IR 05000263/2012002

IR 05000263-12-002, on 01/01/2012 - 03/31/2012, Monticello Nuclear Generating Plant. Maintenance Effectiveness; Operability Determinations and Functional Assessments; Occupational and Public Radiation Safety; and Follow-Up of Events

ML12109A161
Person / Time
Site:	Monticello
Issue date:	04/17/2012
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	O'Connor T Northern States Power Co
References
IR-12-002
Download: ML12109A161 (62)

Text

pril 17, 2012

SUBJECT:

MONTICELLO NUCLEAR GENERATING PLANT - NRC INTEGRATED INSPECTION REPORT 05000263/2012002

Dear Mr. OConnor:

On March 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Monticello Nuclear Generating Plant. The enclosed report documents the inspection findings, which were discussed on April 11, 2012, with Mr. Haskell and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Three NRC-identified findings and one self-revealed finding of very low safety significance were identified during this inspection.

Three of these findings were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Monticello Nuclear Generating Plant. In addition, if you disagree with a cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Monticello Nuclear Generating Plant.

T. O'Connor -2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's Agencywide Document Access and Management 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 N. Shah Acting For/

Kenneth Riemer, Branch Chief Branch 2 Division of Reactor Projects Docket No. 50-263 License No. DPR-22

Enclosure:

Inspection Report 05000263/2012002; w/Attachment: Supplemental Information

REGION III==

Docket No: 50-263 License No: DPR-22 Report No: 05000263/2012002 Licensee: Northern States Power Company, Minnesota Facility: Monticello Nuclear Generating Plant Location: Monticello, MN Dates: January 1 through March 31, 2012 Inspectors: S. Thomas, Senior Resident Inspector P. Voss, Resident Inspector M. Ziolkowski, Reactor Engineer M. Phalen, Senior Health Physicist S. Bell, Health Physicist Approved by: K. Riemer, Branch Chief Branch 2 Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000263/2012002; 01/01/2012 - 03/31/2012; Monticello Nuclear Generating Plant.

Maintenance Effectiveness; Operability Determinations and Functional Assessments;

Occupational and Public Radiation Safety; and Follow-Up of Events.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Four Green findings were identified by the inspectors. Three findings were considered to be non-cited violations (NCVs) of NRC regulations. 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 NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649,

Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a finding of very low safety significance and non-cited violation (NCV) of 10 CFR 50.65(a)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees failure to establish an a(1) action plan and associated goals when the condensate feedwater (CFW) system a(2) preventative maintenance demonstration became invalid. Specifically, in May 2011, the No. 12 CFW train exceeded its performance criteria when it experienced two maintenance preventable functional failures (MPFFs). The licensee failed to appropriately account for these failures in their Maintenance Rule Program and, as a result, the site failed to monitor the equipment under 10 CFR 50.65(a)(1) as required.

Corrective actions taken by the licensee to address this issue included performing a root cause evaluation of the sites Maintenance Rule programmatic deficiencies; performing an extent of condition which identified several other instances where MPFFs of other systems had not been accounted for; and creating an a(1) action plan for the CFW system. These issues were entered into the licensees corrective action program as CAP 01321996, CAP 01324083, and CAP 01323429.

The inspectors determined that the licensees failure to monitor the CFW system in accordance with the requirements of 10 CFR 50.65(a)(1) due to inadequately accounting for two MPFFs under 10 CFR 50.65(a)(2) was a performance deficiency, because it was the result of the failure to meet a requirement or a standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented.

The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the equipment performance attribute of the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors applied IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, to this finding. The inspectors evaluated the issue under the Initiating Events Cornerstone, and utilized Column 1 of the Table 4a worksheet to screen the finding. For transient initiators, the inspectors answered No to the question,

Does the finding contribute to both the likelihood of a reactor trip AND the likelihood that mitigation equipment or functions will not be available? and determined the finding to be of very low safety significance. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Problem Identification and Resolution, having corrective action program (CAP) components, and involving aspects associated with the licensee trending and assessing items from the CAP in the aggregate to identify programmatic and common cause problems, and communicating the results of the trending to applicable personnel P.1(b). (Section 1R12)

Green.

A finding of very low safety significance was self -revealed on November 19, 2011, when a reactor scram occurred during planned turbine-generator testing, as a result of the sites failure to effectively monitor and control turbine lube oil (TLO) tank vacuum and perform turbine shaft voltage monitoring in accordance with vendor recommendations. The mismanagement of the ability to monitor and control TLO tank vacuum led to the fouling of turbine shaft grounding braids and subsequent degradation of the turbine speed governor drive gears through electrolysis.

The degradation of the front standard components ultimately resulted in control oil pressure oscillations during speed load changer testing, which activated the load rejection pressure switches and scrammed the plant. Corrective actions taken by the licensee to address this issue included repairing the speed governor gear drive and main shaft oil pump components; installing a more robust shaft grounding strap; improving the instrumentation on the TLO tank and adjusting the control bands on the operator logs; and developing a revised testing methodology for generator electrical checks to include vendor recommendations.

The inspectors determined that the licensees failure to effectively monitor and control TLO tank vacuum and perform turbine shaft voltage monitoring in accordance with vendor recommendations was a performance deficiency because it was the result of the failure to meet a requirement or standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented.

The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the procedure adequacy attribute of the Initiating Events Cornerstones objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors applied IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, to this finding. The inspectors evaluated the issue under the Initiating Events Cornerstone, and utilized Column 1 of the Table 4a worksheet to screen the finding. For transient initiators, the inspectors answered No to the question,

Does the finding contribute to both the likelihood of a reactor trip AND the likelihood that mitigation equipment or functions will not be available? and determined the finding to be of very low safety significance. The inspectors determined that the most significant causal factor associated with the performance deficiency was associated with the cross-cutting area of Human Performance, having resources components, and involving aspects associated with procedures are available and adequate to assure nuclear safety

H.2(c). (Section 4OA3)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and non-cited violation (NCV) of 10 CFR 50.65(a)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the licensees failure to establish an a(1) action plan and associated goals when the residual heat removal (RHR) system a(2) preventative maintenance demonstration became invalid. Specifically, in June 2011, the No. 13 RHR pump exceeded its performance criteria when it experienced a second maintenance preventable functional failure (MPFF). The licensee failed to appropriately evaluate these failures in their Maintenance Rule Program and, as a result, the site failed to monitor the equipment under 10 CFR 50.65(a)(1) as required.

Corrective actions taken by the licensee to address this issue included performing a root cause evaluation of the sites Maintenance Rule programmatic deficiencies, and creating an a(1) action plan for the RHR system. The issue was entered into the licensees corrective action program as CAP 01325200.

The inspectors determined that the licensees failure to monitor the RHR system in accordance with the requirements of 10 CFR 50.65(a)(1) due to inadequately evaluating three MPFFs under 10 CFR 50.65(a)(2) was a performance deficiency, because it was the result of the failure to meet a requirement or a standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented.

The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

The inspectors applied IMC 0609, Attachment 4, to this finding. The inspectors evaluated the issue under the Mitigating Systems Cornerstone, and utilized Column 2 of the Table 4a worksheet to screen the finding. The inspectors answered No to all five questions, and determined the finding to be of very low safety significance.

The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, having work practices components, and involving aspects associated with the licensee ensuring supervisory and management oversight of work activities, such that nuclear safety is supported H.4(c). (Section 1R12)

Green.

The inspectors identified a finding of very low safety significance and violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to identify and properly evaluate a compensatory measure imbedded in an operability recommendation associated with MO-2020 [RHR Division I Drywell Spray -

Outboard] and MO-2021 [RHR Division II Drywell Spray - Outboard] in accordance with licensee procedure FP-OP-OL-01, Operability/Functionality Determination.

Specifically, the operability recommendation directed operators, upon receipt of a dual indication on MO-2020/MO-2021, to perform actions documented in an operational decision making instruction (ODMI), which were not identified or evaluated as compensatory measures, nor were they conducted in accordance with an approved procedure. Corrective actions taken by the licensee included revising the applicable operability recommendation, in part to eliminate the imbedded compensatory measure, eliminating the applicable ODMI, and preparing and implementing an Operations Manual procedure change, which provides operators instructions on actions to take if an unexpected dual indication should occur on MO-2020 or MO-2021.

