IR 05000325/2006003: Difference between revisions

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{{Adams|number = ML062090441}}
#REDIRECT [[IR 05000324/2006003]]
 
{{IR-Nav| site = 05000325 | year = 2006 | report number = 003 }}
 
=Text=
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[[Issue date::July 28, 2006]]
 
Carolina Power and Light CompanyATTN:Mr. James ScarolaVice PresidentBrunswick Steam Electric Plant P. O. Box- 10429-
Southport, NC 28461
 
SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTIONREPORT NOS. 05000325/2006003 AND 05000324/2006003
 
==Dear Mr. Scarola:==
On June 30, 2006, the US Nuclear Regulatory Commission (NRC) completed an inspection atyour Brunswick Units 1 and 2 facilities. The enclosed integrated inspection report documentsthe inspection findings, which were discussed on July 18, 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.As an incentive to encourage licensee participation in the International Atomic Energy AgencyOperational Safety Review Team (OSART) Missions, the NRC determined that, for those NRCbaseline inspections that overlap, either in part or fully, with an OSART review, a one-time regulatory credit (reduction in baseline inspection program), would be granted. Based on a review of the inspection report from an OSART inspection conducted at Brunswick in May, 2005, the NRC determined that Brunswick qualified for a 25% reduction of the inspection effortfor two NRC inspection procedures (IPs) documented in the enclosed report. Specifically,credit was given for IP 71114.03, Emergency Response Organization Augmentation, and IP 71114.05, Correction of Emergency Preparedness Weaknesses and Deficiencies. As such, the scope of the inspection of these procedures was reduced by 25%. This report documents one NRC-identified finding of very low safety significance (Green). Thefinding was determined to involve a violation of NRC requirements. However, because of thevery low safety significance and because it had been entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV), in accordance withSection VI.A.1 of the NRC's Enforcement Policy. If you contest this NCV, you should provide aresponse within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRCResident Inspector at the Brunswick Steam Electric Plant.
 
CP&L2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system(ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
 
Sincerely,/RA/Paul E. Fredrickson, ChiefReactor Projects Branch 4 Division of Reactor ProjectsDocket Nos.: 50-325, 50-324License Nos:DPR-71, DPR-62
 
===Enclosure:===
Inspection Report 05000325, 324/2006003
 
===w/Attachment:===
Supplemental Informationcc w/encl: (See page 3)
CP&L2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's document system(ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
 
Sincerely,/RA/Paul E. Fredrickson, ChiefReactor Projects Branch 4 Division of Reactor ProjectsDocket Nos.: 50-325, 50-324License Nos:DPR-71, DPR-62
 
===Enclosure:===
Inspection Report 05000325, 324/2006003
 
===w/Attachment:===
Supplemental Informationcc w/encl: (See page 3)X PUBLICLY AVAILABLE G NON-PUBLICLY AVAILABLEG SENSITIVE X NON-SENSITIVEADAMS: X YesACCESSION NUMBER:__ML062090441 OFFICERII:DRPRII:DRPRII:DRPRII:DRSRII:DRSRII:DRSRII:DRSSIGNATUREEMD /RA/JDA /RA/TXN /RA/MAS /RA/NLS /RA/RCC /RA/NAMEEDipaoloJAustinTNazarioMScottNStaplesRChouDATE07/27/200607/27/200607/27/200607/28/200607/28/200607/27/2006 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO OFFICIAL RECORD COPY DOCUMENT NAME: E:\Filenet\ML062090441.wpd CP&L3cc w/encl:James W. Holt, Manager Performance Evaluation and Regulatory Affairs PEB 7 Carolina Power & Light Company Electronic Mail DistributionEdward T. O'Neil, ManagerTraining Carolina Power & Light Company Brunswick Steam Electric Plant Electronic Mail DistributionRandy C. Ivey, ManagerSupport Services Carolina Power & Light Company Brunswick Steam Electric Plant Electronic Mail DistributionGarry D. Miller, ManagerLicense Renewal Progress Energy Electronic Mail DistributionLenny Beller, SupervisorLicensing/Regulatory Programs Carolina Power and Light Company Electronic Mail DistributionDavid T. ConleyAssociate General Counsel - Legal Dept.
 
Progress Energy Service Company, LLC Electronic Mail DistributionJames RossNuclear Energy Institute Electronic Mail DistributionJohn H. O'Neill, Jr.Shaw, Pittman, Potts & Trowbridge 2300 N. Street, NW Washington, DC 20037-1128Beverly Hall, Acting DirectorDivision of Radiation Protection N. C. Department of Environment and Natural Resources Electronic Mail Distribution Chairman of the North Carolina Utilities Commission c/o Sam Watson, Staff Attorney Electronic Mail DistributionRobert P. GruberExecutive Director Public Staff NCUC 4326 Mail Service Center Raleigh, NC 27699-4326Public Service CommissionState of South Carolina P. O. Box 11649 Columbia, SC 29211David R. SandiferBrunswick County Board of Commissioners P. O. Box 249 Bolivia, NC 28422Warren LeeEmergency Management Director New Hanover County Department of Emergency Management P. O. Box 1525 Wilmington, NC 28402-1525Distribution w/encl: (See page 4)
CP&L4Report to from Paul E. Fredrickson dated July 28, 2006
 
SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTIONREPORT NOS. 05000325/2006003 AND 05000324/2006003Distribution w/encl:B. Mozafari, NRR L. Slack, RII EICS RIDSRIDSNRRDIPMLIPB PUBLIC EnclosureU. S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos:50-325, 50-324 License Nos:DPR-71, DPR-62 Report Nos:05000325/2006003 and 05000324/2006003 Licensee:Carolina Power and Light (CP&L)
Facility:Brunswick Steam Electric Plant, Units 1 & 2 Location:8470 River Road SESouthport, NC 28461Dates:April 1, 2006 through June 30, 2006 Inspectors:E. DiPaolo, Senior Resident InspectorJ. Austin, Resident Inspector M. Scott, Senior Reactor Inspector (1R02, 1R17.2)N. Staples, Reactor Inspector (1R02, 1R17.2)
R. Chou, Reactor Inspector (1R02, 1R17.2)
T. Nazario, Reactor Inspector [in-office] (1R17.1)Approved by:Paul Fredrickson, ChiefReactor Projects Branch 4 Division of Reactor Projects EnclosureEnclosure
 
=SUMMARY OF FINDINGS=
IR 05000325/2006003, 05000324/2006003; 04/01/2006 - 06/01/2006;  Brunswick SteamElectric Plant, Units 1 and 2; Equipment Alignment.The report covered a 3-month period of inspection by resident inspectors, one senior reactorinspector, and four reactor inspectors. One Green non-cited violation (NCV) was identified.
 
The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercialnuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3,dated July 2000.A.NRC-Identified and Self-Revealing Findings
 
===Cornerstone: Mitigating Systems===
: '''Green.'''
An NRC-identified non-cited violation was identified for failure to meet TechnicalSpecification (TS) 5.4.1, Procedures. Specifically, the temporary modification process was not followed when implementing a temporary change to the Unit 2 reactor core isolation cooling keepfill system. As a result, appropriate reviews of the impact onreactor core isolation cooling system operability were not performed. This resulted inthe Unit 2 reactor core isolation cooling system being inoperable due to the potential ofvoiding the reactor core isolation cooling pump discharge piping during certain scenarios. This finding is more than minor because it is associated with operating equipment lineupand affected the Mitigating System Cornerstone objective to ensure the reliability ofsystems that respond to initiating events to prevent undesirable consequences. Thefinding was determined to be of very low safety significance (Green) because it did not represent an actual loss of safety function for greater than the TS allowed outage time.
 
