IR 05000263/2013005

IR 05000263-13-005; 07200058-13-001, 10/01/2013 - 12/31/2013; Monticello Nuclear Generating Plant. Post Maintenance Testing; Surveillance Testing; and Occupational ALARA Planning and Controls

ML14041A007
Person / Time
Site:	Monticello
Issue date:	02/07/2014
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Fili K Northern States Power Co
References
IR-13-001, IR-13-005
Download: ML14041A007 (48)

Text

UNITED STATES ary 7, 2014

SUBJECT:

MONTICELLO NUCLEAR GENERATING PLANT NRC INTEGRATED AND POWER UPRATE INSPECTION REPORT NOS. 05000263/2013005 AND 07200058/2013001

Dear Ms. Fili:

On December 31, 2013, 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 January 8, 2014, with you and other members of your staff.

Three NRC-identified findings of very low safety significance (Green) were identified during this inspection. Two of the findings were determined to involve violations of NRC requirements.

Further, licensee-identified violations which were determined to be of very low safety significance are listed in this report. The NRC is treating these violations as non-cited violations (NCVs) in accordance with Section 2.3.2.a of the NRC 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.

As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and 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 Documents Access and Management System (ADAMS),

accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Kenneth Riemer, Branch Chief Branch 2 Division of Reactor Projects Docket No. 50-263;72-058 License No. DPR-22

Enclosure:

IR Nos. 05000263/2013005 and 07200058/2013001; w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-263;72-058 License No: DPR-22 Report Nos: 05000263/2013005 and 07200058/2013001 Licensee: Northern States Power Company, Minnesota Facility: Monticello Nuclear Generating Plant Location: Monticello, MN Dates: October 1 through December 31, 2013 Inspectors: P. Zurawski, Senior Resident Inspector P. Voss, Resident Inspector S. Bell, Health Physicist M. Learn, Reactor Engineer M. Bielby, Senior Operations Engineer C. Moore, Operations Engineer J. Laughlin, Emergency Preparedness Inspector Approved by: K. Riemer, Branch Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000263/2013005; 10/01/2013 - 12/31/2013; Monticello Nuclear

Generating Plant. Post-Maintenance Testing; Surveillance Testing; and Occupational ALARA Planning and Controls.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Three Green findings were identified by the inspectors. Two of the findings were considered non-cited violations (NCVs) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using IMC 0609,

Significance Determination Process dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross Cutting Areas dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when the licensee failed to accomplish activities affecting quality in accordance with instructions, procedures, or drawings. Specifically, licensee personnel failed to abide by procedural requirements for pump discharge pressure limitations contained in Procedure 0255-02-III, SBLC Quarterly Pump and Valve Tests, when they imprecisely controlled the 11 standby liquid control (SBLC) flow control valve during the test. This led to the halting of the SBLC test while the equipment condition was evaluated and resulted in the validity of the inservice test (IST) data being brought in to question. The licensee re-performed the test for the 11 SBLC pump; stood down the workers involved; increased operational oversight of the test; evaluated the condition of the equipment; performed a human performance event review; and included communication of the error as part of a site-wide stand down. This issue was entered into the licensees corrective action program (CAP 1401816).

The inspectors determined that the licensees failure to abide by SBLC procedural limitations was a performance deficiency, because it was the result of the failure to meet the requirements of 10 CFR 50, Appendix B, Criterion V; the cause was reasonably within the licensees ability to foresee and correct; and should have been prevented.

The inspectors screened the performance deficiency per Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, and determined that the issue was more than minor because, if left uncorrected, it had the potential to lead to a more significant safety concern. Specifically, if pressure limitations had been further exceeded, the discharge relief valve would have lifted, which could result in inoperability of the 11 SBLC pump until repair or replacement of the relief valve. In addition, inadequately performing the SBLC surveillance and IST testing could have the potential to mask degraded conditions associated with the pump. The inspectors applied IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, to this finding. The inspectors utilized Exhibit 2, Section A, Mitigating Systems, to screen the finding. The finding was determined to have very low safety significance because the inspectors answered No to all four questions. 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 using human error prevention techniques during performance of work activities H.4(a).