The inspectors determined that the failure to identify and appropriately evaluate a compensatory measure imbedded in OPR 01323839-01 was a performance deficiency, because it was the result of the failure to meet a requirement or standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented. The inspectors screened the performance deficiency per IMC 0612,

Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted configuration control attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors applied IMC 0609, Attachment 4, Phase 1 -

Initial Screening and Characterization of Findings, to this finding. The inspectors evaluated the issue under the Mitigating Systems Cornerstone, and utilized Column 2 of the Table 4a worksheet to screen the finding. The inspectors answered No to all five questions and determined the finding to be of very low safety significance.

The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Problem Identification and Resolution, having corrective action components, and involving aspects associated with the licensee thoroughly evaluating problems such that the resolutions address the causes and extent conditions, as necessary. This includes properly evaluating for operability conditions adverse to quality P.1(c). (Section 1R15)

Licensee-Identified Violations

No violations were identified.

REPORT DETAILS

Summary of Plant Status

Monticello operated at approximately 100 percent power for the entire inspection period with the exception of minor downpowers of short duration to accomplish planned surveillances or rod pattern adjustment.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition - Heavy Snowfall Conditions

a. Inspection Scope

On February 29, 2012, a winter storm warning was issued for expected snow and ice accumulations. The inspectors observed the licensees preparations and planning for the significant winter weather potential. The inspectors reviewed licensee procedures and discussed potential compensatory measures with control room personnel.

The inspectors focused on plant managements actions for implementing the stations procedures for ensuring adequate personnel for safe plant operation and emergency response would be available. The inspectors conducted a site walkdown, including walkdowns of various plant structures and systems, to check for maintenance or other apparent deficiencies that could affect system operations during the predicted significant weather. The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures.

Specific documents reviewed during this inspection are listed in the Attachment to this report.

This inspection constituted one readiness for impending adverse weather condition sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• Division II emergency diesel generator (EDG) emergency service water (ESW)system during Division I EDG maintenance outage;

• Division I 125/250 Vdc batteries during a Division II EDG maintenance outage; and

• Division I residual heat removal (RHR) system during Division II RHR system planned maintenance.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report (USAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions.

The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable.

The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies.

The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

During the week of March 19, 2012, the inspectors performed a complete system alignment inspection of the high pressure coolant injection (HPCI) system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment.

The inspectors walked down the system to review mechanical and electrical equipment line ups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the to this report.

These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Fire Zone 32 (emergency filtration train (EFT) building second floor);

• Fire Zone 12-A (lower 4kV bus area (11, 13, & 15));

• Fire Zone 19-A and 19-B (makeup demin area and essential motor control center (MCC) area);

• Fire Zone 19-C (feedwater pipe chase); and

• Fire Zone 23 (intake structure pump room and corridor).

The inspectors reviewed areas to assess if 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 implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

These activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the 11 RHR heat exchanger to verify that potential deficiencies did not mask the licensees ability to detect degraded performance; to identify any common cause issues that had the potential to increase risk; and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria; the correlation of scheduled testing and the frequency of testing; and the impact of instrument inaccuracies on test results. Inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing conditions. Documents reviewed for this inspection are listed in the Attachment to this report.

This annual heat sink performance inspection constituted one sample as defined in IP 71111.07-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On March 19, 2012, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate; evaluators were identifying and documenting crew performance problems; and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On March 17, 2012, the inspectors observed control room operators during control rod drive (CRD) exercising and CRD withdrawal stall flow testing. Also, on March 29, 2012, the inspectors observed control room operators during reactor water cleanup (RWCU)testing. These were activities that required heightened awareness and were related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board manipulations; and

• oversight and direction from supervisors.

The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• condensate feedwater (CFW) system;

• EDG/ESW system; and

• RHR and reactor pressure relief systems.

The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the Maintenance Rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted three quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

1. Failure to Monitor Condensate Feedwater System under 50.65(a)(1) due to Inadequate

Maintenance Rule Failure Tracking Introduction The inspectors identified a finding of very low safety significance when the licensee failed to follow the requirements of 10 CFR 50.65(a)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the CFW system.

Specifically, the licensee did not properly account for two maintenance preventable functional failures (MPFFs) of the CFW system and, as a result, the licensee failed to take appropriate a(1) monitoring actions when the 10 CFR 50.65(a)(2) demonstration became invalid in May 2011.

Description During a review of the licensees maintenance rule program database and corrective action reports, which documented component failures on the CFW system over a two year period, the inspectors noted that some component failures were not accounted for in the licensees Maintenance Rule Program as MPFFs. In addition, the inspectors noted that there were several instances where system unavailability had not been accounted for. The inspectors discussed these observations with engineering personnel. The site investigated this issue and determined that two of the CFW system component failures were not appropriately counted as MPFFs. The following corrective action documents were not accounted for as MPFFs:

• On May 23, 2011, the No. 12 reactor feed pump (RFP) tripped on low suction flow due to the pumps minimum flow valve failing closed. The licensee determined that the cause of the failure was associated with contract maintenance workers failing to tighten the jam nut on the valve positioner following outage planned maintenance activities (CAP 01287286).

• On May 24, 2011, the No. 12 RFP tripped on low suction flow a second time, due to the pumps minimum flow valve failing closed. The licensee determined that the cause of this issue was associated with maintenance workers failing to tighten the jam nut on the minimum flow valve feedback linkage, following reassembly of the positioner after the initial valve failure (CAP 01287453).

In addition, the inspectors examined the performance of equipment associated with the reactor pressure relief system and the EDG/ESW system to determine whether component failures associated with those systems had been properly classified and accounted for in the licensees Maintenance Rule Program. The inspectors determined that the following MPFFs were also not correctly accounted for in the licensees program:

• On June 23, 2011, the licensee was forced by procedural administrative limits to shut down in order to repair a leaking safety relief valve (SRV). The licensee determined that the leakage condition was a result of foreign material exclusion (FME) introduced into the valve during reactor startup SRV testing.

This occurrence constituted an MPFF for the system according to the licensees Maintenance Rule Program (CAP 01291640).

• On October 21, 2011, the 11 EDG/ESW system became inoperable when the ESW supporting the EDG failed to deliver the required flow to support diesel operation during an actual demand associated with the 2R transformer lockout and reactor scram. The licensee attributed this failure to a maintenance preventable blockage condition in the ESW pump suction (CAP 01309393).

In each of the cases noted, the licensee had performed Maintenance Rule evaluations, and had determined that the events in question should be classified as MPFFs.

However, the licensee had failed to incorporate the results of these evaluations into their Maintenance Rule Program and, as a result, these events were not being considered in the a(2) demonstrations of their associated systems. As a result of the inspectors questions, the licensee performed an initial extent of condition evaluation to determine how many events that had been classified as MPFFs had not been accounted for in the sites Maintenance Rule Program. The licensee determined that there were several instances where MPFFs had not been accounted for. In addition, as a result of the inspectors questions, the licensee determined that, contrary to their Maintenance Rule Program requirements, they had not yet accounted for the impact of a scram in November 2011 on their unplanned capability loss (UCL) plant level performance criteria. Once identified, this unavailability time caused the site to exceed this plant level performance criterion. As a result, the licensee generated an a(1) plan for UCL.

During additional discussions, the inspectors noted that the licensees extent of condition had failed to identify that the October 21, 2011, EDG/ESW event had not been accounted for as an MPFF. The licensee determined it was necessary to perform an additional extent of condition evaluation to determine whether there were other instances similar to the EDG/ESW event that had been missed in the initial extent of condition evaluation. Aside from the CFW system and the UCL factor, the licensees extent of condition did not identify any other cases where unaccounted for MPFFs caused a system to exceed its performance criteria and invalidate its a(2) demonstration.

The licensee evaluated the CFW system, and determined that when the additional CFW MPFFs were considered, the system exceeded its reliability criteria in May 2011, and the 10 CFR 50.65(a)(2) conclusion became invalid. In February 2012, because system performance indicated that the system was not being effectively controlled through appropriate preventive maintenance, the sites Maintenance Rule Expert Panel classified the CFW system as (a)(1). This classification prompted the creation of an a(1) action plan, which was approved in March 2012, so that performance of the system could be monitored against established goals, as required by 10 CFR 50.65.

The licensee ultimately recognized that they needed to gain a better understanding of the full extent of the programmatic issues associated with the management of their Maintenance Rule Program. As a result, they assembled a team, and performed a root cause evaluation (RCE) in order to identify and correct the gaps that existed within their program. This RCE included evaluation of the deficiencies that led to the missed CFW, UCL, and RHR a(1) classifications.