The inspectors determined that the cause of this finding is a performance aspect of the human performance cross-cutting area, in that the cause was due to personnel failing tofollow the temporary modification process (Section 1R04).
 
===B. Licensee Identified Violations===
None EnclosureEnclosure
 
=REPORT DETAILS=
Summary of Plant StatusUnit 1 began the report period in Mode 5 (Refueling) and in Refueling Outage (RFO) B116R1. Mode 4 (Cold Shutdown) was achieved on April 4, and a unit startup was commenced on April
 
===6. The unit entered Mode 1 (Power Operation) on April 7, and synchronized with the grid onApril 8 to complete the RFO (35 days). On April 15, with power being held at 98 percent due to===
 
the review of new feedwater flow measurement venturi's, the unit performed an unplanned downpower to 79 percent as a result of the B circulating water intake pump tripping due to an instrumentation problem. Unit 1 achieved full power later that day. On May 18, the unit performed an unplanned downpower to approximately 86 percent due to high temperature on the main generator output B phase bus caused by a closed bus duct air cooling damper. The unit returned to full power later that day. The unit performed an unplanned downpower to approximately 91 percent due to securing the B circulating water intake pump when a diver experienced an emergency situation while cleaning the pumps associated trash rack. Full power was achieved later that day. On June 16, the unit performed a planned downpower to approximately 60 percent to facilitate fuel leak suppression testing. After successfullyidentifying and suppressing one leaking fuel assembly, power ascension was commenced. Full power was achieved on June 21. Another unplanned downpower to approximately 83 percent was performed on June 24, when the C circulation water intake pump tripped due to an instrumentation problem. The unit returned to full power later that day.Unit 2 began the report period at approximately 52 percent in order to facilitate control rodscram time testing, and main turbine and main steam valve testing. The unit returned to full power on April 3. On May 19, Unit 2 commenced a plant shutdown for a midcyle RFO (B217M1) in order to replace leaking fuel assemblies. Mode 5 (Refueling) was achieved on May 21. The unit entered Mode 2 (Startup) on May 28 and Mode 1 (Power Operation) on May 30. Full power was achieved on June 4, where the unit remained for the remainder of the inspection period.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection
 
====a. Inspection Scope====
The inspector's reviewed the licensee's preparations for severe weather conditions priorto hurricane season and hot weather. The inspectors reviewed the results of multi-discipline-attended preparation meetings and reviewed the station's procedures for severe weather warnings (i.e., hurricanes). The inspectors toured and reviewed a sampling of design features (e.g., missile shields, severe weather doors, sumps) of the nuclear service water and emergency diesel generator buildings (1 adverse weather sample of 2 systems) to verify that they would remain functional when challenged byadverse weather. Documents reviewed are listed in the Attachment.
 
4EnclosureEnclosure
 
====b. Findings====
No findings of significance were identified.
{{a|1R02}}
==1R02 Evaluations of Changes, Tests or Experiments==
 
====a. Inspection Scope====
The inspectors reviewed selected samples of evaluations to confirm that the licensee had appropriately considered the conditions under which changes to the facility,Updated Final Safety Analysis Report (UFSAR), or procedures may be made, and tests conducted, without prior NRC approval. The inspectors reviewed evaluations for sevenchanges and additional information, such as calculations, supporting analyses, the UFSAR, and drawings to confirm that the licensee had appropriately concluded that the changes could be accomplished without obtaining a license amendment. The seven evaluations reviewed are listed in the Attachment.The inspectors also reviewed samples of changes for which the licensee haddetermined that evaluations were not required, to confirm that the licensee's conclusionsto "screen out" these changes were correct and consistent with 10 CFR 50.59. The eighteen "screened out" changes reviewed are listed in the Attachment.The inspector also reviewed programmatic action requests (ARs, corrective actiondocuments) to confirm that problems were identified at an appropriate threshold, were entered into the corrective action process, and appropriate corrective actions had been initiated.
 
====b. Findings====
No findings of significance were identified.
{{a|1R04}}
==1R04 Equipment Alignment.1Partial System Walkdowns==
 
====a. Inspection Scope====
The inspectors performed three partial walkdowns of the below listed systems to verifythat the systems were correctly aligned while the redundant train or system wasinoperable or out-of-service (OOS) or, for single train risk significant systems, while thesystem was available in a standby condition. The inspectors assessed conditions suchas equipment alignment (i.e., valve positions, damper positions, and breaker alignment)and system operational readiness (i.e., control power and permissive status) that couldaffect operability. The inspectors verified that the licensee had identified and resolvedequipment alignment problems that could cause initiating events or impact mitigating system availability. The inspectors reviewed Administrative ProcedureADM-NGGC-0106, Configuration Management Program Implementation, to verify that 5EnclosureEnclosureavailable structures, systems or components (SSCs) met the requirements of theconfiguration control program. Documents reviewed are listed in the Attachment.*Unit 2 residual heat removal/residual heat removal service water systems onMay 21, 2006 while in shutdown cooling mode prior to core floodup.*Unit 1 B loop of core spray when A loop was OOS on June 8, 2006
*Unit 2 reactor core isolation cooling (RCIC) system on June 26, 2006 (risksignificant single train)
 
====b. Findings====
 
=====Introduction.=====
An NRC-identified Green NCV was identified for failure to meet TS 5.4.1, Procedures, in that the temporary modification process was not followed when implementing a temporary change to the Unit 2 reactor core isolation cooling keepfill system.
 
=====Description.=====
On June 22, 2006, the licensee identified that the Unit 2 RCIC discharge piping keepfillpressure rose above the normal setpoint which resulted in lifting of the RCIC pump suction relief valve. On June 24, 2006, efforts were made to rebuild the RCIC keepfill pressure control valve (2-E51-PCV-3006); but during the rebuild, the licensee noted that pressure was still rising, indicating a leaking keepfill bypass line valve. On June 26,  aflush of the bypass valve was performed and pressure continued to increase. As a compensatory action to minimize the pressure increase, a vent was opened at atest connection for a keepfill pressure indicator (2-E51-PI-3005). This allowed thelicensee to maintain discharge piping pressure in the normal range during the maintenance by allowing a continuous vent of the keepfill system. The inspectorsquestioned whether the change could affect RCIC system operability with a loss ofkeepfill system pressure (i.e., loss of power to the demineralized water pumps). The licensee informed the inspector that system operability was not effected when in itsnormal standby lineup (i.e., RCIC pump suction lined up to the condensate storage tank). However, with the RCIC system suction lined up to the suppression pool, whichwas the case at the time, there was a potential of voiding the RCIC pump dischargepiping under certain scenarios which could lead to unacceptable pipe water hammer during subsequent pump starts. Subsequently, operators declared RCIC inoperable.
 
The inspectors determined that the licensee had failed to appropriately follow the temporary modification process per Nuclear Generation Group Standard Procedure EGR-NGGC-0005, Engineering Change, when implementing this temporary change to the Unit 2 RCIC keepfill system. As a result, appropriate reviews of the impact on RCICsystem operability were not performed. This resulted in rendering the Unit 2 RCICsystem inoperable on June 26, 2006 due to the potential of voiding the RCIC pumpdischarge piping during certain scenarios.
 
