IR 05000263/2007003
Download: ML072010242
Text
July 18, 2007
Mr. Timothy J. O'ConnorSite Vice President Monticello Nuclear Generating Plant Nuclear Management Company, LLC 2807 West County Road 75 Monticello, MN 55362-9637
SUBJECT: MONTICELLO NUCLEAR GENERATING PLANTNRC INTEGRATED INSPECTION REPORT 05000263/2007003
Dear Mr. O'Connor:
On June 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspectionat your Monticello Nuclear Generating Plant. The enclosed integrated inspection report documents the inspection findings which were discussed on July 5, 2007, with Mr. Grubb 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.Based on the results of this inspection, there was one NRC-identified finding of very low safetysignificance involving a violation of NRC requirements. However, because this violation was of very low safety significance and because the issue was entered into the licensee's corrective action program, the NRC is treating this finding as a non-cited violation in accordance with Section VI.A.1 of the NRC's Enforcement Policy. Additionally, one licensee-identified violation is listed in Section 4OA7 of this report.If you contest the subject or severity of a 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 Monticello Nuclear Generating Station.
T. O'Connor-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letterand its enclosure will be available electronically for public inspection in the NRC PublicDocument Room 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 by Nirod Shah for/Kenneth Riemer, ChiefBranch 2 Division of Reactor ProjectsDocket No. 50-263License No. DPR-22
Enclosure:
Inspection Report 05000263/2007003
w/Attachment:
Supplemental Informationcc w/encl:M. Sellman, President and Chief Executive OfficerD. Cooper, Senior Vice President and Chief Nuclear Officer Manager, Nuclear Safety Assessment J. Rogoff, Vice President, Counsel, and Secretary Nuclear Asset Manager, Xcel Energy, Inc.
State Liaison Officer, Minnesota Department of Health R. Nelson, President Minnesota Environmental Control Citizens Association (MECCA)
Commissioner, Minnesota Pollution Control Agency D. Gruber, Auditor/Treasurer, Wright County Government Center Commissioner, Minnesota Department of Commerce Manager - Environmental Protection Division Minnesota Attorney General's Office
SUMMARY OF FINDINGS
Inspection Report 05000263/2007003; 04/01/2007 - 06/30/2007; Monticello Nuclear GeneratingPlant. Identification and Resolution of Problems.This report covers a three-month period of baseline resident inspection and announcedbaseline inspections of radiation protection and maintenance effectiveness. The inspections were conducted by regional health physics inspectors, regional reactor engineers and the resident inspectors. The significance of most findings is indicated by their color (Green, White,
Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be "Green" or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.A.NRC-Identified and Self-Revealed Findings
Cornerstone: Mitigating Systems
- Green.
A finding of very low safety significance was identified by the inspectors for aviolation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," associated with the licensee's failure to perform portions of Fleet Procedure FP-PE-SW-01, "Service Water and Fire Protection Inspection Program." Contrary to the requirements of the procedure, the licensee did not increase monitoring or determine degradation mechanisms when emergency service water (ESW) system pipe wall thickness indications were found to meet thresholds that required additional monitoring.
As a result of an apparent cause evaluation and service water focused self-assessment, several corrective actions were developed to correct procedural and equipment deficiencies associated with the ESW and other raw water systems at Monticello. The inspectors determined that the performance deficiency affected the cross-cutting area of Human Performance, having resource components and involving aspects associated with maintaining long-term plant safety by the maintenance of design margins and the minimization of long-standing equipment issues H.2(a).The finding was more than minor because the performance deficiency affected theprocedure quality attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using Inspection Manual Chapter (IMC) 0609, Appendix G, "Phase 1 Screening," and determined that Checklist 8, "Boiling Water Reactor (BWR) Cold Shutdown or Refueling Operation Time to Boil > 2 Hours: Reactor Coolant System (RCS) Level < 23 Feet Above Top of Flange," applied. However; because all qualitative criteria within the Core Heat Removal, Inventory Control, Power Availability, and Containment guidelines were met; because the finding did not meet the Checklist 8 criteria for Phase 2 or Phase 3 quantitative analysis; and because no event occurred that could be characterized as a loss of control as listed in Table 1 of IMC 0609, Appendix G, the finding was considered to be of very low safety significance. (Section 4OA2.4)
Enclosure2
B.Licensee-Identified Violations
Violations of very low safety significance, which was identified by the licensee have beenreviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. These violations and the licensee's corrective action tracking numbers are listed in Section 4OA7 of this report.
Enclosure3
REPORT DETAILS
Summary of Plant StatusMonticello was shutdown for a planned refueling outage at the beginning of the assessmentperiod. The reactor was restarted on April 26, 2007, and the main electrical generator was connected to the grid on April 28, 2007. Full power was reached May 4, 2007. Monticello operated at full power for the remainder of the assessment period except for brief down-power maneuvers to accomplish rod pattern adjustments and to conduct planned surveillance testing activities.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, andEmergency Preparedness1R01Adverse Weather (71111.01)
a. Inspection Scope
The inspectors performed a detailed review of the licensee's procedures and performeda walkdown of areas near large station transformers and substation electrical equipment to observe the licensee's preparations for adverse weather; specifically, adverse conditions that could result from high winds. The inspectors focused on plant specific design features and implementation of the procedures for preparing for the onset of adverse weather. Inspection activities included a review of the licensee's adverse weather procedures and a review of the protocols between the licensee and the transmission service operator to verify that appropriate information would be exchanged if issues arose that could adversely impact the offsite power system. The inspectors also verified that operator actions specified by plant specific procedures to address abnormal offsite power situations were appropriate.The inspectors evaluation of readiness for seasonal susceptibilities (high winds)constituted one inspection sample.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment (71111.04Q)
a. Inspection Scope
The inspectors performed partial walkdowns of accessible portions of trains ofrisk-significant equipment. The inspectors reviewed equipment alignment to identify any discrepancies that could impact the function of the system and potentially increase risk.
The inspectors selected redundant or backup systems for inspection during times when equipment was of increased importance due to unavailability of the redundant train or 4other support related equipment. Inspection activities included a review of the licensee'sprocedures, verification of equipment alignment, and an observation of material condition, including operating parameters of equipment in-service.The inspectors selected the following equipment trains to assess operability and properequipment line-up for a total of four samples:*Division II shutdown cooling during a planned Division I outage period;*high pressure coolant injection (HPCI) system while the reactor core isolationcooling (RCIC) system was out-of-service for planned work;*14 residual heat removal service water (RHRSW) system while the 12 RHRSWsystem was out-of-service for planned work; and*'B' standby gas treatment (SBGT) system while the 'A' SBGT system wasout-of-service for planned work.
b. Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05).1Quarterly Fire Zone Walkdowns (71111.05Q)
a. Inspection Scope
The inspectors walked down risk significant fire areas to assess fire protectionrequirements. The inspectors reviewed areas to determine whether the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and had implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems or features. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's Individual Plant Examination of External Events, or the potential to impact equipment which could initiate or mitigate a plant transient. The inspection activities included the control of transient combustibles and ignition sources, fire detection equipment, manual suppression capabilities, passive suppression capabilities, automatic suppression capabilities, compensatory measures, and barriers to fire propagation.The inspectors selected the following areas for review for a total of eleven samples:
- Fire Zone 1-F, (torus area - elevation 896' and 923');
- Fire Zone 17, (turbine building north cable corridor 941');
- Fire Zone 13C, (turbine building 911' elevation east motor controlcenter (MCC) area);*Fire Zone 8, (cable spreading room);
5*Fire Zone 16, (turbine building east and west corridor, elevations 911' and 931');*Fire Zone 19A, (make-up demineralizer area);
- Fire Zone 19B, (essential MCC area - No. 142 and 143 931' elevation); and
- Fire Zone 23B, (intake structure corridor).