Analysis The inspectors determined that the licensees failure to monitor the CFW system in accordance with the requirements of 10 CFR 50.65(a)(1) due to inadequately accounting for two MPFFs under 10 CFR 50.65(a)(2) was a performance deficiency, because it was the result of the failure to meet a requirement or a standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented.

The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Problem Identification and Resolution, having CAP components, and involving aspects associated with the licensee trending and assessing items from the CAP in the aggregate to identify programmatic and common cause problems, and communicating the results of the trending to applicable personnel P.1(b).

The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the equipment performance attribute of the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors applied IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, to this finding. The inspectors evaluated the issue under the Initiating Events Cornerstone, and utilized Column 1 of the Table 4a worksheet to screen the finding. For transient initiators, the inspectors answered No to the question, Does the finding contribute to both the likelihood of a reactor trip AND the likelihood that mitigation equipment or functions will not be available? and determined the finding to be of very low safety significance. (Green)

Enforcement Title 10 CFR 50.65 (a)(1), requires, in part, that holders of an operating license shall monitor the performance or condition of SSCs within the scope of the rule as defined by 10 CFR 50.65 (b), against licensee established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions.

Title 10 CFR 50.65 (a)(2) states, in part, that monitoring, as specified in 10 CFR 50.65 (a)(1), is not required where it has been demonstrated that the performance or condition of an SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended function.

Contrary to the above, on May 24, 2011, Monticello Nuclear Generating Plant (MNGP)was unable to demonstrate that the performance or condition of the CFW system had been effectively controlled through the performance of appropriate preventive maintenance, and failed to monitor the equipment against licensee-established a(1) goals. Specifically, the site failed to properly account for two MPFFs of the CFW system occurring in May 2011, which demonstrated that the performance or condition of SSCs in the CFW system was not being effectively controlled through appropriate preventive maintenance. As a result, a(1) goal setting and monitoring was required, but it was not performed until the issue was identified by the inspectors on January 24, 2012. Because the finding was of very low safety significance and has been entered into the licensees corrective action program (CAP 01321996, CAP 01324083, CAP 01323429), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000263/2012002-01; Failure to Monitor Condensate Feedwater System under 50.65(a)(1) due to Inadequate Maintenance Rule Failure Tracking)

2. Failure to Monitor Residual Heat Removal System Under 50.65(a)(1) due to Inadequate

Maintenance Rule Evaluations Introduction The inspectors identified a finding of very low safety significance when the licensee failed to follow the requirements of 10 CFR 50.65(a)(2), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the RHR system.

Specifically, the licensee did not properly evaluate three MPFFs of the RHR system, and as a result, the licensee failed to take appropriate a(1) monitoring actions when the 10 CFR 50.65(a)(2) demonstration became invalid in June 2011.

Description During a review of the licensees Maintenance Rule Program database and corrective action reports, which documented component failures on the RHR system over a two year period, the inspectors noted that some component failures were not correctly evaluated in the licensees Maintenance Rule Program as MPFFs. The inspectors discussed these observations with engineering personnel. The site investigated this issue and determined that the three RHR system component failures were not appropriately counted as MPFFs. The following corrective action documents were not accounted for as MPFFs:

• On May 27, 2011, the No. 13 RHR breaker failed to close to start the pump when operators were aligning RHR to the torus cooling mode of operation.

After troubleshooting, the licensee was unable to conclusively identify the cause of the failure, but corrective actions were taken, and the system was returned to service. However, when a later failure occurred on June 2, 2011, the licensee ultimately attributed the May 27th failure to a misaligned trip coil bracket (CAP 01288036).

• On June 2, 2011, the No. 13 RHR breaker failed to close to start the pump during testing. The licensee attributed this failure and the May 27th failure to a misaligned trip coil bracket, and they determined that the condition had not been corrected when the previous failure occurred (CAP 01289462).

• On October 22, 2011, the No. 13 RHR pump experienced a motor cooling coil failure, and as a result, the pump was declared inoperable. The licensee determined the cooling coil had failed due to corrosion/erosion, and that the site had missed opportunities to avoid the failure by incorporating internal operating experience (CAP 1309430).

In the case of the June 2, 2011, breaker failure, the licensee had performed the Maintenance Rule evaluation, and determined that the failure was an MPFF. However, the licensee had incorrectly credited that failure to the wrong system. In addition, because the failure happened one week after a similar breaker failure for the No. 13 RHR pump, the site inappropriately discussed both failures in the same evaluation and counted the failure as one MPFF, rather than two. This occurred despite the fact that after the first breaker failure, corrective action was taken, and the pump was restored to service prior to the occurrence of the second breaker failure. Prior to the second breaker failure, the licensee had not performed a Maintenance Rule evaluation for the first breaker failure. In the case of the October 22, 2011, No. 13 RHR cooling coil failure, the licensee failed to identify that a Maintenance Rule evaluation was necessary for the event. The licensee failed to recognize the need for a Maintenance Rule evaluation, despite the fact that a nearly identical failure had occurred on the No. 11 core spray pump a year earlier, and the event had resulted in an MPFF being assigned to the core spray system.

The licensee failed to adequately account for these MPFFs due to incorrectly attributing one to the wrong system, and failing to recognize that the other two failures necessitated their own Maintenance Rule evaluations. This led to a failure to incorporate three MPFFs into the licensees Maintenance Rule Program and, as a result, these events were not being considered in the a(2) demonstrations of the RHR system. Because the performance criterion for the No. 13 RHR pump was less than two MPFFs in two years, the inspectors noted that the RHR system had exceeded its performance criteria and required a(1) evaluation.

The licensee evaluated the RHR system and determined that when the additional RHR MPFFs were considered, the system exceeded its reliability performance criteria in June 2011, and the 10 CFR 50.65(a)(2) conclusion became invalid.

In February 2012, because system performance indicated that the system was not being effectively controlled through appropriate preventive maintenance, the sites Maintenance Rule Expert Panel classified the RHR system as (a)(1). This classification prompted the creation of an a(1) action plan, which was approved in March 2012, so that performance of the system could be monitored against established goals, as required by 10 CFR 50.65.

The licensee ultimately recognized that they needed to gain a better understanding of the full extent of the programmatic issues associated with the management of their Maintenance Rule Program. As a result, they assembled a team, and performed a RCE in order to identify and correct the gaps that existed within their program.

This RCE included evaluation of the deficiencies that led to the missed CFW, UCL, and RHR a(1) classifications.

Analysis The inspectors determined that the licensees failure to monitor the RHR system in accordance with the requirements of 10 CFR 50.65(a)(1) due to inadequately evaluating three MPFFs under 10 CFR 50.65(a)(2) was a performance deficiency, because it was the result of the failure to meet a requirement or a standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented.

The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Human Performance, having work practices components, and involving aspects associated with the licensee ensuring supervisory and management oversight of work activities, such that nuclear safety is supported H.4(c).

The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the equipment performance attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

The inspectors applied IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, to this finding. The inspectors evaluated the issue under the Mitigating Systems Cornerstone, and utilized Column 2 of the Table 4a worksheet to screen the finding. The inspectors answered No to all five questions and determined the finding to be of very low safety significance. (Green)

Enforcement Title 10 CFR 50.65 (a)(1), requires, in part, that holders of an operating license shall monitor the performance or condition of SSCs within the scope of the rule as defined by 10 CFR 50.65 (b), against licensee established goals, in a manner sufficient to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions.

Title 10 CFR 50.65 (a)(2) states, in part, that monitoring, as specified in 10 CFR 50.65 (a)(1), is not required where it has been demonstrated that the performance or condition of an SSC is being effectively controlled through the performance of appropriate preventive maintenance, such that the SSC remains capable of performing its intended function.