(Section 1R22)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a finding of very low safety significance and a NCV of Technical Specification (TS) 5.4.1 due to the failure to perform safety-related maintenance in accordance with documented instructions. Specifically, the improper control of safety-related maintenance on reactor core isolation cooling (RCIC) injection check valve AO-13-22 resulted in the injection of seven sticks of a leak sealing compound (e.g. Furmanite) instead of the maximum four called out in Work Order (WO)486966. This issue was entered into the licensees corrective action program (CAP 1402240). Corrective actions included a site stand down; down-grade of the Furmanite technicians leak repair certification, pending investigation and retraining; revise procedures requiring each Furmanite injection be observed by maintenance supervision; and development of a fleet procedure/process for oversight of supplemental personnel.

The inspectors determined that the failure to perform safety-related maintenance in accordance with documented instructions was a performance deficiency requiring evaluation. The inspectors determined the issue was more than minor because, if left uncorrected, the failure to follow leak sealant work instructions could lead to more significant safety concerns. The inspectors assessed the significance of this finding in accordance with Inspection Manual Chapter (IMC) 0609 and determined that it was of very low safety significance. The inspectors concluded that this finding was cross-cutting in the Human Performance, work practices area because of the failure to ensure supervisory and management oversight of work activities H.4(c).

(Section 1R19)

Cornerstone: Occupational Radiation Safety

Green.

A finding of very low safety significance was self-revealed due to the licensee having unplanned and unintended occupational collective radiation dose because of deficiencies in the licensees radiological work planning and work control program.

Specifically, the licensee failed to properly incorporate as-low-as-reasonably-achievable (ALARA) strategies and insights while planning and executing two work activities during the refueling outage (RFO) 26. The first was the inservice inspection (ISI) examinations performed in the drywell. The initial dose estimate for this activity was 7.500 person-rem. However, 13.173 actual person-rem of dose was received. The second activity was associated with drywell snubber inspection activities within the drywell. The initial estimate for this activity was 3.600 person-rem. However, 7.243 actual person-rem of dose was received. These results were caused by poor radiological planning and work execution of these tasks. The licensee entered this issue into their CAP as Action Reports 1404210 and 1404244.

The finding was more than minor because it was associated with the program and process attribute of the Occupation Radiation Safety Cornerstone. Additionally, this issue affected the cornerstone objective of ensuring the adequate protection of the workers health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Additionally, the finding is very similar to Inspection Manual Chapter (IMC) 0612, Appendix E, Examples of Minor Issues,

Example 6.i. This example provides guidance that an issue is not minor if the actual collective dose exceeded 5 person-rem and exceeded the planned, intended dose by more than 50 percent. The inspectors determined that this finding was of very low safety significance because Monticello Nuclear Generating Plants current 3-year rolling average collective is 110.633 person-rem (2010-2012). This is less than the 240 person-rem/unit referenced within IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process. This finding had a cross-cutting aspect in the area of Human Performance, related to the cross-cutting aspect of work control, in that the outage plan did not adequately incorporate action to address the impact of work on different job activities H.3(b). (Section 2RS2)

• Violations of very low safety or security significance or Severity Level IV that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program (CAP). These violations and CAP tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Monticello began the inspection period operating at full power (1775 megawatts thermal (MWt)).

On December 9, 2013, Amendment 176 was issued to Facility Operating License DPR-22.

The Amendment regards extended power uprate (EPU) and increases the authorized maximum licensed thermal power level by approximately 13 percent, from the current licensed thermal power of 1775 MWt to 2004 MWt. On December 13, 2013, power was reduced to approximately 85 percent power (based on 1775 MWt) for turbine valve testing and control rod pattern adjustment for EPU testing. Subsequent to these activities, the plant was restored to its previously licensed thermal power limit of approximately 1775 MWt (88.5 percent of new 2004 MWt limit). Extended power uprate testing activities recommenced on December 30, 2013, with power increased to approximately 102.5 percent of the previously licensed 1775 MWt limit (91 percent of 2004 MWt).