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures (71111.06)
a. Inspection Scope
The inspectors performed an annual review of flood protection barriers and proceduresfor coping with external flooding. The inspection focused on evaluating the licensee's preparations to mitigate the consequences of the maximum probable flood scenario, as described in Appendix G of the Monticello Nuclear Generating Plant (MNGP) Updated Safety Analysis Report (USAR). The inspection activities included a review of the probable maximum flood scenario, historical Mississippi River levels and predicted levels for the 2007 spring flood season, and operations procedures which are implemented to mitigate the effects of rising river level. The inspectors also interviewed the site engineers responsible for predicting and mitigating the consequences of flooding at the Monticello site. Topics of discussion included: tools used to predictmaximum river level, development of flood plans, the availability and use of materials specified to mitigate the impact of the flood, and potential time available to implement mitigating actions for the maximum probable flood scenario.The inspectors' review constituted a total of one external flooding inspection sample.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11)
a. Inspection Scope
The inspectors performed a quarterly review of licensed operator requalification training. The inspectors assessed the licensee's effectiveness in implementing the requalification program; whether licensed individuals could demonstrate operation of the facility safely and within the conditions of their license; and licensed operator performance of high-risk operator actions. The inspectors observed:*crew performance and timeliness during high risk portions of the evolution;*implementation of the emergency plan;
- incorporation of past lessons learned;
- clarity and formality of communications;
- control board conduct, alarm response actions and task prioritization;
- procedural adequacy and implementation; 6*supervisory oversight;*the dynamics of the crew;
- interpretations of Technical Specifications (TSs);
- simulator fidelity; and
- the licensee's critique of performance.The inspectors observed the following requalification activity for a total of one inspectionsample:*a training crew during an evaluated simulator scenario that included: aninadvertent HPCI initiation, a lockout of Bus 15, and a steam leak in the drywell resulting in abnormal and emergency operating procedure entries, primary containment temperature and pressure control, and event classification and notifications.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12).1Routine Evaluation (71111.12Q)
a. Inspection Scope
The inspectors reviewed areas and systems to assess maintenance effectiveness,including maintenance rule activities, work practices, and common cause issues.
Inspection activities included the licensee's categorization of specific issues including evaluation of performance criteria, appropriate work practices, identification of common cause errors, extent of condition, and trending of key parameters. Additionally, the inspectors reviewed implementation of the Maintenance Rule (10 CFR 50.65)requirements, including a review of scoping, goal-setting, performance monitoring, short-term and long-term corrective actions, functional failure determinations associated with reviewed corrective action program (CAP) documents, and current equipment performance status. The inspectors performed the following maintenance effectiveness reviews for a total ofthree samples:a review of reactor water clean-up (RWCU) system maintenance issues andhistorical treatment of component issues under the maintenance rule; a review of emergency service water (ESW) system microbiologically-influencedcorrosion issues; and*a review of licensee monitoring, maintenance, and corrective actions for wetted 4 kV cabling associated with the 11 residual heat removal (RHR) pump, 13 RHR pump, and the 11 core spray (CS) pump.
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b. Findings
No findings of significance were identified..2Periodic Evaluation (71111.12B)
a. Inspection Scope
The inspectors examined the last two Maintenance Rule periodic evaluation reportscompleted for the periods of June 2004 through March 2005, and April 2005 through March 2006. The inspectors reviewed a sample of: (a)(1) Action Plans, Performance Criteria, Functional Failures, and CAP documents to evaluate the effectiveness of (a)(1) and (a)(2) activities. These same documents were reviewed to verify that the threshold for identification of problems was at an appropriate 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 five Maintenance Rule systems (samples):non-essential diesel generator;service water system;structures;emergency diesel generators (EDGs); andHPCI.The inspectors verified that the periodic evaluation was completed within the timerestraints defined in 10 CFR 50.65 (once per refueling cycle, not to exceed 24 months).
The inspectors also ensured that the licensee reviewed its goals, monitored structures, systems, and components (SSCs) 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 action was 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 thatthe licensee had established (a)(2) performance criteria, examined anySSCs that failed to meet their performance criteria, and reviewed any SSCs that have suffered 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.This review represented five triennial inspection samples.
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b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed maintenance activities to review risk assessments (RAs) andemergent work control. The inspectors verified the performance and adequacy of RAs, management of resultant risk, entry into the appropriate licensee-established risk bands, and the effective planning and control of emergent work activities. The inspection activities included a verification that licensee RA procedures were followed and performed appropriately for routine and emergent maintenance, that RAs for the scope of work performed were accurate and complete, that necessary actions were taken to minimize the probability of initiating events, and that activities to ensure that the functionality of mitigating systems and barriers were performed. Additionally, the assessment included an evaluation of external factors, the licensee's control of work activities, and appropriate consideration of baseline and cumulative risk.The inspectors observed maintenance or planning associated with the followingactivities or risk significant systems undergoing scheduled or emergent maintenance for a total of seven samples:*isolation of shutdown cooling to support component testing;*Division II RHR pumps and CS pump failed to start during emergencycore cooling system (ECCS) testing;*cooler flush subsequent to flow testing revealing reduced flow to the12 CS motor cooler;*rod position indication system troubleshooting and position indicating probereplacement for Control Rod 26-35;*13 & 14 ESW piping replacement due to indications of MIC;
- main generator seal oil vacuum pump replacement; and
- loss of control power for MO-2020, Division I RHR drywell spray outboard valve,following preventive maintenance.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors reviewed operability evaluations which affected mitigating systems orbarrier integrity to ensure that operability was properly justified and that the component or system remained available. The inspection activities included a review of the technical adequacy of the operability evaluations to determine the impact on TS, the 9significance of the evaluations to ensure that adequate justifications were documented,and that risk was appropriately assessed.The inspectors reviewed the following operability evaluations for a total of four samples:
- CAP 01081986-03 (internal seal welds in safety relief valves may not meetcodes);*CAP 01088367 (12 CS pump motor cooler reduced cooling flow);
- CAP 01089542 (Is abandoned cable in the drywell accounted for in analysis?);and*CAP 01085173 (12 EDG failed vibration post-maintenance test (PMT)).
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing (71111.19)
a. Inspection Scope
The inspectors verified that the PMT procedures and activities were adequate to ensuresystem operability and functional capability. Activities were selected based upon the SSCs ability to impact risk. The inspection activities included witnessing or reviewing the integration of testing activities, applicability of acceptance criteria, test equipment calibration and control, procedural use and compliance, control of temporary modifications or jumpers required for test performance, documentation of test data, system restoration, and evaluation of test data. Also, the inspectors verified that maintenance and PMT activities adequately ensured that the equipment met the licensing basis, TS, and USAR design requirements. The inspectors selected the following post-maintenance activities for review for a total ofsix samples:*reactor coolant pressure boundary leakage test;*primary containment integrated leak rate test (ILRT), Part B, pressurizationand stabilization;*No. 13 250 Vdc battery cells 37 and 65 following replacement;
- solenoid valve SV-2379 [associated with torus to reactor building vacuumbreaker] following replacement;*12 EDG circulating oil pump following coupling replacement and realignment;and*post-replacement testing of 12 RHRSW pump.
b. Findings
No findings of significance were identified.
101R20Outage Activities (71111.20)
a. Inspection Scope
The inspectors continued evaluation of outage activities for a refueling outage (RFO)that began on March 14, 2007, and ended on April 28, 2007. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule, developed mitigation strategies for loss of key safety functions, and adhered to operating license and TS requirements to ensure defense-in-depth. The inspection activities included a review of the outage plan, monitoring of shutdown and startup activities, control of outage activities and risk, and observation of reduced inventory operations, maintenance and refueling activities.The following represents a partial list of the major outage activities the inspectorsreviewed/observed, all or in part: *review of both outage plans and the ready-backlog;
- control room turnover meetings and selected pre-job briefings;
- refueling activities;
- torus closeout inspection;
- drywell closeout inspection;
- startup and heatup activities, including criticality, feed pump startup, main turbinegenerator startup and synchronization, and elements of power escalation to full power; and*identification and resolution of problems associated with the outage.Inspection activities for this inspection sample began in the first quarter 2007assessment period and were documented in Inspection Report 05000263/2007002.
The inspection activities were concluded in the second quarter 2007. These inspection activities constitute one sample.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed surveillance testing activities to assess operational readinessand to ensure that risk-significant SSCs were capable of performing their intended safety function. Activities were selected based upon risk significance and the potential risk impact from an unidentified deficiency or performance degradation that a SSC could impose on the unit if the condition was left unresolved. The inspection activities included a review for preconditioning, integration of testing activities, applicability of acceptance criteria, test equipment calibration and control, procedural use, control of temporary modifications or jumpers required for test performance, documentation of test data, TS applicability, and evaluation of test data.