6EnclosureEnclosureAnalysis.The failure to appropriately follow the temporary modification process, which resulted in the Unit 2 RCIC system being inoperable on June 26, 2006, is a performancedeficiency. This issue is more than minor because it is associated operating equipment lineup and affected the Mitigating System Cornerstone objective to ensure the reliabilityof systems that respond to initiating events to prevent undesirable consequences. Thefinding was determined to be of very low safety significance (Green) because it did not represent an actual loss of safety function for greater than the TS Allowed outage time.
 
The inspectors determined that the cause of this finding is a performance aspect of the human performance cross-cutting area, in that the cause was due to personnel failing tofollow the engineering change (EC) process.Enforcement.TS 5.4.1 requires that written procedures shall be implemented covering the applicableprocedures recommended in Regulatory Guide 1.33, Appendix A, November 1972.
 
Regulatory Guide 1.33, Appendix A, requires Administrative Procedures for Equipment Control. The licensee's procedures for temporary changes are contained in EGR-NGGC-0005, Engineering Change, Rev. 25. Contrary to EGR-NGGC-0005, a temporary change was made to the Unit 2 RCIC keepfill system on June 26, 2006,without using the instructions of the procedure. As a result, appropriate reviews of the impact on RCIC system operability were not performed. This resulted in the Unit 2RCIC system being rendered inoperable due to the temporary change. Because thisfinding is of very low safety significance and has been entered into the corrective action program (CAP) as AR 198380, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000324/2006003-01, Failure toFollow Engineering Change Procedure Resulting in Inoperable Reactor Core Isolation Cooling System.
 
===.2 Complete System Walkdown===
 
====a. Inspection Scope====
The inspectors performed a complete walkdown of the accessible portions of the Unit 1and 2 service water chlorination and control room emergency ventilation (CREV) systemchlorine detection system. The inspectors focused on verifying adequate materialcondition and correct system alignment. The inspectors reviewed the TS, operatingprocedures, and the UFSAR. The inspectors held discussions with the service water and CREV system engineers to review system status including a review of open systemmodifications and temporary modifications. The inspectors reviewed open work requests for the system, operator work-arounds, and open adverse conditions or ARs toensure that the impact on equipment functionality was properly evaluated. The inspectors reviewed the documents listed in the Attachment.
 
7EnclosureEnclosure
 
====b. Findings====
No findings of significance were identified.
{{a|1R05}}
==1R05 Quarterly Fire Protection==
 
====a. Inspection Scope====
Fire Area WalkdownsThe inspectors reviewed ARs and work orders (WOs) associated with the firesuppression system to confirm that their disposition was in accordance with Procedure0AP-033, Fire Protection Program Manual. The inspectors reviewed the status of ongoing surveillance activities to verify that they were current to support the operabilityof the fire protection system. In addition, the inspectors observed the fire suppressionand detection equipment to determine whether any conditions or deficiencies existed which would impair the operability of that equipment. The inspectors toured thefollowing eight areas important to reactor safety and reviewed the associated prefire plans to verify that the requirements for fire protection design features, fire area boundaries, and combustible loading were met. Documents reviewed are listed in the
.*Unit 2 Reactor Building East and West, 50' Elevation (2 areas)*Unit 2 North and South Residual Heat Removal Rooms, -17' Elevation (2 areas)
*Diesel Generator Cells 1, 2, 3, and 4, 23' Elevation (4 areas)
 
====b. Findings====
No findings of significance were identified.
{{a|1R06}}
==1R06 Flood Protection==
 
====a. Inspection Scope====
The inspectors performed a walkdown of the Units 1 and 2 service water building toverify that internal flood protection features were consistent with the licensee's internalflooding analysis as described in UFSAR Section 3.4.2, Protection From Internal Flooding. The inspectors reviewed the effects of postulated piping failures for the area to verify that analysis assumptions and conclusions were based on the current plant configuration. The internal flooding design features and equipment for coping with internal flooding were also inspected. The walkdown included sources of flooding and drainage, sump pumps, level switches, watertight doors, curbs, pedestals and equipment mounting. The inspectors reviewed the procedures for coping with internal flooding.
 
8EnclosureEnclosure1R11Quarterly Licensed Operator Requalification
 
====a. Inspection Scope====
The inspectors observed licensed operator performance and reviewed the associatedtraining documents during dynamic simulator examination sessions for training cycle2006-02. The simulator observations and review included evaluations of emergency operating procedure and abnormal operating procedure utilization. The inspectorsreviewed Procedure 0TPP-200, Licensed Operator Continuing Training Program, to verify that the program ensures safe power plant operation. Two simulator examinations (different crews) were observed on May 3, 2006. The scenarios tested the operators' ability to diagnose and respond to various instrumentation failures, abnormaloperating transients, losses of power to various safety-related and nonsafety-related electrical bus' and accidents. The inspectors reviewed operator activities to verify consistent clarity and formality of communication, conservative decision-making by the crew, appropriate use of procedures, and proper alarm response. Group dynamics and supervisory oversight, including the ability to properly identify and implement appropriateTS actions, regulatory reports, and notifications, were observed. The inspectors observed instructor critiques and preliminary grading of the operating crews and assessed whether appropriate feedback was planned to be provided to the licensed operators.
 
====b. Findings====
No findings of significance were identified.
{{a|1R12}}
==1R12 Maintenance Effectiveness==
 
====a. Inspection Scope====
For the two equipment issues described in the ARs listed below, the inspectors reviewedthe licensee's implementation of the Maintenance Rule (10 CFR 50.65) with respect to the characterization of failures, the appropriateness of the associated Maintenance Rulea(1) or a(2) classification, and the appropriateness of the associated a(1) goals and corrective actions. The inspectors also reviewed operations logs and licensee event reports to verify unavailability times of components and systems, if applicable. Licenseeperformance was evaluated against the requirements of Procedure ADM-NGG-0101, Maintenance Rule Program. The inspectors also reviewed deficiencies related to the work activities associated with the ARs to verify that the licensee had identified and resolved deficiencies in accordance with Procedure CAP-NGGC-0200, Corrective Action.*AR 173198, Diesel generator #4 air compressive repetitive functional failure*AR 173069, Diesel generator air compressor #1 in degraded condition 9EnclosureEnclosure
 
====b. Findings====
No findings of significance were identified.
{{a|1R13}}
==1R13 Maintenance Risk Assessments and Emergent Work Evaluation==
 