Contrary to the above, on June 2, 2011, MNGP was unable to demonstrate that the performance or condition of the RHR system had been effectively controlled through the performance of appropriate preventive maintenance, and failed to monitor the equipment against licensee-established a(1) goals. Specifically, the site failed to properly evaluate three MPFFs of the RHR system occurring in May, June, and October 2011, which demonstrated that performance or condition of SSCs in the RHR system was not being effectively controlled through appropriate preventive maintenance. As a result, a(1) goal setting and monitoring was required, but it was not performed until the issue was identified by the inspectors in February 2012. Because the finding was of very low safety significance and has been entered into the licensees corrective action program (CAP 01325200), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000263/2012002-02; Failure to Monitor Residual Heat Removal System under 50.65(a)(1) due to Inadequate Maintenance Rule Evaluations)

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• V-AC-4 (B RHR room air cooling unit) cooling coil replacement;

• EFT train 'A' unplanned limiting condition for operation (LCO) entry;

• main turbine and RFP high level trip unplanned LCO entry; and

• HPCI maintenance window yellow risk.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

These maintenance risk assessments and emergent work control activities constituted four samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• B EFT emergency filter fan motor and CRV Division II exhaust recirc fan motor greased motor windings;

• V-AC-4 (B RHR room cooling unit) cooling coil leak;

• RHR/ low pressure coolant injection (LPCI) relays found without required seismic restraints;

• B core spray pump affected by minimum TS frequency;

• MO 2020/2021 dual indicationprimary containment isolation valve (PCIV) post accident monitoring; and

• Monticello susceptibility to degraded voltage and under voltage conditions identified by January 30, 2012, event at the Byron Station.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and USAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

This inspection constituted six operability samples as defined in IP 71111.15-05.

1. Inadequate Evaluation of Compensatory Measure

Introduction The inspectors identified a finding of very low safety significance and violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to identify and properly evaluate a compensatory measure imbedded in an operability recommendation (OPR) associated with MO-2020 [RHR Division I Drywell Spray - Outboard] and MO-2021 [RHR Division II Drywell Spray - Outboard] in accordance with licensee procedure FP-OP-OL-01, Operability/Functionality Determination. Specifically, the OPR directed operators, upon receipt of a dual indication on MO-2020/MO-2021, to perform actions documented in an operational decision making instruction (ODMI), which were not identified or evaluated as compensatory measures, nor were they conducted in accordance with an approved procedure.

Description The licensee identified a condition in which, during the performance of certain plant evolutions, the control room panel position indicating lights for MO-2021 would change from closed indication to dual indication. Since the light indication is relied upon to provide positive verification of the local valve position to meet the requirements of TS 3.6.1.8, Residual Heat Removal (RHR) Drywell Spray, and TS 3.3.3.1, Post Accident Monitoring (PAM) Instrumentation, the ability of the SSC to perform its specified safety function was challenged. On February 6, 2012, following the most recent occurrence of the dual indication for MO-2021, the licensee entered the applicable TS actions and implemented appropriate actions to clear the dual indication.

The licensee entered the issue into their corrective action program as CAP 01323839 on February 6, 2012. An OPR to evaluate the condition of MO-2020 and MO-2021 was a specific action documented in CAP 01323839. The licensee also prepared a Type I operational decision making evaluation checklist to aid in their evaluation of this issue.

The OPR identified that, in 2009, engineering change (EC) 12361 was performed on MO-2020/2021. This EC modified both valves to remove the seal-in feature of the control logic so the valves could be throttled in both the open and closed directions.

The EC also maintained the automatic torque switch bypass feature during safety function initiation via jumpers landed between the torque switch circuit and the closed light indication circuit. One byproduct of this configuration was that any time the remote operating hand switches for MO-2020/2021 were in the AUTO position and the torque switch contacts for the valve were closed, the open (red) position indicating light illuminated. Following manual operation to close MO-2020/2021 using the remote hand switch, the torque switch contacts are normally open, resulting in only the closed (green)position indicating. The licensee determined that the periodic dual indication condition being experienced for MO-2021 was due to the control circuit electrical configuration introduced by EC 12361, combined with the occasional slight relaxation of the valves operating gear train causing the torque switch contacts to close. Past practice by the licensee of taking the remote hand switch for MO-2021 in the closed direction, when the dual indication condition was present, had been successful in eliminating the gear train relaxation, opening the torque switch contacts, and extinguishing the open (red)indicating light.

The inspectors reviewed OPR 01323839-01, Revision 0. During this review, the inspectors noted that the licensee had included a statement within the body of the OPR that said, ODMI Type I (AR 1323839) will provide the necessary guidance to operations in the event dual indication is received. The ODMI stated, in part, that the final decision was to provide interim guidance to the duty crew that, should dual indication appear, then an attempt should be made to check the valve closed using the hand switch 10A-S9A/B, and if the condition does not clear using the hand switch and dual indication remains, then the duty crew should evaluate TS actions for PCIV and PAM indication. The inspectors noted that since the action of taking the hand switch 10A-S9A/B to the closed position was key to restoring the operability of the PAM function, and important to supporting the reasonable assurance of operability of the containment isolation function of MO-2021 once the dual indication condition existed.

As a result, the inspectors considered this action to be a compensatory measure that had not been identified nor appropriately analyzed as such. The inspectors communicated their concerns to licensee management. In response to the inspectors concerns, the licensee revised OPR 01323839-01, in part to eliminate the imbedded compensatory measure; eliminated the applicable ODMI associated with this issue; and prepared and implemented an Operations Manual procedure change for the RHR system. Abnormal Procedure B.03.04-05.H.11, Response to Dual Indication on MO-2020 or MO-2021, provides operators with instructions on actions to take if an unexpected dual indication should occur on MO-2020 or MO-2021.

Analysis The inspectors determined that the failure to identify and appropriately evaluate a compensatory measure imbedded in OPR 01323839-01 was a performance deficiency, because it was the result of the failure to meet a requirement or standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented. The inspectors determined that the contributing cause that provided the most insight into the performance deficiency was associated with the cross-cutting area of Problem Identification and Resolution, having corrective action components, and involving aspects associated with the licensee thoroughly evaluating problems such that the resolutions address the causes and extent conditions, as necessary. This includes properly evaluating for operability conditions adverse to quality P.1(c).

The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted configuration control attribute of the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

The inspectors applied IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, to this finding. The inspectors evaluated the issue under the Mitigating Systems Cornerstone, and utilized Column 2 of the Table 4a worksheet to screen the finding. The inspectors answered No to all five questions and determined the finding to be of very low safety significance. (Green)

Enforcement Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to this requirement, the licensee failed to adequately perform Step 5.5.7 of Procedure FP-OP-OL-01, Operability/Functionality Determination, a procedure affecting quality. Specifically, on February 14, 2012, the licensee failed to identify and properly evaluate a compensatory measure imbedded in an OPR associated with MO-2020 [RHR Division I Drywell Spray - Outboard] and MO-2021 [RHR Division II Drywell Spray - Outboard] in accordance with their procedure. Because the finding was of very low safety significance and has been entered into the licensees corrective action program (CAP 01327217) this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000263/2012002-03; Inadequate Evaluation of Compensatory Measure)

2. Monticello Susceptibility to Degraded Voltage and Under Voltage Conditions Identified

by January 30, 2012, Event at the Byron Station The licensees position, as documented in OPR 01325199-01 is as follows. The failure of phase C insulator at Byron Station that resulted in an open circuit condition caused an imbalanced voltage condition at their essential buses. At both Byron Station and MNGP, neither the degraded bus voltage nor the loss of voltage logic was designed to provide isolation due to an open phase connection resulting from a component failure.

The degraded voltage logic is designed to monitor voltage at the 4kV essential buses to ensure that when connected to the offsite source, the voltage is adequate to provide for proper operation of safety-related components. The design and licensing bases requirements do not require analysis of imbalanced voltage conditions resulting from equipment or component failures. Therefore, the degraded voltage relaying scheme is capable of responding to degraded grid conditions as described in the Monticello TS 3.3.8.1, Amendment 147, LOP Instrumentation. Also, in conclusion, the licensee documented the following, The degraded voltage relays and loss of voltage relays are operable. The vulnerability is not considered to impact the operability of the specified design basis automatic functions of the various relays described in Technical Specification 3.3.8.1 (Loss of Power Instrumentation) and in accordance with applicable design requirements. The NRC inspectors plan to further review the licensees position that the condition is not required to be evaluated by their licensing and design basis.

Since this evaluation will require additional review by subject matter experts located at both the Regional Office and Headquarters, this issue will be treated as an Unresolved Item (URI). (URI 5000263/2012002-04; Monticello Susceptibility to Degraded Voltage and Under Voltage Conditions Identified by January 30, 2012, Event at the Byron Station)

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification:

• EC 19350 (RHR shutdown cooling suction line pressure relief).

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the USAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed in the course of this inspection are listed in the Attachment to this report.

This inspection constituted one permanent plant modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance (PM) activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• PM testing for secondary containment isolation dampers VD-11 and VD-12;

• PM testing for RHR pump No. 12 following breaker maintenance;

• residual heat removal service water (RHRSW) No. 14 maintenance window;

• main turbine RFP high level trip unit replacement;

• plant protection system relay replacements; and

• reactor manual control system relay replacements.