11The inspectors selected the following surveillance testing activities for review for a totalof eight samples:*RHR shutdown cooling inboard and outboard supply isolation valve leak test(containment isolation valve);*primary containment integrated primary containment leak rate test, Part C,verification test (routine);*14 ESW quarterly pump and valve tests (inservice test);
- HPCI automatic initiation test (routine);
- alternate shutdown system cycle functional test for 12 EDG and diesel transferpump switches (routine);*containment sump flow measurement instrumentation functional test (reactorcoolant system (RCS) leakage detection);*low pressure ECCS auto initiation test (routine); and
- 13 diesel generator 5-year automatic start/loading test (routine).
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope
The inspectors reviewed a temporary modification associated with an enclosureweldment and sealing of a piping-to-flange weld crack downstream of the 12 moisture separator drain tank dump valve CV-1001. This modification was chosen to assess the impact of the modification, and included a review of design documents, safety screening documents, USAR, and applicable TS to determine that the temporary modification was consistent with modification documents, drawings and procedures. The inspectors also reviewed the post-installation test results to confirm that tests were satisfactory and that the actual impact of the temporary modification on the permanent system and interfacing systems were adequately verified.This review represented one inspection sample.
b. Findings
No findings of significance were identified.1EP6Drill Evaluation (71114.06)
a. Inspection Scope
The inspectors observed a full-scale emergency preparedness drill on June 27, 2007that the licensee had credited as providing input to the Drill/Exercise PI. The inspectors reviewed classification of events by the shift manager and emergency director, simulated notifications to off-site agencies, protective action recommendation development, and post-drill critiques. Observations were compared with the licensee's 12observations and CAP entries. The inspectors verified that there were no discrepanciesbetween observed performance and PI reported statistics.The review represented one inspection sample.
b. Findings
No findings of significance were identified.2.RADIATION SAFETYCornerstone: Public Radiation Safety2PS3Radiological Environmental Monitoring Program (REMP) And Radioactive MaterialControl Program (71122.03).1
Inspection Planning
a. Inspection Scope
The inspectors reviewed the most current Annual Environmental Monitoring Reports(2005 and 2006) and licensee assessment results to determine if the REMP was implemented as required by the Radiological Environmental Technical Specifications (RETS) and the Offsite Dose Calculation Manual (ODCM). The inspectors reviewed the reports for changes to the ODCM with respect to environmental monitoring and commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, inter-laboratory comparison program, and data analysis.The inspectors reviewed the ODCM and the Annual Reports for 2005 and 2006 toidentify environmental monitoring stations and their locations and evaluated licensee self-assessments, audits, and the licensee's vendor laboratory inter-laboratory comparison program results. The inspectors reviewed the Updated Final Safety Analysis Report for information regarding the environmental monitoring program and meteorological monitoring instrumentation. The inspectors also reviewed the scope of the licensee's audit program to determine if it met the requirements of 10 CFR 20.1101c.This review represented one inspection sample.
b. Findings
No findings of significance were identified.
13.2Onsite Inspection
a. Inspection Scope
The inspectors walked down five of the air sampling stations (greater than 30 percent)and approximately 20 percent of the thermoluminescent dosimeter monitoring stations to determine whether they were located as described in the ODCM and to determine the equipment material condition.The inspectors observed the collection and preparation of a variety of environmentalsamples including surface water and air filters. The environmental sampling program was evaluated to determine if it provided data that was representative of the release pathways as specified in the ODCM and that sampling techniques were performed in accordance with station procedures.From direct observations and record reviews, the inspectors determined if themeteorological instruments were operable, calibrated, and maintained in accordance with guidance contained in the annual report, NRC Safety Guide 23, and licensee procedures. The inspectors determined if the meteorological data readout and recording instruments, including computer interfaces and data loggers at the tower, were operable; if readouts of wind speed, wind direction, delta temperature, and atmospheric stability measurements were available on the licensee's computer system, which was available in the control room; and if the system was operable.The inspectors reviewed each event documented in the Annual EnvironmentalMonitoring Report which involved missed samples, inoperable samplers, lost thermoluminescent dosimeters, or anomalous measurements for the cause and corrective actions. The Annual Reports were reviewed for positive sample results (i.e., licensed radioactive material detected above the lower limits of detection) and the licensee's evaluation of the source of this material.The inspectors reviewed the ODCM for significant changes resulting from modificationsto the land use census or sampling station changes made since the last inspection.
This included a review of technical justifications for changed sampling locations. The inspectors determined if the licensee performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases on the environment.The inspectors reviewed calibration and maintenance records for five air samplers alongwith calibration records for radiation measurement (counting room) instrumentation that could be used for environmental sample analysis and was used for the free release of liquids or solids from the radiologically restricted area. This included the determination of the appropriate detection sensitivities for the counting samples, in that the instrumentation could achieve the RETS/ODCM required environmental lower levels of detection limits. The inspectors reviewed quality control data used to monitor radiation measurement instrument performance, and actions that would be taken if indications of degrading detector performance were observed.
14The licensee did not perform radio-chemical analyses of REMP samples. Radio-Chemical Analysis of REMP samples were performed by a vendor. The inspectors reviewed the licensee's vendor laboratory data of the analyzed samples.
The inspectors also reviewed the licensee's audit of the vendor laboratory's program to verify that the analytical and quality assurance programs were adequate.The inspectors reviewed quality assurance audit results of the program to determinewhether the licensee met the TS/ODCM requirements. This review represented six inspection samples.
b. Findings
No findings of significance were identified..3Unrestricted Release of Material From the Radiologically Restricted Area
a. Inspection Scope
The inspectors observed the access control location where the licensee monitoredpotentially contaminated material leaving the radiologically restricted area and inspected the methods used for the control, survey, and release of material from this area. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use to determine if the surveys were performed in accordance with plant procedures.The inspectors determined if the radiation monitoring instrumentation was appropriatefor the radiation types present and was calibrated with appropriate radiation sources that represented the expected isotopic mix. The inspectors reviewed the licensee's criteria for the survey and release of potentially contaminated material and determined if there was guidance on how to respond to an alarm indicating the presence of licensed radioactive material. The inspectors reviewed the licensee's equipment to determine if radiation detection sensitivities were consistent with the NRC guidance contained in Circular 81-07 and IE Information Notice 85-92 for surface contamination and in HPPOS-221 for volumetrically contaminated material. The inspectors determined if the licensee performed radiation surveys to detect radio-nuclides that decay via electron capture.The inspectors reviewed the licensee's procedures and records to determine if theradiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters such as counting times and background radiation levels. The inspectors determined whether the licensee had established a "release limit" by altering the instrument's typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high radiation background area.This review represented two inspection samples.
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b. Findings
No findings of significance were identified..4Identification and Resolution of Problems
a. Inspection Scope
The inspectors reviewed the licensee's self-assessments, audits, and Special Reportsrelated to the REMP since the last inspection to determine if identified problems were entered into the CAP for resolution. The inspectors also determined if the licensee's self-assessment program was capable of identifying and addressing repetitive deficiencies or significant individual deficiencies that were identified by the problemidentification and resolution process.The inspectors also reviewed corrective action reports related to the REMP that affectedenvironmental sampling and analysis and meteorological monitoring instrumentation.
Staff members were interviewed and documents were reviewed to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:*initial problem identification, characterization, and tracking;*disposition of operability/reportability issues;
- evaluation of safety significance/risk and priority for resolution;
- identification of repetitive problems;
- identification of contributing causes;
- identification and implementation of effective corrective actions;
- resolution of non-cited violations (NCVs) tracked in the corrective action system;and*implementation/consideration of risk significant operational experience feedback.This review represented one inspection sample.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
Cornerstones: Mitigating Systems, Barrier Integrity and Public Radiation Safety.1Reactor Safety Strategic Area
a. Inspection Scope
The inspectors used guidance and definitions contained in Nuclear Energy Institute(NEI) Document 99-02, Revision 5, "Regulatory Assessment Performance Indicator Guideline," to assess the accuracy of PI data. The inspectors reviewed licensee event reports (LERs), data within operator logs, and CAP documents for each PI. In conjunction with the RCS leakage detection inspection sample referenced in Section 1R22, the inspectors observed the surveillance activity that functionally tests instrumentation that measures identified RCS leakage.The following PIs were reviewed for a total of two inspection samples:
- Safety System Functional Failures, for the period of April 2006 through March2007 (Mitigating Systems Cornerstone); and*RCS Leakage, for the period of April 2006 through March 2007 (Barrier IntegrityCornerstone).
b. Findings
No findings of significance were identified..2Radiation Safety Strategic Area
a. Inspection Scope
The inspectors sampled the licensee's PI submittals for the periods listed below. The inspectors used PI definitions and guidance contained in Revision 5 of NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," to determine if the PI data was accurate. The following PI was reviewed:*RETS/ODCM Radiological Effluent Occurrences including first quarter 2006through first quarter 2007.The inspectors reviewed data associated with the RETS/ODCM PI to determine if theindicator was accurately assessed and reported. This review included the licensee's CAP database to identify any potential occurrences such as unmonitored, uncontrolled or improperly calculated effluent releases that may have impacted offsite dose. The inspectors also reviewed selected gaseous and liquid effluent release data and the results of associated offsite dose calculations generated over the previous four quarters.
