Changes; Revision 26
- FTI-B0002; Control Rod Movements; Revision 8
- ONI-C51; Unplanned Changes in Reactor Power or Reactivity; Revision 20
- PDB-A0006; Power Flow Map; Revision 11
- CR 06-02993; Reactor Vortex Event; dated July 6, 2006
- ONI-C11-1; Inability to Move Control Rods; Revision 10
- Control Room Logs; dated July 8-9, 2006
- CR 06-03038; Targeted Control Rod Pattern Not Achieved During July 8
th Down Power; datedJuly 9, 2006
- CR 06-03047; MEOD Boundary Line Exceeded During Power Ascension on July 9
th; dated July 10, 2006
- CR 06-03158;
- ONI-C51 Entry Not Evaluated for Exceeding MEOD on 7/09/06; dated July 17, 2006
- Licensee Personnel Statements; MEOD Boundary Line Exceeded; dated July 10-12, 2006Reactivity Plan; dated July 7, 2006
- PYBP-POS-0011; Reactivity Plans; Revision 0
- NOP-OP-1004; Reactivity Management; Revision 3
- Operations Night Order; dated July 10, 2006
- Control Room Logs; dated September 10-11, 2006
- CR 06-01930; Additional Fire Protection Evaluation Needed For EDG Circuit; dated May 2, 2006
- 8
LIST OF ACRONYMS
USEDAEGTSannulus exhaust gas treatm
ent system CFRCode of Federal RegulationsCRcondition reportEDGemergency diesel generator
FENOCFirstEnergy Nuclear Operating Company
FPIFire Protection Instruction
FSARFinal Safety Analysis Report
IMCInspection Manual Chapter
LERLicensee Event Report
MEODmaximum extended operating domain
NCVnon-cited violation
NRCNuclear Regulatory Commission
PAPPerry Administrative Procedure
PMTpost-maintenance testing
RCISRod Control and Indication System
RHRresidual heat removal
SSCstructures, systems, and componentsSVIsurveillance instruction
TSTechnical Specification
UFSARUpdated Final Safety Analysis Report
USARUpdated Safety Analysis Report
VLIValve Lineup Instruction
WANOWorld Association Of Nuclear Operators