====a. Inspection Scope====
The inspectors reviewed the licensee's implementation of 10 CFR 50.65 (a)(4)requirements during scheduled and emergent maintenance activities, using Procedure 0AP-025, BNP Integrated Scheduling and Technical Requirements Manual 5.5.13,Configuration Risk Management Program. The inspectors reviewed the effectiveness of risk assessments performed prior to changes in plant configuration for maintenance activities (planned and emergent). The review was conducted to verify that, upon unforseen situations, the licensee had taken the necessary steps to plan and control the resultant emergent work activities. The inspectors reviewed the applicable plant risk profiles, work week schedules, and maintenance WO's for the following seven conditions involving OOS equipment:*AR 190487, Unit 1 risk assessment for transitioning from Mode 4 (ColdShutdown) to Mode 2 (start-up) utilizing provisions of TS 3.0.4.b with aninoperable back-up nitrogen supply to a drywell-to-reactor building vacuum breaker on April 6, 2006 (planned)*AR 195219, Unit 1 isolated phase bus duct cooling damper adjustments tocorrect high B phase temperature on May 20, 2006 (emergent)*AR 194918, Failure of Unit 2 C residual heat removal pump breaker to properlyrack resulting in Yellow plant risk condition on May 18, 2006 (emergent)*AR 194714, Failure of one channel of the Unit 2 main turbine thrust-bearing weardetector on May 16, 2006, resulting in satisfying one-half of the turbine trip logic (emergent)*Work Request (WR) 236201, Unit 1 B circulating water pump tripped on April 15,2006, resulting in a Unit 1 power reduction to approximately 80 percent (emergent)*AR 197918, Unit 2 safety/relief valve C pilot valve leakage identified on June 20,2006 (emergent)*AR 193394, Sodium hypochlorite injection with chlorine detection inoperable(emergent)
 
====b. Findings====
No findings of significance were identified.
 
10EnclosureEnclosure1R14Operator Human Performance
 
====a. Inspection Scope====
The inspectors observed and/or reviewed the following two transients and abnormalplant conditions to assess operator performance during non-routine evolutions and events. Operator logs, plant computer data, and associated operator actions werereviewed as well as the procedures listed in the Attachment.  *AR 195031, Unit 1 high isolated phase bus high temperature due to closed busduct air cooling damper resulting in unplanned downpower on May 18, 2006*AR 195844, Unit 2 entered Abnormal Operating Procedure 0AOP-26, HighReactor Coolant or Condensate Conductivity, on May 29, 2006 due to a main condenser tube leak detected during startup
 
====b. Findings====
No findings of significance were identified.
{{a|1R15}}
==1R15 Operability Evaluations==
 
====a. Inspection Scope====
The inspectors reviewed the operability evaluations associated with the following sixissues documented in the ARs listed below, which affected risk significant systems or components, to assess, as appropriate:  1) the technical adequacy of the evaluations; 2)the justification of continued system operability; 3) any existing degraded conditionsused as compensatory measures; 4) the adequacy of any compensatory measures in place, including their intended use and control; and 5) where continued operability wasconsidered unjustified, the impact on any TS limiting condition for operation and the risk significance. In addition to the reviews, discussions were conducted with the applicable system engineer regarding the ability of the system to perform its intended safetyfunction. *AR 189599, Primary containment isolation system main steam line flow detectorinstrument tubing not properly sloped*AR 194659, Anchor bolt embedment for Unit 1 high pressure coolant injectionsystem support discovered to be less than required minimum*AR 193506, Unit 2 service water vital header discharge flange discovered withexcessive corrosion during ultrasonic test examinations*AR 197630 Unit 2 containment atmosphere pumps (2-CAC-1260 and 1262)exhibiting excessive leakage*AR 197367, Periodic venting of Unit 2 drywell not necessary following RFOB217M1 *WR 240719, EDG #3 manual voltage regulator response during testing was slowduring testing 11EnclosureEnclosure
 
====b. Findings====
No findings of significance were identified.
{{a|1R17}}
==1R17 Permanent Plant Modification==
 
===.1 Annual Review===
 
====a. Inspection Scope====
The inspectors reviewed two permanent plant modifications documented in the belowlisted documents. The inspectors reviewed the design adequacy of the modification for material compatibility which included functional properties, environmental qualification,and seismic evaluation. The review verified that the modification was consistent with theplant's design bases and the design assumptions. Where applicable, the review verified that modification preparation, staging, and implementation did not impairemergency/abnormal operating procedure actions and key safety functions.
 
Post-modification testing was reviewed to confirm that operability would be established,unintended system interactions would not occur, and the testing demonstrated thatmodification acceptance criteria were met. Documents reviewed are listed in the
. The following modifications were reviewed:*Special Procedure 0SP-99-002, Sodium Hypochlorite Injection to CirculatingWater System*Engineering Change (EC) 63657, Repair of Unit 1 Reactor Pressure VesselInternal Core Spray Piping
 
====b. Findings====
No findings of significance were identified.
 
====b. Findings====
No findings of significance were identified.
 
===.2 Biennial Review===
 
====a. Inspection Scope====
The inspectors evaluated design change packages for 14 modifications, in the InitiatingEvents, Mitigating Systems, and Barrier Integrity Cornerstone areas, to evaluate the modifications for adverse effects on system availability, reliability, and functionalcapability. The modifications and the associated attributes reviewed are as follows:
12EnclosureEnclosureAttributes Reviewed by Inspectors-ModificationNumber
-Description
-Cornerstone AffectedMaterials/Replacement Components EnergyNeedsField Observati onSeismicqualificationEnvironmentalqualificationPost-Installa tion testingUpdate of licensee documentsFunctionaltesting adequacy and resultsVendormanuals50053, Iso-Phase BusDuct Cooling (Mitigating Systems)X    XXX      X50516, Unit 1 SLCBoron Concentration Change for EPUR, Revision 5. (Mitigating Systems)XXXX60481, EvaluateManually Filling the 4-Day Fuel Oil Tanks (Mitigating Systems)X    X  X59781, Replace Unit 1RHR Pump Seal Cooler Discharge Line Flow Orifices (Mitigating Systems)XXXXX50098, Unit 1 RRPRunback Setpoint Change and DSS-CD Hardware Installation (Mitigating Systems)XXXXXXXX 13EnclosureEnclosure46681, SFR EliminateSingle Scram Point Switch 2-MS-CS-347 (Initiating Events)XX            X55876, ExtendQualified Lives of Rosemount Pressure Transmitter in EQ Program (Initiating Events)        X    X    X59467, DieselGenerator Output Breaker Logic Change (Mitigating Systems)X    X      X50294, DrywellSnubber Reduction (Initiating Event and Mitigating Systems)50294, DrywellSnubber Reduction (Initiating Event and Mitigating Systems)XX55991, PenetrationSleeve 1-X-2 and Vent Line 1-X-201 H Repairs (Containment Barriers)X        XX55909, Service Level1 Coating Inside Primary Containment (Initiating Events)XX 14EnclosureEnclosure60030, Replacementof RCIC Lube Oil Valves (Mitigating Systems)XXX61290, 1, and 4 EGDAir Control Check Valves (Mitigating Systems)XXXXXX55447, Drywell Insulation Replacement (Initiating Events)X      X 15EnclosureEnclosureFor selected modification packages, the inspectors observed the as-built configuration.Documents reviewed included procedures, engineering calculations, modification design and implementation packages, work orders, site drawings, corrective action documents, applicable sections of the living UFSAR, supporting analyses, TS, and design basis information.The inspectors also reviewed selected ARs associated with modifications to confirm thatproblems were identified at an appropriate threshold, were entered into the corrective action process, and appropriate corrective actions had been initiated.
 