Data collection and analyses methods for PIs were discussed with licensee 17representatives to determine if the process was implemented consistent with industryguidance in Revision 5 of NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline."This review represented one inspection sample.
b. Findings
No findings of significance were identified.4OA2Identification and Resolution of Problems (71152)Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, andEmergency Preparedness.1Routine Review of Identification and Resolution of Problems
a. Inspection Scope
As part of the routine inspections documented above, the inspectors verified that thelicensee entered the problems identified during the inspection into their CAP.
Additionally, the inspectors verified that the licensee was identifying issues at an appropriate threshold and entering them in the CAP, and verified that problems included in the licensee's CAP were properly addressed for resolution. Attributes reviewed included: complete and accurate identification of the problem; that timeliness was commensurate with the safety significance; that evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrence reviews were proper and adequate; and that the classification, prioritization and focus were commensurate with safety and sufficient to prevent recurrence of the issue.
b. Findings
No findings of significance were identified..2Daily CAP Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specifichuman performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's CAP. This review was accomplished by reviewing daily CAP summary reports and attending corrective action review board meetings.
b. Findings
No findings of significance were identified.
18.3Semi-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 inspector's review was focused on the licensee's ability to self-assess their performance and document the results of these assessments in CAP documents and Department Roll-up Meeting reports. The inspectors also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspector's review nominally considered the six-month period of January 2007 through June 2007, although some examples expanded beyond those dates when the scope of the trend warranted.Inspectors reviewed adverse trend CAP items associated with various events thatoccurred during the period. The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self assessment reports, and maintenance rule assessments.
The inspectors compared and contrasted their results with the results contained in the licensees' CAP trending documents. Corrective actions associated with a sample of the issues identified in the licensee's trend report were reviewed for adequacy.Assessment and ObservationsThere were no findings of significance identified. The inspectors evaluated the licenseetrending methodology and observed that the licensee had performed a detailed review.
The inspectors compared the licensee process results with the results of the inspectors' daily screening and did not identify any significant discrepancies.
b. Findings
No findings or issues of significance were identified.
.4 Annual Sample:
Service Water (SW) Inspection Program
a. Inspection Scope
The inspectors reviewed licensee actions to resolve issues associated with through-wallleakage on sections of piping in the 13 ESW system. The inspection focused on two specific examples: the first was a self-revealed through-wall leak which occurred on April 19, 2007; and the second was a licensee-identified through-wall leak on a separate section of piping during post-pipe replacement leakage testing on April 22, 2007. The inspectors reviewed past programmatic implementation of Fleet Procedure FP-PE-SW-01, "Service Water and Fire Protection Inspection Programs." Also included as part of this inspection was a review of the licensee's corrective action documents associated with past SW piping issues, and more recently, with the extent-of-condition associated with the 13 ESW through-wall leaks.
19 b.Assessments and ObservationsIntroduction: The inspectors identified an NCV of 10 CFR 50, Appendix B, Criterion V,"Instructions, Procedures, and Drawings," having very low safety significance (Green)for failing to accomplish portions of FP-PE-SW-01, "Service Water and Fire Protection Inspection Program," which required increased monitoring and determination of degradation mechanisms when wall thickness indications of in-scope systems were found to be less than 87.5 percent of nominal wall thickness. The inspectors identified several cases where examinations performed during past RFOs documented pipe wall thickness measurements less than 87.5 percent (in some cases nearly 50 percent of nominal thickness), and increased monitoring, evaluation, and/or extent-of-condition reviews were not performed as required by the licensee's inspection program.Description: On April 19, 2007, with the reactor in cold shutdown (Mode 4), a smallthrough-wall leak on the 13 ESW pump discharge piping was self-revealed to the licensee by an operator conducting rounds. The licensee performed reactive ultrasonic test (UT) exams of the piping to determine the extent of the pipe wall thinning. The 13 or 14 ESW systems were not within the original SW inspection program scope for the March-April 2007 refueling outage.The licensee performed a limited extent-of-condition review of similar pipingcomponents using traditional UT techniques for the 13 ESW system and did not identify any locations where wall thicknesses were less than 30 percent of nominal wall thickness (the minimum wall thickness for which a determination of operability and an NRC relief request per American Society of Mechanical Engineers (ASME) Code Case N-597-1 would be required to justify continued operation of the safety-related system).
During post-pipe replacement leakage testing of the 13 ESW system an additional through-wall leak was identified just upstream of the initial leaking component. It was later determined that this indication was not identified during the initial extent-of-condition review due to use of traditional "low-gain" settings for the UT equipment.On April 22, the licensee performed UT examinations (using a "high-gain" setting) ofboth the 13 and 14 ESW trains. These examinations included sections of both ESW trains from the discharge piping of each pump to where each ESW train connected with the SW system piping. These piping sections were selected because they were particularly at-risk for bio-fouling (the degradation mechanism that caused the April 19 and 22 leaks) since the piping sections were not treated with a biocide agent and were typically laid-up with stagnant river water for lengthy periods of time. During a second extent-of-condition review, a section of piping on the 14 ESW system was identified as being below the minimum-allowed wall thickness and was subsequently replaced.The inspectors reviewed specific sections of FP-PE-SW-01 concerning componentscope selection, frequency, and corrective actions. Section 5.10.1.2 stated, in part,
"When measured wear is less than 0.875 Tnom [nominal wall thickness] and greater thanTmin [minimum wall thickness; 30 percent of Tnom], follow-up inspections shall be on anincreased frequency, and the degradation mechanism should be considered." The 20inspectors reviewed UT measurements for the 13 and 14 ESW systems conductedduring the 1998, 2005, and 2007 RFOs to determine whether the licensee was meeting the requirements of FP-PE-SW-01, and to determine why the two sections of piping in the 13 ESW system were not identified by the monitoring program. It should be noted that the 13 and 14 ESW systems were not examined during the 2001 or 2003 RFOs, and the 2007 examinations were only conducted as part of the extent-of-condition review from the April 19 leak (i.e. they were not originally part of the examination scope).The inspectors identified that on several occasions dating back to 1998, pipe wallthicknesses were found to be less than 87.5 percent of nominal wall thickness. In some cases, very little margin existed between the measured wall thickness and 50 percent of nominal wall thickness. However, the inspectors could not find, nor could the licensee provide, any documentation that evaluated the degradation mechanism(s) of these piping components. Additionally, the licensee did not formulate any plan to increase the monitoring frequency of these low-margin piping components. After discussing these issues with individuals responsible for the SW inspection program, the inspectors were informed that pipe wall thinning rates were the primary criteria used for future inspection selection and/or pipe replacement. In a few cases dating back to 1998, for example, some indications that were less than 87.5 percent of nominal wall thickness were found to be less than 50 percent of nominal wall thickness in 2007. These thinning rates (linear projection); however, did not conservatively coincide with the predicted thinning rates calculated and used for future scope selection. Per FP-PE-SW-01, the intent of the 87.5 percent of nominal wall thickness criteria was to provide confirmatory data to verify that the predicted thinning rate accurately modeled the actual thinning rate -
where this was not the case, at-risk areas within the piping systems could be monitored more frequently. In the 1998 cases where indications were found less than 87.5 percent of nominal wall thickness, the documented thinning rate would have led to eventual replacement in as many as 20-30 years later, whereas actual thinning rates were demonstrated to be much faster.As part of the licensee's corrective actions, an apparent cause evaluation wasperformed to determine why, with a programmatic inspection process in place, pipe wall thicknesses within the 13 and 14 ESW systems degraded in some cases to the point of leaking and in other cases to being below minimum thickness, requiring replacement.