These activities were selected based upon the SSCs ability to impact risk.

The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with PM tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted six PM testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• 11 EDG/11 ESW quarterly pump and valve tests (inservice test (IST));

• safeguard bus voltage protection relay unit functional test (routine);

• main steam line high flow group I instrument test (routine);

• core spray header differential pressure test and calibration (routine); and

• reactor high pressure scram instrument and calibration (routine).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the USAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for IST activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers (ASME) code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted four routine surveillance testing samples, and one IST inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on March 14, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities.

The inspectors observed emergency response operations in the emergency operations facility and control room simulator to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

This inspection constituted one complete sample as defined in IP 71124.01 05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed all licensee performance indicators (PIs) for the Occupational Exposure Cornerstone for follow-up. The inspectors reviewed the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits). The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed the results of the audit and operational report reviews to gain insights into overall licensee performance.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors determined if there have been changes to plant operations since the last inspection that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether the licensee assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last two radiological surveys from selected plant areas and evaluated whether the thoroughness and frequency of the surveys where appropriate for the given radiological hazard.

The inspectors conducted walkdowns of the facility, including radioactive waste processing, storage, and handling areas to evaluate material conditions and performed independent radiation measurements to verify conditions.

The inspectors selected the following radiologically risk-significant work activities that involved exposure to radiation.

• steam dryer disposal preparations;

• RWCU system maintenance; and

• routine radiation safety.

For these work activities, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were properly identified, including the following:

• identification of hot particles;

• the presence of alpha emitters;

• the potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials (This evaluation may include licensee planned entry into non-routinely entered areas subject to previous contamination from failed fuel.);

• the hazards associated with work activities that could suddenly and severely increase radiological conditions and that the licensee has established a means to inform workers of changes that could significantly impact their occupational dose; and

• severe radiation field dose gradients that can result in non-uniform exposures of the body.

The inspectors observed work in potential airborne areas and evaluated whether the air samples were representative of the breathing air zone. The inspectors evaluated whether continuous air monitors were located in areas with low background to minimize false alarms and were representative of actual work areas. The inspectors evaluated the licensees program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

b. Findings

No findings were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors selected various containers holding non-exempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and assessed whether the containers were labeled and controlled in accordance with 10 CFR 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g), Exemptions To Labeling Requirements.

The inspectors reviewed the following radiation work permits used to access high radiation areas and evaluated the specified work control instructions or control barriers.

• steam dryer disposal preparations;

• RWCU system maintenance; and

• routine radiation safety.

For these radiation work permits, the inspectors assessed whether allowable stay times or permissible dose (including from the intake of radioactive material) for radiologically significant work under each radiation work permit were clearly identified. The inspectors evaluated whether electronic personal dosimeter alarm set-points were in conformance with survey indications and plant policy.

The inspectors reviewed selected occurrences where a workers electronic personal dosimeter noticeably malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately to the off-normal condition. The inspectors assessed whether the issue was included in the CAP and dose evaluations were conducted as appropriate.

For work activities that could suddenly and severely increase radiological conditions, the inspectors assessed the licensees means to inform workers of changes that could significantly impact their occupational dose.

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors potentially contaminated material leaving the radiological control area, and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use, and evaluated whether the work was performed in accordance with plant procedures and whether the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site. The inspectors assessed whether the radiation monitoring instrumentation had appropriate sensitivity for the type(s) of radiation present.

The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was guidance on how to respond to an alarm that indicates the presence of licensed radioactive material.

The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters. The inspectors assessed whether or not the licensee has established a de facto release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high-radiation background area.

The inspectors selected several sealed sources from the licensees inventory records and assessed whether the sources were accounted for and verified to be intact.

The inspectors evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels) during tours of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, radiation work permits, and worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of electronic personal dosimeters in high noise areas as high radiation area monitoring devices.

The inspectors assessed whether radiation monitoring devices were placed on the individuals body consistent with licensee procedures. The inspectors assessed whether the dosimeter was placed in the location of highest expected dose or that the licensee properly employed an NRC-approved method of determining effective dose equivalent.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients.

The inspectors reviewed the following radiation work permits for work within airborne radioactivity areas with the potential for individual worker internal exposures.

• steam dryer disposal preparations;

• RWCU system maintenance; and

• routine radiation safety.

For these radiation work permits, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding; grit blasting; system breaches; entry into tanks, cubicles, and reactor cavities).

The inspectors assessed barrier (e.g., tent or glove box) integrity and temporary high-efficiency particulate air ventilation system operation.

The inspectors examined the licensees physical and programmatic controls for highly activated or contaminated materials (nonfuel) stored within spent fuel and other storage pools. The inspectors assessed whether appropriate controls (i.e., administrative and physical controls) were in place to preclude inadvertent removal of these materials from the pool.

The inspectors examined the posting and physical controls for selected high radiation areas and very-high radiation areas to verify conformance with the Occupational PI.

b. Findings

No findings were identified.

.6 Risk-Significant High Radiation Area and Very-High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors discussed with the radiation protection manager the controls and procedures for high-risk high radiation areas and very-high radiation areas.

The inspectors discussed methods employed by the licensee to provide stricter control of very-high radiation area access as specified in 10 CFR 20.1602, Control of Access to Very-High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and Very-High Radiation Areas of Nuclear Plants. The inspectors assessed whether any changes to licensee procedures substantially reduce the effectiveness and level of worker protection.

The inspectors discussed the controls in place for special areas that have the potential to become very-high radiation areas during certain plant operations with first-line health physics supervisors (or equivalent positions having backshift health physics oversight authority). The inspectors assessed whether these plant operations require communication beforehand with the health physics group, so as to allow corresponding timely actions to properly post, control, and monitor the radiation hazards including re-access authorization.

The inspectors evaluated licensee controls for very-high radiation areas and areas with the potential to become a very-high radiation area to ensure that an individual was not able to gain unauthorized access to the very-high radiation area.

b. Findings

No findings were identified.

.7 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors assessed whether workers were aware of the radiological conditions in their workplace and the radiation work permit controls/limits in place, and whether their performance reflected the level of radiological hazards present.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. The inspectors discussed with the radiation protection manager any problems with the corrective actions planned or taken.

b. Findings

No findings were identified.

.8 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

The inspectors observed the performance of the radiation protection technicians with respect to all radiation protection work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace and the radiation work permit controls/limits, and whether their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be radiation protection technician error. The inspectors evaluated whether there was an observable pattern traceable to a similar cause.

The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

b. Findings

No findings were identified.

.9 Problem Identification and Resolution (02.09)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring and exposure controls.

The inspectors assessed the licensees process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

This inspection constituted one complete sample as defined in IP 71124.05-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the plant FSAR to identify radiation instruments associated with monitoring area radiological conditions including airborne radioactivity, process streams, effluents, materials/articles, and workers. Additionally, the inspectors reviewed the instrumentation and the associated TS requirements for post-accident monitoring instrumentation including instruments used for remote emergency assessment.

The inspectors reviewed a listing of in-service survey instrumentation including air samplers and small article monitors, along with instruments used to detect and analyze workers external contamination. Additionally, the inspectors reviewed personnel contamination monitors and portal monitors, including whole-body counters, to detect workers internal contamination. The inspectors reviewed this list to assess whether an adequate number and type of instruments were available to support operations.

The inspectors reviewed licensee and third-party evaluation reports of the radiation monitoring program since the last inspection. These reports were reviewed for insights into the licensees program and to aid in selecting areas for review (smart sampling).

The inspectors reviewed procedures that govern instrument source checks and calibrations, focusing on instruments used for monitoring transient high radiological conditions, including instruments used for underwater surveys. The inspectors reviewed the calibration and source check procedures for adequacy and as an aid to smart sampling.

The inspectors reviewed the area radiation monitor alarm set-point values and set-point bases as provided in the TSs and the FSAR.

The inspectors reviewed effluent monitor alarm set-point bases and the calculational methods provided in the offsite dose calculation manual.

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors walked down effluent radiation monitoring systems, including at least one liquid and one airborne system. Focus was placed on flow measurement devices and all accessible point-of-discharge liquid and gaseous effluent monitors of the selected systems. The inspectors assessed whether the effluent/process monitor configurations aligned with offsite dose calculation manual descriptions and observed monitors for degradation and out-of-service tags.