====b. Findings====
No findings of significance were identified.
{{a|1R19}}
==1R19 Post-Maintenance Testing==
 
====a. Inspection Scope====
For the six maintenance activities listed below, the inspectors reviewed the post-maintenance test procedure and witnessed the testing and/or reviewed test records to confirm that the scope of testing adequately verified that the work performed wascorrectly completed, and that the test demonstrated that the affected equipment wascapable of performing its intended function and was operable in accordance with TS requirements. The inspectors reviewed the licensee's actions against the requirements in Procedure 0PLP-20, Post Maintenance Testing Program.  *WO 849455, Unit 2 D residual heat removal service water pump motor bearinghigh temperature repairs*WO 633209, Replace Unit 1 feedwater flow venturi
*WO 866974, Troubleshoot and repair emergency diesel generator (EDG) #1reactive power oscillation observed during monthly testing*WO 870266 Unit 2 containment atmosphere control sample pump (2-CAC-1262)excessive leakage*WO 799350, Replace EDG #2 air receiver manway gasket
*WO 849455, Replace Unit 2 D residual heat removal service water pumprotating element
 
====b. Findings====
No findings of significance were identified.
 
16EnclosureEnclosure1R20Refueling and Other Outage Activities
 
====a. Inspection Scope====
===.1 Unit 1 Refueling OutageThe inspectors evaluated Unit 1 RFO B117R1 activities which commenced on March 3,2006.===
At the start of the inspection, fuel movement was complete and the unit was in Mode 5 (Refueling) and preparing for startup activities after experiencing outage schedule delays due to the necessity to repair an in-vessel core spray line weld flaw.
 
Documents reviewed are listed in the Attachment. The following specific areas were reviewed during the inspection period:Licensee Control of Outage Activities. The inspectors reviewed configuration changesdue to emergent work and unexpected conditions were controlled in accordance with the outage risk control plan. The inspectors reviewed the following specific items, as specified:*Decay Heat Removal and Reactor Coolant System Instrumentation. Theinspectors reviewed decay heat removal procedures and observed decay heat removal systems' parameters to verify proper removal of decay heat. Theinspectors also conducted main control room panel walkdowns and walked down portions of the systems in the plant to verify system availability and to confirmthat no work was ongoing that might prevent system use for decay heat removal. *Reactivity Control. The inspectors observed licensee performance to verify thatreactivity control was conducted in accordance with procedures and TS requirements. The inspectors conducted a review of outage activities and risk profiles to verify activities that could cause reactivity control problems were identified.
 
Monitoring of Heatup and Startup Activities. The inspectors reviewed to verify, on asampling basis, that TS, license conditions, and other requirements for mode changes were met prior to changing modes or plant configurations. The inspectors performed a walkdown of containment to verify that debris, which could affect performance of the emergency core cooling suction strainers, had been appropriately removed. Identification and Resolution of Problems. To assess the licensee's ability to identifyand resolve problems, the inspector reviewed AR 190075 which documented body-to-bonnet leakage on several valves located in the drywell during hydrostatic testing.
 
===.2 Unit 2 Maintenance/Refueling OutageThe inspectors evaluated Unit 2 maintenance/refueling outage B217M1 activities whichcommenced on May 19.===
The planned outage was performed in order to address 17EnclosureEnclosuredetected leaking fuel assemblies. Unit 2 entered Mode 1 (Power Operation) on May 30to complete the outage. The following specific areas were reviewed:Outage Plan. The inspectors reviewed Brunswick Nuclear Plant Unit 2 Outage RiskAssessment for Maintenance Outage B217M1. The inspectors reviewed the outageplan to verify that the licensee had considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. Shutdown and Cooldown. The inspectors observed portions of the Unit 2 shutdown toenter the outage to verify that activities were in accordance with General Procedure 0GP-5.0, Unit Shutdown. The inspectors verified that the licensee monitored cooldownrestrictions by performing 2PT-01.7, Heatup/Cooldown Monitoring, to assure that TScooldown restrictions were satisfied.Licensee Control of Outage Activities. The inspectors observed and reviewed activities and plant conditions to verify that the licensee maintained defense-in-depth commensurate with the outage risk control plan. The inspectors reviewed the followingspecific items, as specified:*Decay Heat Removal. The inspectors reviewed decay heat removal proceduresand observed decay heat removal systems' parameters to verify proper removalof decay heat. The inspectors conducted main control room panel walkdowns and walked down portions of the systems in the plant to verify system availability.*Reactivity Control. The inspectors observed licensee performance during theoutage to verify that reactivity control was conducted in accordance with procedures and TS requirements. *Inventory Control. The inspectors observed operator monitoring and control ofreactor coolant temperature and level and monitored outage work and configuration control for activities that had the potential to drain the reactorvessel. This was performed to verify that the activities were performed in accordance with the outage risk plan.*Electrical Power. The inspectors reviewed the following licensee activitiesrelated to electrical power during the refueling outage to verify that they were in accordance with the outage risk plan:* Controls over electrical power systems and components to ensureemergency power was available as specified in the outage risk report* Controls and monitoring of electrical power systems and components andwork activities in the power transmission yard 18EnclosureEnclosureRefueling Activities. The inspectors reviewed refueling activities to verify fuel handlingoperations were performed in accordance with TS and fuel handling procedures and that controls were in place to track fuel movement. The inspectors reviewed refueling floor and plant controls to verify that the foreign material exclusion controls were established. Monitoring of Heatup and Startup Activities. The inspectors reviewed to verify, on asampling basis, that TS, license conditions, and other requirements for mode changes were met prior to changing modes or plant configurations. Identification and Resolution of Problems. The inspectors reviewed ARs to verify thatthe licensee was identifying problems related to outage activities at an appropriate threshold and entering them in the corrective action program. The inspectors reviewed the following issues identified during the outage to verify that the appropriate correctiveactions were implemented or planned:*AR 195275, Steam separator re-assembly guide tube fell into vessel annulus *AR 195875, Condenser waterbox leak during startup*AR 196018, High radiation levels in -17' north residual heat removal room
*AR 195806, Reactor building overhead crane power failure
*AR 195840, Unable to complete source range-to-intermediate range nuclearinstrument overlap during start-up*AR 195811, Debris found during drywell closeout
*AR 195263, Foreign material observed during fuel movement1R22Surveillance Testing
 
===.1 Routine Surveillance Testing===
 
====a. Inspection Scope====
The inspectors either observed surveillance tests or reviewed test data for the three risksignificant SSC surveillances listed below, to verify the tests met TS surveillance requirements, UFSAR commitments, in-service testing (IST), and licensee procedural requirements. The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs were operationally capable of performing their intended safety functions.  *0PT-80.1, Reactor Pressure Vessel ASME Section XI Pressure Test, performedon Unit 1 on April 4, 2006*0PT-2.3.2, Reactor Building to Suppression Chamber Vacuum Breaker andValve Operability Test, performed on Unit 1 on May 20, 2006*0PT-12.2.A, No. 1 Diesel Generator Monthly Load Test, performed on EDG #1on June 5, 2006To assess the licensee's ability to identify and correct problems, the inspectors reviewedthe following ARs:
19EnclosureEnclosure*AR 197565, Low intake canal level during low lunar tide results in failure to meetTS requirements for ultimate heat sink*AR 197831, EDG #3 manual voltage adjustment was slow during monthly loadtest*AR 189439, Unit 1 RCIC outboard steam supply isolation valve stroked slowduring surveillance testing
 
====b. Findings====
No findings of significance were identified..2Inservice Surveillance Testing
 
====a. Inspection Scope====
The inspectors reviewed the performance of Periodic Test 0PT-8.2.2B, Low PressureResidual Heat Removal System Operability Test, performed on Unit 2, April 24, 2006. The inspectors evaluated the effectiveness of the licensee's American Society of Mechanical Engineers (ASME) Section XI testing program to determine equipment availability and reliability. The inspectors evaluated selected portions of the followingareas: 1) testing procedures; 2) acceptance criteria; 3) testing methods; 4) compliance with the licensee's IST program, TS, selected licensee commitments, and code requirements; 5) range and accuracy of test instruments; and 6) required corrective actions. The inspectors also assessed any applicable corrective actions taken.
 