The licensee also performed an extensive focused self-assessment with input from outside expertise to evaluate testing programs, inspection and maintenance, design bases, chemistry/biological-fouling, procedures, training, program effectiveness, and operating experience use at the site with respect to raw water systems. As a result of the apparent cause evaluation and focused self-assessment, the licensee developed (or were in the process of developing) several corrective actions to address, in part, the implementation and procedural deficiencies of FP-PE-SW-01.Analysis: The inspectors determined that failing to accomplish licensee-imposedrequired actions of FP-PE-SW-01, a procedure in place to address Generic Letter 89-13 commitment items, was a performance deficiency warranting a significance evaluation.
The inspectors concluded that the finding was more than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports,"
Appendix B, "Issue Screening," issued on June 22, 2006. The finding was more than 21minor because it affected the attribute of equipment performance, which impacted theMitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Although the through-wall leakage was self-revealed during a time when the 13 and 14 ESW systems were not required to be operable (shutdown plant condition); wall thicknesses less than the nominal wall thickness existed, were not identified by the licensee, and could have been self-revealed at any time (particularly when the system was required to be operable). The inspectors determined that, in part, the cause of the performance deficiency affected the cross-cutting area of Human Performance, had resource components, and involved aspects associated with maintaining long-term plant safety by the maintenance of design margins and the minimization of long-standing equipment issues H.2(a).Because both the through-wall leakage of 13 ESW system piping and the performancedeficiency were identified during plant shutdown conditions, the inspectors evaluated the finding using IMC 0609, Appendix G, "Phase 1 Screening," and determined that Checklist 8, "Boiling Water Reactor (BWR) Cold Shutdown or Refueling Operation Time to Boil > 2 Hours: Reactor Coolant System (RCS) Level < 23 Feet Above Top of Flange." However, because all qualitative criteria within the Core Heat Removal, Inventory Control, Power Availability, and Containment guidelines were met; because the finding did not meet the Checklist 8 criteria for Phase 2 or Phase 3 quantitative analysis (the finding did not: increase the likelihood of a loss of RCS inventory; degrade the licensee's ability to terminate a leak path or add RCS inventory when needed; significantly degrade the licensee's ability to recover decay heat removal once it was lost; or involve only one or less safety relief valves available to establish a heat removal path to the suppression pool due to the vessel head being removed); and because no event occurred that could be characterized as a loss of control as listed in Table 1 of IMC 0609, Appendix G, the finding was considered to be of very low safety significance (Green).Enforcement: Title 10 CFR 50, Appendix B, Criterion V requires, in part, that activitiesaffecting quality shall be accomplished in accordance with prescribed instructions, procedures, or drawings. Contrary to this requirement, the licensee failed to accomplish actions in accordance with FP-PE-SW-01, "Service Water and Fire Protection Inspection Program," which required increased monitoring and evaluation if pipe wall thinning for in-scope systems was found to be below specific acceptance criteria.
Because the issues were of very low safety significance and because the issues were entered into the licensee's corrective action program (CAPs 01088604, 01088981, 01088988, 01088993, and 01092699), this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000263/2007003-01)..5Annual Sample: Operator Workaround (OWA) Review
a. Inspection Scope
The inspectors evaluated the licensee's implementation of processes used to identify,document, track, and resolve operational challenges.
22 b.IssuesThe inspectors reviewed both current and historical operational challenge records todetermine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their CAP, and proposed or implemented appropriate and timely corrective actions which addressed each issue. Included in the review were:*OWAs;*non-transient OWAs;
- control room deficiencies;
- control room "black board" challenges;
- accelerated testing (for equipment with performance issues); and *critical operations manual emergent changes.The inspectors performed plant walkdowns and reviewed various other records toidentify OWAs that had not been identified and evaluated by the licensee. Specifically, items that:*required operations contrary to past training or required more detailedknowledge of a system than was routinely provided;*required a change from longstanding operational practices;
- required operation of systems or components in a manner dissimilar from similarsystems or components;*created the potential for compensatory actions to be performed on equipment orunder conditions for which it was not appropriate;*impaired access to required indications, increased the dependence on oralcommunications, or required actions to be performed under adverse environmental conditions; or*required the use of equipment and interfaces that had not been designed withconsideration of the task being performed.The inspectors reviewed items such as licensee night orders, temporary informationtags, out-plant status boards, daily plant and equipment status logs, controllers being operated in manual, instruments that were out-of-service, and operator aids or tools being used to compensate for material deficiencies as potential sources of unidentified operator workarounds.No findings of significance were identified..6Annual Sample: Documentation of Operability Classifications for SSCs
a. Inspection Scope
The inspectors reviewed the ten outstanding operable-but-degraded (OBD) oroperable-but-nonconforming (OBN) conditions that the licensee proposed to carry forward and not correct prior to plant startup, subsequent to the completion of RFO 23.
This inspection included reviewing selected operability evaluations, corrective action 23documents, condition evaluations, and technical evaluations which justified continuedoperations with the degraded or non-conforming SSCs. b.Assessments and ObservationsThe licensee completed RFO 23 on April 28, 2007. During the week prior to starting upthe reactor, as part of their pre-startup inspections, the inspectors attended several licensee restart readiness meetings. One topic that was discussed during these meetings was the evaluation of OBD/OBN SSCs that would not be corrected prior to starting up the reactor plant. Subsequent to completion of one of the restart readiness meetings, the inspectors queried a licensee manager regarding how initial operability calls for each of the ten OBD/OBN SSCs were documented; the individual was unsure.Licensee Procedure FP-OP-OL-01, "Operability Determination," Revision 2, states inpart that:*The Shift Manager determines if a condition exists that could call into questionthe ability of an SSC to perform its specified safety function.*An operability recommendation is not required if the Shift Manager candetermine SSC operability using available resources, or if adequate information exists in the Action Request [CAP document]. Documentation should be sufficient so that an independent reviewer can arrive at the same conclusion.*If there is a reasonable expectation that the SSC is operable, OBD, or OBN, butclarifying documentation is required to support the operability determination, then the Shift Manager will request an operability recommendation and update the OPS STATUS attribute of the CAP Action Request with the basis for reasonable expectation of operability and that an operability recommendation has been requested to support a follow-up operability determination.Also, in regards to operability determinations, Licensee Procedure FP-PA-ARP-01,"CAP Action Request Process," Revision 16, states in part that:*An SRO [senior reactor operator] SHALL review the CAP Action Request if theissue meets any of the following criteria: affects plant operation or plant equipment; potentially involves external agency notification; involves Technical Specification compliance; or presents an immediate threat to personnel safety.*The following SHALL be determined and documented, where applicable, by anSRO: operability status of any affected SSC; basis or justification used for the immediate operability declaration; and any compensatory actions taken to support operability.*The SRO may initiate an Assignment for the performance of an operabilityrecommendation to support confirmation of the operability status determination.
While awaiting completion of the operability recommendation, the SRO SHALL update the CAP Action Request to document the immediate operability determination. Upon completion of the operability recommendation, the SRO SHALL review the operability recommendation and make an operability declaration. The SRO SHALL document the final declaration on the electronic record.
24The inspectors reviewed the corrective action documents associated with each of theten outstanding OBD/OBN SSCs and determined that the licensee was inconsistent in the documentation of the operability status of these OBD/OBN SSCs. Specific observations included:*The OPS STATUS attribute of the CAP Action Request was not used todocument requests for operability recommendations.*Only half of the OBD/OBN issues were evaluated using the operabilityrecommendation process. In each of these cases, the SRO reviewed and accepted the operability recommendation, but did not document the final operability declaration on the electronic record. *For most OBD/OBN issues not supported by a formal operabilityrecommendation, a clear documented initial statement of operability by an SRO could not be located by the inspectors. Typically, the corrective action documents associated with these issues contained an engineering evaluation of sufficient quality to support a determination of OBD/OBN.The inconsistencies in the implementation of FP-PA-ARP-01 and FP-OP-OL-01, whendispositioning OBD/OBN items, was discussed with senior plant management. Prior to plant startup on April 26, 2007, an SRO reviewed all ten open OBD/OBN issues and formally documented the operability status of each issue in the OPS STATUS attribute of each associated CAP Action Request. Additionally, a memo from Operations department management outlining expectations regarding SRO review of OBD/OBN items was forwarded to all shift managers. This communication included the expectation to utilize the OPR process whenever OBD/OBN conditions are expected.