The inspectors selected portable survey instruments that were in use or available for issuance and assessed calibration and source check stickers for currency as well as instrument material condition and operability.

The inspectors observed licensee staff performance as the staff demonstrated source checks for various types of portable survey instruments. The inspectors assessed whether high-range instruments were source checked on all appropriate scales.

The inspectors walked down area radiation monitors and continuous air monitors to determine whether they were appropriately positioned relative to the radiation sources or areas they were intended to monitor. Selectively, the inspectors compared monitor response (via local or remote control room indications) with actual area conditions for consistency.

The inspectors selected personnel contamination monitors, portal monitors, and small article monitors and evaluated whether the periodic source checks were performed in accordance with the manufacturers recommendations and licensee procedures.

b. Findings

No findings were identified.

.3 Calibration and Testing Program (02.03)

Process and Effluent Monitors

a. Inspection Scope

The inspectors selected effluent monitor instruments (such as gaseous and liquid) and evaluated whether channel calibration and functional tests were performed consistent with radiological effluent TSs/offsite dose calculation manual. The inspectors assessed whether:

(a) the licensee calibrated its monitors with National Institute of Standards and Technology traceable sources;

(b) the primary calibrations adequately represented the plant nuclide mix;

(c) when secondary calibration sources were used, the sources were verified by the primary calibration; and

(d) the licensees channel calibrations encompassed the instruments alarm set-points.

The inspectors assessed whether the effluent monitor alarm set-points were established as provided in the offsite dose calculation manual and station procedures.

For changes to effluent monitor set-points, the inspectors evaluated the basis for changes to ensure that an adequate justification existed.

b. Findings

No findings were identified.

Laboratory Instrumentation

a. Inspection Scope

The inspectors assessed laboratory analytical instruments used for radiological analyses to determine whether daily performance checks and calibration data indicated that the frequency of the calibrations was adequate and there were no indications of degraded instrument performance.

The inspectors assessed whether appropriate corrective actions were implemented in response to indications of degraded instrument performance.

b. Findings

No findings were identified.

Whole Body Counter

a. Inspection Scope

The inspectors reviewed the methods and sources used to perform whole body count functional checks before daily use of the instrument and assessed whether check sources were appropriate and aligned with the plants isotopic mix.

The inspectors reviewed whole body count calibration records since the last inspection and evaluated whether calibration sources were representative of the plant source term and that appropriate calibration phantoms were used. The inspectors looked for anomalous results or other indications of instrument performance problems.

b. Findings

No findings were identified.

Post-Accident Monitoring Instrumentation

a. Inspection Scope

Inspectors selected containment high-range monitors and reviewed the calibration documentation since the last inspection.

The inspectors assessed whether an electronic calibration was completed for all range decades above 10 rem/hour, and whether at least one decade at or below 10 rem/hour was calibrated using an appropriate radiation source.

The inspectors assessed whether calibration acceptance criteria were reasonable, accounted for the large measuring range and the intended purpose of the instruments.

The inspectors selected two effluent/process monitors that were relied on by the licensee in its emergency operating procedures as a basis for triggering emergency action levels and subsequent emergency classifications, or to make protective action recommendations during an accident. The inspectors evaluated the calibration and availability of these instruments.

The inspectors reviewed the licensees capability to collect high-range, post-accident iodine effluent samples.

As available, the inspectors observed electronic and radiation calibration of these instruments to assess conformity with the licensees calibration and test protocols.

b. Findings

No findings were identified.

Portal Monitors, Personnel Contamination Monitors, and Small Article Monitors

a. Inspection Scope

For each type of these instruments used onsite, the inspectors assessed whether the alarm set-point values were reasonable under the circumstances to ensure that licensed material is not released from the site.

The inspectors reviewed the calibration documentation for each instrument selected and discussed the calibration methods with the licensee to determine consistency with the manufacturers recommendations.

b. Findings

No findings were identified.

Portable Survey Instruments, Area Radiation Monitors, Electronic Dosimetry, and Air Samplers/Continuous Air Monitors

a. Inspection Scope

The inspectors reviewed calibration documentation for at least one of each type of instrument. For portable survey instruments and area radiation monitors, the inspectors reviewed detector measurement geometry and calibration methods and had the licensee demonstrate use of its instrument calibrator as applicable. The inspectors conducted comparison of instrument readings versus an NRC survey instrument, if problems were suspected.

As available, the inspectors selected portable survey instruments that did not meet acceptance criteria during calibration or source checks to assess whether the licensee had taken appropriate corrective action for instruments found significantly out of calibration (greater than 50 percent). The inspectors evaluated whether the licensee had evaluated the possible consequences of instrument use since the last successful calibration or source check.

b. Findings

No findings were identified.

Instrument Calibrator

a. Inspection Scope

As applicable, the inspectors reviewed the current output values for the licensees portable survey and area radiation monitor instrument calibrator unit(s). The inspectors assessed whether the licensee periodically measures calibrator output over the range of the instruments used through measurements by ion chamber/electrometer.

The inspectors assessed whether the measuring devices had been calibrated by a facility using National Institute of Standards and Technology traceable sources and whether corrective factors for these measuring devices were properly applied by the licensee in its output verification.

b. Findings

No findings were identified.

Calibration and Check Sources

a. Inspection Scope

The inspectors reviewed the licensees 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, source term to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

b. Findings

Introduction A URI was identified by the inspectors because additional information was needed to assess the licensees program for ensuring proper calibration practices and detection capability when evaluating for low energy beta emitters.

Description The inspectors reviewed the licensees procedures, surveillance records, and calibration protocol for performing leak tests on sealed radioactive sources. Specifically, the inspectors needed more information in reference to the detection efficiency determination regarding the licensees use of an automatic low background alpha/beta counting system (Tennelec 5XLB). The licensee provided the inspectors with some additional information. However, the inspectors have not completed their review of the licensees program for determining low energy beta emitting sealed source integrity.

(URI 05000263/2012002-05; Radiation Detection Equipment Calibration Protocol for Low Energy Beta Emitters)

.4 Problem Identification and Resolution (02.04)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees CAP. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring instrumentation.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours PI for the period from the 1st Quarter 2011 through the 4th Quarter 2011.

To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for this time period to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

This inspection constituted one unplanned scrams per 7000 critical hours sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI for the period from the 1st Quarter 2011 through the 4th Quarter 2011.

To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used.

The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for this time period to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

This inspection constituted one unplanned scrams with complications sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Transients per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients per 7000 Critical Hours PI for the period from the 1st Quarter 2011 through the 4th Quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports and NRC Integrated Inspection Reports for this time period to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

This inspection constituted one unplanned transients per 7000 critical hours sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Selected Issue Follow-Up Inspection: Monticello Nuclear Generating Plant Degraded

Voltage Relay Scheme Susceptibility to Loss of a Single Phase Condition

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting the licensees initial response and evaluation to an event which occurred at the Byron Station. Specifically, on January 30, 2012, the Byron Station, Unit 2, experienced an automatic reactor trip from full power because of an undervoltage condition on two 6.9kV electrical buses that power reactor coolant pumps B and C. It was determined that the undervoltage on the C phase was due to an open condition caused by a insulator stack at the station auxiliary transformer metering transformer breaking apart and falling to the ground. This open phase created an undervoltage condition in which, due to how the line voltage was monitored and control logic was satisfied, there was adequate voltage still present on monitored phases to inhibit the actuation of undervoltage relays. The inspectors evaluated the timeliness and adequacy of the licensees initial response to this issue, including determining if the same vulnerability existed at Monticello.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Follow-Up Inspection: Nonconforming Condition Associated with

Remote Position Indication for MO-2020 and MO-2021

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting an issue where the operators received dual indication on a containment isolation valve (CIV) during performance of a test procedure.

Specifically, during performance of the RHR Loop B quarterly pump and valve test on February 6, 2012, the operators noted dual indication on the outboard RHR B containment spray valve, MO-2021, following the start of the 12 RHR pump and the subsequent opening of the torus cooling injection isolation valves. Following receipt of the dual indication, the operators evaluated and entered TS action statements for the containment isolation, containment spray, and PAM functions of the CIV. Further evaluation revealed that the dual indication deficiency was the result of a modification made by the licensee in 2009 to allow throttling of both A and B division outboard containment spray CIVs.