====b. Findings====
No findings of significance were identified.
 
===Cornerstone:===
Emergency Preparedness1EP6Drill Evaluation
 
====a. Inspection Scope====
The inspectors observed a site emergency preparedness training drill/simulator scenarioconducted on June 8, 2006. The inspectors reviewed the drill scenario narrative toidentify the timing and location of classifications, notifications, and protective action recommendations development activities. The inspectors evaluated the drill conductfrom the control room simulator, technical support center, and the emergency operations facility. During the drill, the inspectors assessed the adequacy of eventclassification and notification activities. The inspectors observed portions of the licensee's post-drill critiques at the technical support center and emergency operatingfacility.
 
20EnclosureEnclosureThe inspectors verified that the licensee properly evaluated the drill's performance withrespect to performance indicators and assessed drill performance with respect to drillobjectives. To assess the ability of the licensee to identify and correct problems, theinspectors reviewed the following corrective action documents that were generated as a result of the drill:*AR 197676, Emergency operating facility knowledge weaknesses*AR 196944, Slow activation of operations support center
*AR 196943, Technical support center/operations support center mission controland coordination problems
 
====b. Findings====
No findings of significance were identified.4.OTHER ACTIVITIES
{{a|4OA1}}
==4OA1 Performance Indicator Verification==
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the Units 1 and 2 performance indicators(PIs) listed below for the periods indicated. To verify the accuracy of the PI datareported during that period, PI definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline",
Revision 4, were used to confirm the reporting basis for each data element.Reactor Safety Cornerstone*Unplanned Power Changes per 7,000 Critical Hours for the period April 2004through March 2006*Safety System Functional Failures for the period July 2004 through March 2006A sample of plant records and data was reviewed and compared to the reported data toverify the accuracy of the PIs. The licensee's corrective action program records were also reviewed to determine if any problems with the collection of PI data had occurred.
 
====b. Findings====
No findings of significance were identified.
 
21EnclosureEnclosure4OA2Identification and Resolution of Problems.1Routine Review of ARsTo aid in the identification of repetitive equipment failures or specific humanperformance issues for followup, the inspectors performed frequent screenings of items entered into the licensee's CAP. The review was accomplished by reviewing daily ARs..2Annual Sample Review
 
====a. Inspection Scope====
The inspectors performed an in-depth annual sample review of AR 196168 whichdocumented that Unit 2 power ascension was delayed following RFO B217M1 due to steam jet air ejector hi radiation alarms. The purpose of the review was to verify that conditions adverse to quality were addressed in a manner that was commensurate with the safety significance of the issue. The inspectors reviewed the actions taken to verify that the licensee had adequately addressed the following attributes:*Complete, accurate, and timely identification of the problem *Evaluation and disposition of operability and reportability issues*Consideration of previous failures, extent of condition, generic or common causeimplications*Prioritization and resolution of the issue commensurate with the safetysignificance*Identification of the root cause and contributing causes of the problem*Identification and implementation of corrective actions commensurate with thesafety significance of the issue
 
====b. Findings and Observations====
 
=====Introduction.=====
Two unresolved items (URIs) were identified regarding the failure to follow an operatingprocedure and the potential reduction in the effectiveness of the licensee's emergency plan due to the introduction of air into the condenser off-gas flowpath.Description.Following Unit 2 midcycle outage RFO B217M1, completed on May 30, 2006, the maincondenser offgas system experienced increased radiation levels during powerascension. The cause of the increased offgas radiaton levels was due to previous operation with leaking fuel assemblies. Radiation levels are measured by steam jet air ejector (SJAE) radiation monitors 2-D12-RM-K601A&B, located at the outlet of the SJAEafter-condensers. Radiation levels are a function of the concentration of radio-isotopes present in the sample chamber. The level of readings depend on many factors including reactor coolant system activity, the amount of hydrogen being injected into the reactor 22EnclosureEnclosurecoolant system, reactor power level, and the concentration of nonradioactive gases(e.g., oxygen and nitrogen). A high alarm on the radiation monitors requires investigation and entry into Emergency Operating Procedure (EOP) 0EOP-04-RRCP,Radioactivity Release Control Procedure. Additionally, emergency action levels (EALs)for both an Unusual Event and an Alert are based on readings from the SJAE (i.e.,
>12,000mr/hr for an Unusual Event and 120,000mr/hr for an Alert) and are used to address abnormal core conditions and core damage.On two occasions on May 31, 2006, while Unit 2 was performing power ascension, highalarms were received on the radiation monitors. On both occasions operators entered EOP 0EOP-04-RRCP as required. Following confirmation of no fuel cladding failure,operators cleared the alarm; once by placing both SJAE in half-load and once by raising the alarm setpoints in accordance with plant procedures. On June 1, 2006, power ascension was secured based on SJAE radiation monitor levelsincreasing with reactor power increases. Operators projected that the high alarmsetpoint would again be reached prior to attaining full power. A focus team was formed to address the issue. At the recommendation of the focus team, operators utilizedSection 8.9 of Operating Procedure (OP) 2OP-30, Condenser Air Removal and Off-gas Recombiner System, to inject service air into the SJAEs, so that the increased flow past the radiation monitors would dilute the concentration of activity and reduce the number of "false-fuel-failure" alarms. However, the inspectors found that an initial condition of OP 2OP-30, that service air injection to the SJAEs was needed for continued hydrogen water chemistry, was not met in this case. Sufficient condenser air in-leakage was present to provide enough oxygen for hydrogen recombination. The inspectors determined that as a result of this procedure adherence deficiency, in addition to reducing the number of "false-fuel-failure" alarms, the licensee had reduced the ability tomonitor for actual fuel cladding damage. The licensee subsequently raised the setpoint of the radiation monitors, secured air injection to the SJAEs, and entered this failure to follow procedure into the CAP as AR 196365. The inspectors reviewed the procedure history of OP 2OP-30. The inspectors foundthat the first procedural allowance of using valved-in air to the offgas flowpath during plant operation was in 1997, with the creation of Special Procedure (SP) 0SP-97-004, Service Air Injection to SJAEs. The purpose of the air was for providing sufficient oxygen in the offgas flowpath for recombining with hydrogen, in the hydrogen recombiners, in the case when condenser air in-leakage was insufficient. The introduction of air into the offgas flowpath also has the affect of reducing SJAE radiation monitor readings. This change appears to have potentially reduced the effectiveness of the site Emergency Plan because EAL classifications for both an Unusual Event and an Alert are based on radiation level readings from the SJAE radiation monitor. However, the safety screen for SP 0SP-97-004 stated that the change to inject service air to the offgas flowpath did not involve a change to the previously accepted Emergency Plan.
 