The memo also stressed that OBD/OBN conditions require SRO concurrence to ensure that operability is maintained and actions to restore full qualification are planned or are in place.No findings of significance were identified by the inspectors during this inspection.4OA3Event Follow-up (71153).1(Closed) Licensee Event Report 50-263/2006-002-01: "Unplanned LCO Due to Loss ofCooling in the Upper 4kV Room"This initial evaluation of this event was performed by the inspectors and documentedin Inspection Report 05000263/2006005. This LER revision provides additional information regarding the cause of the event, subsequent to the completion of the licensee's cause evaluation. The additional information was reviewed by the inspectors and no findings of significance were identified..2(Open) Licensee Event Report 50-263/2007-002-00: "Unexpected De-energizing ofBus 16 During Refuel Outage 23"The initial evaluation of this event was performed by the inspectors and documented inInspection Report 05000263/2007002. This LER provides information regarding the preliminary cause of the event and discusses planned and completed corrective actions.
25The licensee is continuing its investigation into this event, and has committed to issuinga supplement to this LER when the investigation has completed. The information contained in this LER was reviewed by the inspectors and no new findings of significance were identified. This LER will remain open pending review of the supplement when issued..3Operator Performance During Non-Routine Event: Reactor Pressure Boundary TestOn April 13, 2007, the licensee performed a reactor coolant pressure boundary leakagetest. This test is required by ASME Boiler and Pressure Vessel Code Section XI prior to startup following each reactor RFO. The primary focus of the inspectors during the performance of this test was to evaluate the operating crew's ability to control the reactor coolant temperature and rate of reactor coolant pressure increase while increasing pressure to approximately 1000 psig. Also, as part of this inspection, the inspectors attended the test pre-job brief, monitored the performance of selected test prerequisite activities, and observed portions of post-test system restorations.No findings of significance were identified during this inspection. 4OA6Meetings.1Exit MeetingThe inspectors presented the inspection results to Mr. Grubb and other members oflicensee management on July 5, 2007. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified..2Interim Exit MeetingsInterim exits were conducted for:
- Radiological environment monitoring program and radioactive material controlprogram and RETS/ODCM radiological effluents, with Mr. W. Guldemond on May 4, 2007; and*Maintenance effectiveness periodic evaluation with Mr. J. Grubb, EngineeringDirector, on May 18, 2007.4OA7Licensee-Identified ViolationsThe following violations of very low safety significance were identified by the licenseeand are violations of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.*Technical Specification 3.9.2, "Refuel Position One-Rod-Out Interlock" requiresimmediately, with the refuel position one rod-out-interlock inoperable, that 1) control rod withdrawal be suspended, and 2) actions be initiated to fully insert 26all insert-able control rods in core cells containing one or more fuel assemblies. Contrary to this requirement, during control rod exercise testing on April 20, 2007, the reed switch which fed the one rod-out-interlock was inoperable for Control Rod 26-35 and immediate actions were not taken to suspend control rod withdrawal. Although unrecognized at the time by the operators - because the full core display position indication for Control Rod 26-35 did not change from green to amber in color, the one-rod-out interlock was not met and thus was inoperable. After completing testing for Control Rod 26-35 and while withdrawing the next control rod (26-31) in the test one notch (Position 02), the operators realized that the color change had not occurred for Control Rod 26-35.
The operators immediately re-inserted Control Rod 26-31, stopped the test and notified management, and entered the issue into the corrective action program as CAP 01088836. This finding is of very low safety significance because at no time was more than one control rod withdrawn.ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- T. O'Connor, Site Vice President
- B. Sawatzke, Plant Manager
- J. Grubb, Site Engineering Director
- S. Radebaugh, Maintenance Manager
- S. Sharp, Operations Manager
- W. Guldemond, Nuclear Safety Assurance Manager
- K. Jepson, Radiation Protection - Chemistry Manager
- K. Shields, Maintenance Rule Coordinator
- J. Sabados, General Supervisor Chemistry
- K. Riemer, Chief, Reactor Projects Branch 2
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened50-263/2007-002-00LERUnexpected De-energizing of Bus 16 During RefuelOutage 23 (Section 4OA3.2)
Opened and Closed
05000263/2007003-01NCVFailure to Accomplish Service Water Inspection ProgramRequirements (Section 4OA4.4)Closed50-263/2006-002-01LERUnplanned LCO Due to Loss of Cooling in the Upper4kV Room (Section 4OA3.1)DiscussedNone.
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 or any part of it, unless this is stated in the body of the inspection reports.
Section 1R01:
- Adverse Weather1487; Site Loose Material Quarterly Inspection; Revision 3; dated April 17, 2007Licensee Response to Generic Letter 2006-02; Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power; July 21, 2006
Section 1R04: Equipment Alignment9111-02; Shutdown Cooling Division
- II Protected System Ticket Checklist; Revision 12118; Plant Prestart Checklist HPCI System; Revision 14
- 2154-10; HPCI System Prestart Valve Checklist; Revision 28
- 2154-23; RHRSW System Prestart Valve Checklist; Revision 27
- NH-36664-CC; RHR Service Water & ESW Systems P&ID; Revision 76
Section 1R05: Fire ProtectionStrategy A.3-02-B; East
- Strategy A.3-01-F; Torus Area - Elevation 896' and 923'; Revision 7
- Strategy A.3-17; Turbine Building North Cable Corridor 941'; Revision 4
- Strategy A.3-16; Corridor, Turbine Building East and West (Elevations 911' and 931');
- Revision 10
- Strategy A.3-13-B; Reactor Feed Pump and Lube Oil Reservoir Room; Revision 9
- Strategy A.3-13-C; Turbine Building 911' Elevation East MCC Area; Revision 6
- Strategy A.3-08; Cable Spreading Room; Revision 11
- Strategy A.3-19-B; Essential MCC Area - No. 142 and 142 931' Elevation; Revision 9
- Strategy A.3-19-A; Make-Up Demineralizer Area; Revision 5
- Strategy A.3-23-B; Intake Structure Corridor; Revision 5
Section 1R06:
- Flood Protection MeasuresA.6; Acts of Nature; Revision
- 241478; Annual Flood Surveillance; Revision 02
- Design Basis Document-T.5; External Flooding; Revision 04
- CAP 01096533; NRC Review Questions the Sites' Ability to Implement A.6 Procedure
- NH-178639; MNGP Flood Barriers for A.6 Acts of Nature Procedure; Revision B
- NH-48841; MNGP Flood Protection for Office and Control Building - Steel Details
- NH-51677-A; MNGP Flood Protection for Turbine Building Tube Pulling Structure - Steel Details Attachment3
Section 1R11: Licensed Operator Requalification ProgramSimulator Exercise Guide
- RG-SS-56E; HPCI Initiation, Bus 15 Lockout, Steam Leak in Drywell;Revision 0
==Section 1R12: Maintenance EffectivenessCAP
- 01088981; Adverse Trend:==
- Monitoring Fails to Pre-identify Pipe Wall FailuresCAP
- 01088993; Biocide Not Performed on 13/14 ESW Discharge