The licensee determined that the dual indication was the result of a nonconforming condition that existed in the position indication logic for the valve, and that the condition did not adversely affect the valves ability to perform its containment isolation and containment spray functions. However, the condition resulted in periodic inaccurate CIV indications on the valve, and when present, this represented a loss of PAM indication for the valve. The inspectors observed the immediate licensee actions to address the dual indication when it was received in the control room. In addition, the inspectors reviewed the licensees intermediate and long-term actions to address the nonconforming condition. The inspectors also reviewed previous licensee evaluations of the logic issue, as well as previous opportunities the licensee had to take action to address the nonconforming condition. The inspectors determined that although the actions to address the issue when it was originally identified were not timely, the licensee ultimately recognized that additional action was necessary, and that opportunities for previous action were not fully utilized. The inspectors determined that this did not represent a violation of NRC requirements.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

No findings were identified.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report (LER) 05000263/2011-006-01: Intake Structure Fire

Suppression System Blockage This event, which occurred on September 2, 2011, involved the licensees discovery of a blockage condition within the fire protection sprinkler system piping in the plant intake structure. On August 26, 2011, during the performance of Surveillance Test 0323-01, Fire Protection System Sprinkler Functional Tests, the licensee found blockage at valve FP-171-10, an inspector test valve located at the most remote end of the intake structure sprinkler system. The blockage condition rendered the sprinkler system incapable of passing flow to portions of the intake structure, which contained safety-related RHRSW pumps used for response to and mitigation of accidents.

This revision of the LER clarified a statement in the Previous Similar Events section of the original LER. Specifically, this revision clarified that the blockage found during a PM test in 2009 was not cleared locally when it was found. Instead, in 2009, the site determined erroneously that, because no sprinkler heads were located downstream of the blockage, the sprinkler system remained functional. The site failed to consider the extent of the blockage that existed upstream of the visible blockage, and the effect of the condition on the upstream sprinklers. This performance deficiency resulted in a licensee-identified NCV documented in the Special Inspection Team Report associated with this event.

Additional information on this event was documented in Special Inspection Report 05000263/2011010, and Integrated Inspection Report 05000263/2011005.

Documents reviewed as part of this inspection are listed in the Attachment to this report.

This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

.2 (Closed) Licensee Event Report (LER) 05000263/2011-007-01: Both Emergency Diesel

Generators Declared Inoperable Due to Inadequate Surveillance This event, which occurred on September 29, 2011, involved the licensees discovery that they had been inadequately demonstrating that both EDGs could meet the surveillance requirement for load rejection capability. As a result, the licensee declared both the 11 and 12 EDGs inoperable and entered the applicable LCO action statements.

The licensee requested and was granted a Notice of Enforcement Discretion (NOED) to allow the site time to develop a new procedure that met the design requirements and perform the required EDG testing. The licensee submitted Revision 1 to this LER to correct the omission of not also reporting the event under 10 CFR 50.73(a)(2)(vii),

Common Cause Inoperability of Independent Trains or Channels. This issue was identified and evaluated by the inspectors and documented in Section 4OA3 of Integrated Inspection Report 05000263/2011005. Documents reviewed as part of this inspection are listed in the Attachment to this report. This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

.3 (Closed) Licensee Event Reports (LERs) 05000263-2011-008-00 and

05000263-2011-008-01: Reactor Scram Due to Loss of Normal Offsite Power The inspectors reviewed the plants response to a reactor scram caused by the loss of the normal offsite power supply. At 12:50 on October 21, 2011, a 2R transformer lockout occurred, causing off-site power to automatically transfer to the 1R auxiliary transformer, ultimately resulting in a reactor scram. The cause of the 2R transformer lockout was determined to be a fault to ground on an A phase conductor, which supplies power from 2RS transformer to 2R transformer. Subsequent testing of the faulted cable revealed that the cables insulation suffered from environmental and age-related degradation. Corrective actions taken by the licensee to address the cause of this event included the replacement of the 2RS to 2R feeder cables, and employing a new 2RS to 2R feeder cable route designed to avoid submergence of the cables in water.

This event was evaluated in detail by the inspectors during the fourth quarter of 2011.

The results of these inspections were documented in Section 1R20.1, Section 4OA3.1, and Section 4OA7 of Integrated Inspection Report 05000263/2011005. Documents reviewed as part of this inspection are listed in the Attachment to this report. This LER is closed.

On February 8, 2012, the licensee submitted Revision 1 to LER 05000263-2011-008-00.

The purpose of the revision was primarily to provide additional detail to the event description section of the LER. After reviewing the revision, the inspectors determined that the additional material did not impact the inspectors original assessment of the event. Licensee Event Report 05000263-2011-008-01 is closed.

This event follow-up review constituted two samples as defined in IP 71153-05.

.4 (Closed) Licensee Event Reports (LERs) 05000263-2011-009-00 and

05000263-2011-009-01: Automatic Reactor Scram While Performing Turbine-generator Testing The inspectors reviewed the licensees evaluation of a reactor scram which occurred during planned turbine-generator testing at approximately 23:12 on November 19, 2011.

One self-revealed finding of very low safety significance associated with this review is discussed below. The licensees initial response to this event was evaluated in detail by the inspectors during the fourth quarter of 2011. The results of these inspections were documented in Section 1R20.2 and Section 4OA3.2 of Integrated Inspection Report 05000263/2011005. This LER is closed.

The license submitted Revision 1 to this LER, which included information gained through the completion of their RCE and documented specific corrective actions taken by the licensee to address the issues that were identified in the RCE. Documents reviewed as part of this inspection are listed in the Attachment to this report. This LER is closed.

This event follow-up review constituted two samples as defined in IP 71153-05.

Introduction A finding of very low safety significance was self -revealed on November 19, 2011, when a reactor scram occurred during planned turbine-generator testing, as a result of the sites failure to effectively monitor and control turbine lube oil (TLO) tank vacuum and perform turbine shaft voltage monitoring in accordance with vendor recommendations.

The mismanagement of the ability to monitor and control TLO tank vacuum led to the fouling of turbine shaft grounding braids and subsequent degradation of the turbine speed governor drive gears through electrolysis. The degradation of the front standard components ultimately resulted in control oil pressure oscillations during speed load changer testing, which activated the load rejection pressure switches and scrammed the plant.

Description During the performance of a scheduled turbine-generator quarterly surveillance, an unplanned reactor scram occurred. To better understand the cause of the unexpected scram, the licensee performed a RCE (CAP 01313997). The cause of the scram was determined to be the actuation of the main turbine acceleration relay (load rejection)pressure switches. Following initial investigations, the licensee replaced a degraded component in the turbine control system that was designed to dampen normal pressure oscillations in the turbine control oil. Ultimately, the troubleshooting team determined that the cause of the oil pressure fluctuations sensed by the pressure switches was damage caused by electrolysis to gears and bearings located in the turbine front standard.

The licensees RCE determined that the root cause of the event was the ineffective management of TLO tank vacuum. This mismanagement resulted from operator round sheets having inappropriate control bands for lube oil tank vacuum. In addition, the calibration bands and instrument accuracy for instruments used to monitor TLO tank vacuum were insufficient to allow operators to accurately assess the condition of the TLO tank. Operating with insufficient TLO tank vacuum resulted in oil and oil vapor from the C shaft coupling enclosure oil deflector to build up on the turbine shaft, resulting in fouling of the shaft grounding braids. Oil and oil mist combined with dust and dirt increased the contact resistance between the shaft and the shaft grounding device, which degraded the devices effectiveness. The degradation of the grounding device ultimately led to development of circulating currents across the shaft, produced by applied shaft voltages during normal turbine generator operation (normally significantly mitigated by the grounding braids). These circulating currents were transmitted to the gears and bearings in the front standard, which caused accelerated electrical corrosion of the components (electrolysis), and ultimately, the November 19, 2011, reactor scram.

Corrective actions taken by the licensee to address this issue included repair of the speed governor gear drive and main shaft oil pump components, installation of a more robust shaft grounding strap, improving the instrumentation on the TLO tank and adjusting the control bands on the operator logs, and developing a revised testing methodology for generator electrical checks to include vendor recommendations.

Analysis The inspectors determined that the licensees failure to effectively monitor and control TLO tank vacuum and perform turbine shaft voltage monitoring in accordance with vendor recommendations was a performance deficiency because it was the result of the failure to meet a requirement or standard; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented.

The inspectors determined that the most significant causal factor associated with the performance deficiency was associated with the cross-cutting area of Human Performance, having resources components, and involving aspects associated with procedures are available and adequate to assure nuclear safety H.2(c).