Procedural steps to inject service air were later incorporated into OP 2OP-30, the corresponding Unit 1 procedure OP 1OP-30, and SP 0SP-97-004 was cancelled. The licensee entered the failure to address the procedure change effects on the Emergency Plan into the CAP as AR 196254.
 
23EnclosureEnclosureEnforcement. The two issues discussed above are unresolved pending additional NRC review. URI05000325,324/2006003-02, Potential Reduction in Effectiveness of Emergency Plan, isunresolved pending an NRC review of the potential reduction of the effectiveness of thelicensee's Emergency Plan due to the introduction of air in the offgas flowpath. URI 05000325/2006003-03, Failure to Follow Condenser Air Removal and Off-gas Recombiner System Procedure, is unresolved pending a further NRC procedural review,subsequent to the resolution of URI 05000325,324/2006003-02.
 
===.3 Semi-Annual Trend Review===
 
====a. Inspection Scope====
The inspectors performed a review of the licensee's CAP and associated documents toidentify trends that could indicate the existence of a more significant safety issue. The review was focused on repetitive equipment issues but also considered the results of frequent inspector CAP item screening (discussed above), licensee trending efforts, and licensee human performance results. The review considered the period of January through June 2006. The review further included issues documented outside the normal CAP in major equipment lists, repetitive and/or rework maintenance lists, operational focus list, control room deficiency list, outstanding work order list, quality assurance audit/surveillance reports, key performance indicators, and self-assessment reports. The inspectors compared and contrasted their results with the results contained in the Brunswick Plant CAP Rollup and Trend Analysis report for the 1st quarter 2006. Corrective actions associated with a sample of the issues identified in the licensee's trend reports were reviewed for adequacy. The inspectors also evaluated the reports against the requirements of the licensee's CAP as specified in Nuclear Generation Group Standard Procedure CAP-NGGC-0200, Corrective Action Program, and 10 CFR 50, Appendix B.
 
b.Assessment and ObservationsNo findings were identified. During the current review period, the inspector notedseveral inspector-identified, self-revealing, and licensee-identified issues involving inadequacies in procedure compliance. Section 1R04 and
{{a|4OA2}}
==4OA2 of this report==
 
document two inspector-identified issues involving procedure noncompliance. NRC Inspection Report 05000324,325/2006005, dated April 30, 2006, documented a self-revealing NCV due to a failure to follow a procedure which resulted in a plant transient.
 
Other less significant (i.e., minor) instances of procedure noncompliances were noted including:  1) an inspector-identified issue involving the adjustment of the Unit 1 isophase bus duct cooling dampers with no written procedure contrary to the plant equipment control procedure; 2) a self-revealing issue involving the failure to follow an instrumentation loop maintenance procedure resulting in a main turbine/feedwater turbine half-trip condition; 3) an inspector-identified issue involving the failure to properly prioritize a CREV and control room air compressor maintenance rule functional failure in accordance with CAP-NGGC-0200, Corrective Action; and 4) several 24EnclosureEnclosureinspector-identified instances where the formal operability determination process wasnot entered for equipment conditions as required by OPS-NGGC-1305, OperabilityDeterminations (also observed by the licensee's nuclear assurance organization).
 
Based on the inspectors' review, the inspectors concluded that procedure usage and compliance was an area of challenge for the licensee. As a result of the inspectors' conclusion, the licensee entered the issue into the CAP as AR 200605.4OA3Event Follow-up
 
===.1 (Closed) Licensee Event Report (LER) 050003252006002: Cracking Found in B LoopCore Spray Header Piping.===
During in-vessel visual inspections of core spray piping, the licensee identified cracking on a core spray system header piping weld. Ultrasonic testexaminations demonstrated that the as-found condition of the weld was unacceptablefor operation without repair. The licensee completed permanent repairs to the piping weld. This event was discussed in NRC Inspection Report 05000325/2006002, datedApril 30, 2006, and resulted in a Green NRC-identified TS NCV. No new issues wereidentified by the LER. This LER is closed.
 
===.2 (Closed) LER 05000325,324/2006001: Control Room Emergency Ventilation (CREV)and Air Conditioning (AC) Inoperable Due to Loss of Control Air.===
On January 12, 2006, with the Unit 2 A control building instrument air compressor out-of-service, the Unit 2 B air compressor failed to maintain pressure. This resulted in the CREV and AC systemsshutting down resulting in a loss of function. The licensee returned the A air compressor to service to restore the CREV and AC systems to an operable status. The inspectors reviewed the LER and associated corrective action documents. TheLER stated that the cause was due to ineffective condition monitoring of the compressor oil pressure to detect hydraulic unloader degradation. However, subsequent failure analysis of the compressor revealed that the low oil pressure was due to excessive wear of the cylinder head wrist pins. The inspector concluded that the licensee's original corrective actions were adequate because no additional actions were identified due to the new information. Additionally, the inspectors noted that the A air compressor experienced a similar failure on December 16, 2005. The inspectors concluded that an opportunity to detect and repair the B air compressor prior to failure, based on the A air compressor failure, was not reasonable based on the short time frame (i.e., less than one month) between the failures. This LER is closed.4.OTHER ACTIVITIES 4OA6MeetingsOn July 18, 2006, the resident inspectors presented the inspection results toMr. J. Scarola and other members of his staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection.ATTACHMENT: 
 
=SUPPLEMENTAL INFORMATION=
 
==KEY POINTS OF CONTACT==
 
===Licensee Personnel===
: [[contact::G. Atkinson]], Supervisor - Emergency Preparedness
: [[contact::L. Beller]], Supervisor - Licensing/Regulatory Programs
: [[contact::A. Brittain]], Manager - Security
: [[contact::T. Cleary]], Director - Site Operations
: [[contact::E. O'Neil]], Manager -  Training Manager
: [[contact::M. Grantham]], Manager (Acting) - Engineering
: [[contact::D. Griffith]], Manager - Outage and Scheduling
: [[contact::L. Grzeck]], Lead Engineer - Technical Support
: [[contact::S. Howard]], Manager - Maintenance
: [[contact::R. Ivey]], Manager - Site Support Services
: [[contact::A. Pope]], Manager - Operations
: [[contact::S. Rogers]], Manager Nuclear Assessment
: [[contact::J. Scarola]], Site Vice President
: [[contact::M. Turkal]], Lead Engineer - Technical Support
: [[contact::M. Williams]], Manager - Operations Support
: [[contact::B. Waldrep]], Plant General Manager
===NRC Personnel===
: [[contact::P. Fredrickson]], Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II
A-2Attachment
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
Opened05000325,324/2006003-02URIPotential Reduction in Effectiveness of EmergencyPlan (Section 4OA2.2)05000325/2006003-03URIFailure to Follow Condenser Air Removal andOff-gas Recombiner System Procedure (Section
4OA2.2)
===Opened and Closed===
05000324/2006003-01NCVFailure to Follow Engineering Change ProcedureResulting in Inoperable Reactor Core Isolation
Cooling System (Section 1R04)
===Closed===
: [[Closes LER::05000325/LER-2006-002]]LERCracking Found in B Loop Core Spray HeaderPiping (Section 4OA3.1)
: 05000325,324/2006001LERControl Room Emergency Ventilation (CREV) andAir Conditioning (AC) Inoperable due to Loss of
: Control Air (Section 4OA3.2)  DiscussedNone
: A-3Attachment
==LIST OF DOCUMENTS REVIEWED==
==Section 1R01: Adverse Weather ProtectionPlant Operating Manual (POM), Volume==
: XIII, Plant Emergency Procedure 0PEP-02.1, Initial
: Emergency Actions, Rev. 50
: POM, Volume XIII, Plant Emergency Procedure 0PEP-02.6, Severe Weather, Rev. 9POM, Volume I, Administrative Instruction, 0AI-68, Brunswick Nuclear Plant Response to Severe Weather Warnings, Rev. 25
: POM, Volume XXI, Abnormal Operating Procedure, 0AOP-13.0, Operation during Hurricane,
: Flood Conditions, Tornado, or Earthquake, Rev. 36
 