- EWI-08.22.01; Generic Letter 89-13; Revision 1
- 1386-03; ESW External Pipe Inspection Loop A and B; Revision 8
- FP-PE-SW-01; SW and Fire Protection Inspection Program; Revision 2
- Monticello Maintenance Rule Periodic Assessment Report; June, 2004 - March 2005
- Monticello Maintenance Rule Periodic Assessment Report; April 2005 - March 2006
- EWI-05.02.01; Monticello Maintenance Rule Program Document; Revision 11
- PEI-06.01; Maintenance Rule Coordinator Activities; Revision 3
- Monticello Maintenance Rule Program System Basis Document - NDG; Revision 3
- Maintenance Rule Performance Improvement Plan (a)(1) for Safety SW; October 15, 2004, Revision 1
- Maintenance Rule Performance Improvement Plan (a)(1) for NDG; April 29, 2004
- M-Rule Expert Panel Meeting Minutes; February 14, 2007
- Availability and Reliability Trend NDG; June 2005 - March 2007
- Availability and Reliability Trend DGN Division I; June 2005 - March 2007
- CAP 00830789;
- CV-2065 Failed PMT Stroke Time Test; April 8, 2005
- October 24, 2005
- CAP 01027374; Water Seepage into Upper kV Space; May 1, 2006
- Monticello Maintenance Rule Program System Basis Document - RWCU; Revision 3
- RC-49-1, 11 RWCU F/D Air Supply or Vent
- CAP 01010982;
- AO-12-4-41, 11 RWCU Precoat Pump Discharge Leaks
- CAP 01011480; Water Leaking From 4160 kV Cable Penetration
- CAP 039569; Degrade Grounding Cable in Reactor Core Isolation Cooling Pull Box in Reactor Building, Elevation 896' Cable and Raceway Information System Electrical Cable Schedule Data for Selected 4 kV
- Cables
- EWI-08.19.01; Cable Condition Monitoring Program; Revision 0
- 4181-03-PM; 13 RHR Pump Motor; Revision 06
- 4181-01-PM; 11 RHR Pump Motor; Revision 05
- 211-01-PM; CS Pump Motor 11; Revision 08
- Assorted Megger Data for 11 RHR Pump, 13 RHR Pump, and 13 CS Pump During a Time Period From 2002 to 2006
- Attachment4NF-36172; MNGP Turbine Generator Building Embedded Conduits Below Elevation 911"-0";Revision A
- Drawing E-303; Reactor Building Embedded Conduits Below Elevation 896'; Revision 2
Section 1R13:
- Maintenance Risk Assessments and Emergent Work ControlApril 4, 2007; Shutdown Cooling Window ScheduleCombined Shutdown Cooling Window Contingency Plan; prepared April 4, 2007
- March 28-31, 2005; Temperature Trend During Shutdown Cooling Isolation (April 4, 2007,
e-mail attachment from Nuclear Engineering Staff to Operations Shift Manager)
- Projected Equilibrium Pool/Cavity Temperatures for March 17 to April 17, 2007 (April 4, 2007,
e-mail attachment from Nuclear Engineering Staff to Operations Shift Manager)
- WO 325884-03; Investigate/Repair Cause of Circuit Malfunction Troubleshooting Plan for Work Order (WO)
- 325884; April 22, 2007
- WO 326287-01; Investigate 12 core spray pump Motor Cooling Inlet/Coils
- 1339; ECCS Pump Motor Cooler Flush; Revision 19
- CAP 01088773; Control Rod Drive (CRD) 26-35 Displays Green Indication When Not at Position
- WO 00140371; Full Core Display Reads Incorrect for CRD-26-35
- WO 00267320; Contingency - Repair Bad rod position indication system Indications - RFOCAP
- 01088988; Leak from Elbow - Line ESW 1-4" HBD Adjacent to Valve ESW-44
- CAP 01094202; Increase Temperature and Amps on H2 Seal Oil Vacuum Gearcase/Motor
==Section 1R15: Operability EvaluationsCAP
- 01081986; Internal Seal Welds in Safety Relief Valves May Not Meet CodesCAP
- 01088367; 12==
- CS Pump Motor Cooler Reduced Cooling Flow
- CAP 01089542; NRC Question:
- Is Abandoned Cable in Drywell Accounted for in Analysis?
- Sargent & Lundy Evaluation 2007-06140; Acceptability of Vibration Monitoring Modification
(EC 9174) with Respect to ECCS Suction Strainer Debris Loading; Revision 00
- CA-98-310; ECCS Suction Strainer Debris Loading for Prototype Strainer Test; Revision 00
- CA-97-228; MNGP:
- ECCS Strainer Head Loss Estimates; Revision 00
- CA-01-135; Evaluation of Effects of Paint Chips on Debris Loading of ECCS Suction Strainers;Revision 00
- CAP 01093320; Unable to Located Document on Control Room Ventilation Heat Load Effect
- ESW System
- 255-11-III-3; 13 ESW Quarterly Pump and Valve Tests; Revision 38Safety Review Item 88-013; Justification for Plant Operation at SW Temperatures up to 90°F;
- Revision 1
- Attachment5
Section 1R19: Post-Maintenance Testing0255-20-IIC-1; Reactor Coolant Pressure Boundary Leakage Test; Revision 280255-20-IIC-2; Reactor Coolant Pressure Boundary Leakage Test; Revision 23
- PEI-02.05.08; Visual Examination (VT-2) for Evidence of Leakage; Revision 0
- 0136; Integrated Primary Containment Leak Rate Test (Parts A & B); Revision 16
- WO 292142; 0136 Integrated Primary Containment Leak Rate Test
- 0137 Master Local Leak Rate Test; Revision 29
- WO 284610; 0127 Master Local Leak Rate Test
- WO 322632; 13 Battery Replace Cells 37 (D3A) and 65 (D3B)
- 0193-01; No. 13 250 Vdc Battery Operability Check (Division I); Revision 21
- 20; Changeout Procedure for ASCO Solenoid Valves; Revision 20
- PM 4920 - Replace Solenoid Valve SV-2379
- WO 331287; P-109B, Replace Pump
Section 1R20:
- Outage Activities1371; Drywell Prestart Inspection; Revision 07C.1; Startup Procedure; Revision 54
- 2300; Reactivity Adjustment; Revision 0; and Attachments for Reactor Startup 232
- 2159; Predicted Critical for Plant Startup; Revision 7 (Reactor Startup 232)
Section 1R22: Surveillance Testing0255-04-ID-5;
- RHR Shutdown Cooling Inboard and Outboard Supply Isolation Valve Leak Test;Revision 13
- WO 0289065; 0255-04-ID-5 RHR Shutdown Cooling Inboard Supply Isolation Valve Leak Test
- 255-20-IIC-1; Reactor Coolant Pressure Boundary Leakage Test; Revision 28
- 255-20-IIC-2; Reactor Coolant Pressure Boundary Leakage Test; Revision 23
- PEI-02.05.08; Visual Examination (VT-2) for Evidence of Leakage; Revision 0
- 0136; Integrated Primary Containment Leak Rate Test; Revision 16
- 0515; Primary Containment Visual Examination for Structural Problems; Revision 4Engineering Action Plan to Address Low Flow to 'B' Emergency Filtration Train-ESW
- Components; April 2, 2007
- SCR-07-0182; Modify 14 ESW Quarterly Pump and Valve Tests
- 255-11-III-4; 14 ESW Quarterly Pump and Valve Tests; Revision 42; March 29, 20070255-11-III-4; 14 ESW Quarterly Pump and Valve Tests; Revision 43; March 31, 20070255-11-III-4; 14 ESW Quarterly Pump and Valve Tests; Revision 44; April 1,
- 20070136; Integrated Primary Containment Leak Rate Test (Parts A & C); Revision 16
- WO 292142; 0136 Integrated Primary Containment Leak Rate Test
- 0137 Master Local Leak Rate Test; Revision 29
- WO 284610; 0127 Master Local Leak Rate Test
- CAP 01088531; Steps in 0136 Were Missed
- CAP 01088249; Step 108 of 0136 Performed Prior to Temporary Change
- OSP-HPC-0563; HPCI Automatic Initiation Test; Revision 1
- Attachment6CAP
- 01088532; HPCI Control Valve (HO-8) Did Not Respond Properly on Initiation Signal0419-01; Alternate Shutdown System Cycle Functional Test for 12 DG/Diesel Oil Transfer Pump Switches; Revision 14
- CAP 01088410; Unexpected Response at Step 22 of 419-01 Alternate Shutdown System Test
- 0533; Containment Sump Flow Measurement Instrumentation; Revision 12
- 257-A; Reactor Coolant Drywell Leak Rate Check; Revision 95
- CAP01095672; Loss of Control Power for B3339
- 1388; 13 DG Auto Start/Loading Test; Revision 6
- OSP-ECC-0566; Low Pressure ECCS Automatic Initiation and Loss of Auxiliary Power Test;
- Revision 2
==Section 1R23: Temporary Plant ModificationsCAP
- 01090085; Significant Full Wall Crack on Weld Downstream of==
- CV-1001Engineering Change (EC) 10745;
- CV-1001 Enclosure Repair of Cracked Weld