The inspectors screened the performance deficiency per IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because it impacted the procedure adequacy attribute of the Initiating Events Cornerstones objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

The inspectors applied IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, to this finding. The inspectors evaluated the issue under the Initiating Events Cornerstone, and utilized Column 1 of the Table 4a worksheet to screen the finding. For transient initiators, the inspectors answered No to the question, Does the finding contribute to both the likelihood of a reactor trip AND the likelihood that mitigation equipment or functions will not be available? and determined the finding to be of very low safety significance.

Enforcement The inspectors concluded that no violation of NRC requirements occurred. The licensee entered this finding into their corrective action program (CAP 01313997) and implemented several corrective actions to address the issue. This was considered a finding of very low safety significance. (FIN 05000263/2012002-06; Ineffective Management of Turbine Lube Oil Tank Vacuum Resulting in Fouling of Grounding Braids)

.5 (Closed) Licensee Event Report (LER) 05000263-2011-010-00: Rod Worth Minimizer

Bypassed During Startup The inspectors evaluated an event involving a human performance issue which resulted in the rod worth minimizer (RWM) being inoperable in a Mode of operation where it was required to be operable. On November 27, 2011, the operating crew was making preparations for starting up the reactor. At approximately 16:57, Mode 2 was entered when the Mode switch was taken to STARTUP. As part of their normal startup testing, the operators commenced Procedure 0212, Rod Worth Minimizer Operability Test.

The general purpose of this test is to ensure that the RWM is capable of monitoring the selection and movement of control rods and inserting withdrawal blocks and/or select errors when control rods are selected and/or attempted to be withdrawn out of sequence. Step 7 of Procedure 0212 directs the operator to WITHDRAW the first permissible rod to Position 02. Step 8 of the procedure directs the operator to Attempt to withdraw the first rod in the next group in the sequence. While attempting to withdraw the control rod per Step 8, the operator noted that the control rod began to step out. Since no control rod movement was expected, the operator immediately stopped withdrawing the control rod. The crew promptly restored the second control rod to the full in position and identified that the RWM Mode switch was not in the correct position to support Mode 2 operation (BYPASS vs. OPERATE). Because the crew was unaware of the configuration of the RWM switch, they did not have the dedicated operator and necessary controls that would normally need to be in place if the plant was starting up with the RWM inoperable, as required by TS 3.3.2.1, Action C. Subsequent to restoring the RWM Mode switch to operate, the crew successfully completed the 0212 procedure.

The preliminary investigation revealed that the plant was properly configured for startup on November 26, 2011, but in response to an emergent equipment issue with the RWCU system, the operators changed the Mode switch from REFUEL to SHUTDOWN.

To support startup on November 27, 2011, the operating crew performed Procedure 0074, Control Rod Drive Exercise, but failed to return the RWM Mode switch to Operate, as required by Step 29 of the procedure. The failure to complete the 0074 procedure and the incorrect configuration of RWM Mode switch for Mode 2 operation, were not identified by the crew prior to entering Mode 2.

Actions taken by the licensee in response to this event included declaring the event a reactivity management event; making an NRC notification under 10 CFR 50.72(b)(3)(v)(D); resetting their site event clock; providing additional training for the applicable operating crew; and revising procedures associated with this event to clarify the sequencing of key activities associated with the transition between Mode 4 and Mode 2. The licensee entered this issue into their corrective action program (CAP 01314953).

This event was evaluated in detail by the inspectors during the fourth quarter of 2011.

The results of these inspections were documented in Section 1R20.2 of Integrated Inspection Report 05000263/2011005. Documents reviewed as part of this inspection are listed in the Attachment to this report. This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

.6 (Closed) Licensee Event Report (LER) 05000263-2011-011-00: Failure to Lock Mode

Switch in Refuel Position During Control Rod Exercises The inspectors evaluated an event, which was discovered on December 1, 2011, involving a human performance issue that resulted in an operation or condition prohibited by TSs. On November 30, 2011, the plant was in cold shutdown (Mode 4),with the Mode switch in the Refuel position to facilitate upcoming CRD exercising.

At approximately 15:23, the applicable TSs were entered and CRD testing commenced, in accordance with Procedure 0074, Single Control Rod Withdrawal - Cold Shutdown.

On December 1, 2011, at approximately 21:42, control room operators identified that the Mode switch was in the Refuel position, but was not locked in that position, as required by TS. Once identified, the operators took prompt actions to lock the Mode switch in the Refuel position.

The inspectors evaluated the significance of the event. The inspectors determined that a performance deficiency did exist, but was not of more than minor safety significance because the Mode switch, although not locked, remained in the Refuel position during the rod exercise surveillance, ensuring that the one-rod-out interlock remained capable of preventing more than one control rod from being withdrawn. The licensee implemented appropriate corrective actions to immediately lock the Mode switch in the correct position and to address the human performance issues that contributed to the event. This issue has been entered into the licensees corrective action program (CAP 01315669). Documents reviewed as part of this inspection are listed in the to this report. This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 11, 2012, the inspectors presented the inspection results to Mr. Haskell and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The inspection results for the areas of Radiological Hazard Assessment and Exposure Controls; and Radiation Monitoring Instrumentation with Mr. T. OConnor, Site Vice President, on March 16, 2012; and

• The status and an update of the Radiation Safety URI with Ms. S. OConnor, Regulatory Affairs Analyst, on March 28, 2012.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

4OA7 Licensee-Identified Violations

None.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. OConnor, Site Vice President

J. Grubb, Plant Manager

W. Paulhardt, Operations Manager

N. Haskell, Site Engineering Director

K. Jepson, Assistant Plant Manager

S. Radebaugh, Maintenance Manager

M. Holmes, Chemistry Manager

A. Zelie, Radiation Protection Manager

P. Kissinger, Regulatory Affairs Manager

Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

Attachment

LIST OF ITEMS

Opened

05000263/2012002-01 NCV Failure to Monitor Condensate Feedwater System Under 50.65(a)(1) due to Inadequate Maintenance Rule Failure Tracking (Section 1R12)

05000263/2012002-02 NCV Failure to Monitor Residual Heat Removal System Under 50.65(a)(1) due to Inadequate Maintenance Rule Evaluations (Section 1R12)

05000263/2012002-03 NCV Inadequate Evaluation of Compensatory Measure (Section 1R15)

05000263/2012002-04 URI Monticello Susceptibility to Degraded Voltage and Under Voltage Conditions Identified by January 30, 2012, Event at the Byron Station (Section 1R15)

05000263/2012002-05 URI Radiation Detection Equipment Calibration Protocol for Low Energy Beta Emitters (Section 2RS5)

05000263/2012002-06 FIN Ineffective Management of Turbine Lube Oil Tank Vacuum Resulting in Fouling of Grounding Braids (Section 4OA3.4)

Closed

05000263/2012002-01 NCV Failure to Monitor Condensate Feedwater System Under 50.65(a)(1) due to Inadequate Maintenance Rule Failure Tracking (Section 1R12)

05000263/2012002-02 NCV Failure to Monitor Residual Heat Removal System Under 50.65(a)(1) due to Inadequate Maintenance Rule Evaluations (Section 1R12)

05000263/2012002-03 NCV Inadequate Evaluation of Compensatory Measure (Section 1R15)

05000263/2012002-06 FIN Ineffective Management of Turbine Lube Oil Tank Vacuum Resulting in Fouling of Grounding Braids (Section 4OA3.4)

05000263-2011-006-01 LER Intake Structure Fire Suppression System Blockage (Section 4OA3.1)

05000263-2011-007-01 LER Both Emergency Diesel Generators Declared Inoperable Due to Inadequate Surveillance (Section 4OA3.2)

05000263-2011-008-00 LER Reactor Scram Due to Loss of Normal Offsite Power (Section 4OA3.3)

05000263-2011-008-01 LER Reactor Scram Due to Loss of Normal Offsite Power (Section 4OA3.3)

Attachment

05000263-2011-009-00 LER Automatic Reactor Scram While Performing - Generator Testing (Section 4OA3.4)

05000263-2011-009-01 LER Automatic Reactor Scram While Performing - Generator Testing (Section 4OA3.4)

05000263-2011-010-00 LER Rod Worth Minimizer Bypassed During Startup (Section 4OA3.5)

05000263-2011-011-00 LER Failure to Lock Mode Switch in Refuel Position During Control Rod Exercises (Section 4OA3.6)

Discussed

None.

Attachment