==Section 1R02: Evaluation of Changes, Tests, or ExperimentsFull Evaluations (licensing identification #)02-1791,==
: EHC Pressure Regulator Out-of-Service05-0665 and 05-0627, Turbine Building Once Through Ventilation
: 04-1042, [04-019 Temporary Change],
: AI-117 Filter SLC Tank
: 05-0424,
: EC 60736 Condenser Vacuum Pressure Switches
: 04-0748, Freeze Seal on 1-RCC-74-1-1/2-15404-0956, 2-CAC-X18D Use of Procedure 2SP-04-005
: 05-0153, Extend Life of Chlorine DetectorsScreened Out Items (EC = modifications):51357, electrical - RIP Module Change-out 50053, electrical - EPUR (Extended Power Uprate) Iso-Phase Bus Cooling
: 294 civil - Snubber Reduction
: 59781, mechanical - Replace Unit 1 RHR Pump Seal Cooler Discharge Line Flow Orifices55447, civil - Drywell Insulation
: 50516, chemistry - SLC Concentration Change for EPUR
: 55876, electrical - Rosemount Transmitter EQ Qualification Extended
: 55909, civil - Torus Coatings
: 55991, civil - Penetration Sleeve 1-X-2 & Vent Line 1-X-20H Repairs
: 59819,  mechanical -
: RHR Seal Cooler Orifice Changed60051 and 59437, mechanical  - EDG Starting Air Requirements
: 60030, civil - 1/2-E51-RV96/97 Replacement and Notching of RCIC Pipe Supports on Skid
: 46681, electrical - Eliminate Single Scram Point Switch 2-MS-CS-347
: 290, 61291 and 61294 mechanical - EDG Air Control Check Valves
: 60481, mechanical - Evaluation of Manual Fill of EDG 4 Day Tank51180, 55504 mechanical/civil - EPUR Mod of Steam Dryer
: 59467, electrical - DG Output Breaker Logic Change 
: 57859, mechanical - EDG Air Check Valve Replacement           
: A-4AttachmentCorrective Action Documents (ARs)00131519, SLC Pump Inoperability00133346, CAC X18D Failed Open
: 00190317, Incorrect Wire Label Used During
: DG-1 Wiring ChangeWork Orders562428, Freeze Seal 1-RCC-74-1/2-154823648, 1-EHC-XY-644-A69, Pressure Regulaton
: 333171 05, EC 50052
: 179877 01, 2-RIP-
: CS-1218ProceduresOSPP-MECH502, Freeze Seals 1/2" to 4" Piping, Rev. 170OI-01.08, Control of Equipment and System Status, Rev. 15REG-NGGC-0010, 10
: CFR 50.59 and Selected Regulatory Reviews, Rev. 8
: 1SP-03-001, Unit Extended Power Uprate Startup Test Plan, Rev. 2 (completed data set on iso-phase bus duct coolers)Miscellaneous Documents:SER "Brunswick Steam Electric Plant, Units 1 and 2 - Issuance of Amendments Re: StandbyLiquid Control Sodium Pentaborate Solution Concentration and Requirements" (TAC Nos.
: MB5680 and MB5681), March 25, 2003.
: BSEP 03-0035, Response to NRC Request for Additional InformationOBNP-TR-001, "BNP Inservice Inspection Technical Report", Rev. 7
: Calculation 0DSA-0005, Diesel Generator Starting Air Requirements, Rev. 0
: SER
: November 1973, Section 9.5.4 Diesel Generator Staring Air System
: UFSAR Section 8.3.1, Diesel Generator Staring Air System Design Basis Document-39, Emergency Diesel Generator System Letter from J. S. Keenan (CP&L) to the U.S.N.R.C., "Brunswick Steam Electric Plant, Unit Nos.
and 2; Docket Nos. 50-325 and 50-324/License Nos.
: DPR-71 and
: DPR-62; Request for License Amendments Core Flow Operating Range Expansion," November 12, 2002.Drawings:D-02547, Unit No. 2 Reactor Building Standby Liquid Control System Piping Diagram, Rev. 271-FP-05851, Power Range Neutron Monitoring System RPS Outputs, Rev. BSelf-Assessment DocumentsAR
: 122287, Lack of Control of 50.59 Screens Associated with ECsAR
: 123992,
: OI-29 Clearance Audit Revision
: AR 135204, Failure to Obtain Manager Approvial for 50.59 Work Order
: AR 136063, Inadequate Activity Description in a 50.59 Screen
: A-5AttachmentAR 59451, Incorporate UFSAR Requirements into Plant Procedures
 
==Section 1R04: Equipment AlignmentUFSAR Section 9.2.1Operating Procedure (OP), 1OP-43.1, Chlorination System Operating ProcedurePOM, Volume==
: XXI, Abnormal Operating Procedure 0AOP-34.0, Chlorination Emergency Technical Requirements Manual, Section 3.5, Chloride Intrusion Monitoring
 
==Section 1R05: Fire ProtectionPOM, Volume==
: XIX, Prefire Plan, 1PFP-RB, Reactor Building Prefire Plans, Rev. 6POM Volume XIX, Prefire Plann 0PFP-DG, Diesel Generator Building Prefire Plans, Rev. 8
 
==Section 1R17: Permanent Plant ModificationsSelf-Assessment DocumentsAR
: 116248, Mod Sketches not Rolled into DrawingAR
: 117578, Human Performance Errors Precursors==
: AR 118616, Draft Procedures not Available for Outage Mod Training
: AR 121014,
: EC 50094 Implementation ErrorProceduresSpecial Procedure (SP) 0SP-01-002, Rev. 0 Sodium Hypochlorite injection to the Service WaterSystem
: POM 0SMP-CWI500 Sodium Hypochlorite injection to circulating water system.EGR-NGGC-005, Engineering Change, Rev. 24
: 1OP-05, Standby Liquid Control System, Rev. 45
: 2OP-05, Standby Liquid Control System, Rev. 57
: 0PT-20.14, Testing of SLC Injection Check Valves, Rev. 2
: 0PT-80.1, Reactor Pressure Vessel ASME Section XI Pressure Test, Rev. 52Corrective Action DocumentsAR
: 190346, EDG Start Air SystemAR
: 190317, Incorrect Wire Label on EDG Wiring Change
: AR 190267, UFSAR Change Performed without Proper Evaluation Engineering Calculation 8K49-M-O1Rev0
 
==Section 1R20: Refueling and Other Outage ActivitiesPOM, Volume==
: IV, Operating Procedure, 0GP-02, Approach to Criticality and Pressurization of    the Reactor, Rev. 81
: POM, Volume IV, Operating Procedure, 0GP-01, Prestartup Checklist, Rev. 168
}}

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