- WO 327675-09; Install Temporary Modification
- EC 10745 for
- CV-1001 and Sealant
- CFR 50.59 Screening (SCR) 07-0252;
- CV-1001 Enclosure Repair of Cracked Weld;
- Revision 0
Section 1EP6:
- Drill EvaluationController Copy of the July 27, 2007, Monticello Emergency Plan Drill
Section 2PS3: REMP and Radioactive Material Control Program
- AR 01090933 CAP; Lab Germanium Detectors Calibration Is Not Scheduled; May 3, 2007AR
- The ODCM Shows Them in the Same Sector; May 3, 2007
- AR 01090414 CAP; Unposted Contamination Found on the Inside of a Sealand WhilePerforming Surveys of Miscellaneous Tools, Equipment, and Areas Outside the radiologically-controlled area; May 2, 2007
- AR 01007497 CAP; REMP Upstream Invertebrate Missed; December 14, 2005
- AR 01068703 CAP; Missed REMP Upstream River Sample Due to Thick Ice on the River;
- December 20, 2006
- 2006 Annual Radiological Environmental Operating Report Offsite Radiation Dose Assessment for January 1 through December 31, 2006
Procedure
- 5829; REMP Air Sampler Calibration; Revision 5; November 23, 2005
Procedure
- I.03.39; MCA Operation/Gamma Isotopic Analysis; Revision 7
- HPGe Efficiency and Energy Calibration Analysis for Detector No. 1 and 3; Geometry No. 22;
- March 15, 2007
- RPGP-01.22; Periodic Evaluation of Monticello Radionuclide Mix; Revision 2
- I.05.34; Quarterly Collection and Shipping of Environmental Thermoluminescence Dosimeter Samples; Revision 7
- I.05.38; Annual Cultivated Crop Sampling; Revision 1
- I.05.37; Environmental Milk Sampling; Revision 3
- I.05.39; Monthly Radiological Environmental Analysis Report Verification; Revision 0I.05.41; Annual Land Use Census and Critical Receptor Identification; Revision 3
- I.05.42; Interlaboratory Comparison Program; Revision 0
- I.05.35; Quarterly Environmental Ground Water Sampling; Revision 4
- Attachment7I.05.36; Semiannual Shoreline Sediment; Fish and Invertebrate Sampling; Revision 3I.05.43; REMP Air-Sampler Calibration and Maintenance; Revision 1
- R.06.09; Storage and Inventory of Radioactive Material Outside the Power Block; Revision 9
- R.06.05; Conditional Release of Radioactive Material; Revision 13
- Appendix A; Interlaboratory Comparison Program Results; Environmental, Inc.; Midwest Laboratory; January 2006 through December 2006
- 20; Monticello Meteorological Station Calibration Procedure; Revision 12
- I.06.12; Meteorological/Radiological Data Review; Revision 3
- RPGP-01.14; Self-Assessment Program; Revision 12
- R.07.02; Area Posting; Special Status Signs and Hot Spot Stickers; Revision 28
Section 4OA1: Performance Indicator Verification3530-09;
- NRC Performance Indicator - Safety System Functional Failures; Reporting Periods ofSecond quarter 2006 through first quarter 2007
- 3530-12; NRC Performance Indicator - RCS Total Leakage Worksheet; Reporting Periods of Second quarter 2006 through first quarter 2007
- 0000-J; Operations Daily Log - Part J Outplant; Revision 95
- 2006 Annual Radiological Environmental Operating Report Offsite Radiation Dose Assessment for January 1 through December 31, 2006
Section 4OA2: Identification and Resolution of ProblemsMonticello Operational Challenges List (printed May 2, 2007)Monticello Operational Challenges History List (printed May 2, 2007)
- OWI-01.07; Operations Department Self Assessment; Revision 26
- Operable-but-Degraded/Non-Conforming List (printed May 2, 2007)
- FP-PE-SW-01; Service Water and Fire Protection Inspection Program; Revision 2
- SAR 0840800; Service Water Systems Focused Self-Assessment
- 1998 Monticello Microbiologically Influenced Corrosion Outage Summary Report Monticello 2001 Microbiologically Influenced Corrosion Outage Summary Report Monticello 2003 Microbiologically Influenced Corrosion Outage Summary Report
- SW/MIC Program Outage Summary Report Monticello
- RFO 22 3/5/2005-4/3/2005
- Monticello 2007 SW/Microbiologically-Influenced Corrosion Program Outage Summary Report
- RFO 23
- EWI-08.22.01; Generic Letter 89-013; Revision 1
- CAP 01088988; Leak from Elbow - Line
- ESW1-4"-HBD Adjacent to Valve ESW-44
- CAP 01088981; Adverse Trend:
- Monitoring Fails to Pre-Identify Pipe Wall Failures
- CAP 01098106; SW/MIC inspection program not fully effective
- PEI-02.03.12; Ultrasonic Detection of Pitting; Revision 0
- PEI-02.03.05; Ultrasonic Thickness Measurement; Revision 0
- 1386-03; ESW External Pipe Inspection Loop A and B; Revision 8
- CAP 00717451; Low Pressure Coolant Injection Selection Logic May Not Meet USAR Break Size Detection Requirement
- CAP 01022687;
- SW1-18"-JF Does Not Meet Class I Design Criteria Attachment8CAP
- 01039272; Class II Internal Flooding Lines Don't Meet Class I CriteriaCAP
- 01052180; Class II Fire Lines Do Not Meet Class I Design Criteria
- CAP 01056182; Motor Terminal Voltages Could Drop Below 90 Percent Rated Voltage Under Degraded Conditions Prior to Actuation of Degrade Voltage Protection
- CAP 00752428; Vendor Report on Emergency Filtration Train Design and Licensing Basis Review Requires Site Acceptance
- CAP 01081986; Internal Seal Welds in Safety Relief Valves May Not Meet Codes
- CAP 01083634; Pieces of Reactor Vessel Insulation Missing Department Roll-Up Meeting Results; Engineering; First Quarter 2007
- Department Roll-Up Meeting Results; Maintenance; First Quarter 2007
- Department Roll-Up Meeting Results; Operations; First Quarter 2007
- Department Roll-Up Meeting Results;
- RP-Chem; First Quarter 2007
- CAP 01093869; Adverse Trend in apparent cause evaluations Failing Grades
- CAP 01095951; Negative Trend in Operations Performance Using Jumpers and Boots
- CAP 01096071; Several Rad Material Control Events in Last Two Years
- CAP 01093838; Adverse Trend of No Rework Category in Engineering Thumbs Database
- CAP 01093830; Adverse Trend for Inadequate Tracking Human Performance Failure Mode
- CAP 01093097; Potential Adverse Trend in Contamination Area Boundary Control
- CAP 01092729; Adverse Trend of human performance Induced Equipment Failures in 2006
- CAP 01092701; Adverse Trend in Engineering Human Performance Event Clock Resets
- CAP 01090258; Receiving High RHR shutdown cooling Header Pressure Multiple Times
- CAP 01085105; Refueling Human Performance Events
- CAP 01081675; Emergent Work Challenging the Organization
- CAP 01081245; Recent Increase in Worker Safety Issues
- CAP 01081173; Potential Adverse Trend in Reactor and Turbine Building Crane Performance
- CAP 01076706; quality assurance finding-Recurring Programmatic Issues with Site Welding Program
- CAP 01075452; Continuing Adverse Trend in Procedure Use and Compliance
- CAP 01074810; Repeat Issue, Mod Packages with Admin Errors
- CAP 01070732; Screen Team Effectiveness Indicator Below Fleet Expectation
Section 4OA3:
- Event Follow-up0255-20-IIC-1; Reactor Coolant Pressure Boundary Leakage Test; Revision 28
LIST OF ACRONYMS
- CA [[]]
- CF [[]]
- CR [[]]
DControl Rod Drive
- DG [[]]
- DR [[]]
- ECC [[]]
- ED [[]]
- ES [[]]
WEmergency Service Water
- HC [[]]
UHydraulic Control Unit
- HP [[]]
- HPC [[]]
- IM [[]]
- ILR [[]]
TIntegrated Leak Rate Test
kVKilovolt
- LE [[]]
- MC [[]]
- MNG [[]]
- NC [[]]
- NE [[]]
- NR [[]]
CU.S. Nuclear Regulatory Commission
- OB [[]]
- ODC [[]]
- OW [[]]
- PAR [[]]
SPublicly Available Records
- PM [[]]
- PSI [[]]
GPounds per Square Inch Gauge
- RC [[]]
- REM [[]]
- RET [[]]
- RF [[]]
- RH [[]]
- RHRS [[]]
- RWC [[]]
- SD [[]]
- SR [[]]
- SS [[]]
- LIST [[]]
- OF [[]]
- ACRONY [[]]
- MS [[]]
- USA [[]]
RUpdated Safety Analysis Report
UTUltrasonic Testing
VdcVolts Direct Current