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity and

Emergency Preparedness

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. The inspection focused on Abnormal Procedure C.4-B.08.03.A, Loss of Heating Boiler, and risk significant systems protected by that procedure. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Safety Analysis Report (USAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed 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. Documents reviewed are listed in the Attachment to this report. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

• Emergency service water (ESW);

• Plant heating boiler; and

• Intake structure traveling screens.

This inspection constituted one winter seasonal readiness preparations 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:

• Emergency filtration train (EFT) and control room ventilation (CRV) train B during train A maintenance window;

• Service water radiation monitors due to major loss of assessment capability, if unavailable greater than 15 minutes; and

• 11 emergency diesel generator (EDG) during 12 EDG work window.

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, 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

On November 26, 2013, the inspectors performed a complete system alignment inspection of the EDG-ESW 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 lineups; 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 Attachment 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 13B; Rx feedwater (FW) pump and lube oil reservoir;

• Fire Zone 19-A; Make-up demin area;

• Fire Zone 13-C; Turbine building 911' motor control center (MCC);

• Fire Zone 16; Corridor, turbine building east and west 911' and 931';

• Fire Zone 19-C; FW pipe chase; and

• Fire Zone 19-B; Essential MCC 142/143 area.

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.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the USAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the to this report. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant area to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• Intake Screenhouse.

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

This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

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 12 EDG-ESW jacket water heat exchangers 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 document.

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 December 2, 2013, 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 simulator 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 December 13, 2013, the inspectors observed a planned power reduction to approximately 90 percent power for EPU testing. On December 14, 2013, inspectors observed power ascension activities when the plant was returned to 100 percent power.

Since these power manipulations were performed at a time coincident with an issue of reduced pressure retaining capability of the 12 recirculation pump upper seal, the activities required heightened awareness and 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;

• recirculation pump seal monitoring activities; 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.

a. Findings

No findings were identified.

.3 Biennial Written and Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Biennial Written Examination, administered by the licensee from October 14 - November 22, 2013, and the Annual Operating Test, administered by the licensee from October 14 - November 22, 2013, as required by 10 CFR 55.59(a). The results were compared to the thresholds established in IMC 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP)," to assess the overall adequacy of the licensees Licensed Operator Requalification Training Program (LORT) to meet the requirements of 10 CFR 55.59.

(02.02)

This inspection constituted one annual licensed operator requalification examination results sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

.4 Biennial Review

a. Inspection Scope

The following inspection activities were conducted during the weeks of October 21, 2013, and October 28, 2013, to assess: 1) the effectiveness and adequacy of the facility licensees implementation and maintenance of its systems approach to training (SAT) based LORT program, put into effect to satisfy the requirements of 10 CFR 55.59; 2) conformance with the requirements of 10 CFR 55.46 for use of a plant referenced simulator to conduct operator licensing examinations and for satisfying experience requirements; and 3) conformance with the operator license conditions specified in 10 CFR 55.53. The documents reviewed are listed in the Attachment to this report.

Licensee Requalification Examinations (10 CFR 55.59(c); SAT Element 4 as Defined in 10 CFR 55.4):

The inspectors reviewed the licensees program for development and administration of the LORT biennial written examination and annual operating tests to assess the licensees ability to develop and administer examinations that are acceptable for meeting the requirements of 10 CFR 55.59(a).

• The inspectors conducted a detailed review of two biennial requalification written examination versions to assess content; level of difficulty; and quality of the written examination materials. (02.03)

• The inspectors conducted a detailed review of 10 job performance measures (JPMs) and six simulator scenarios to assess content, level of difficulty, and quality of the operating test materials. (02.04)

• The inspectors observed the administration of the annual operating test and biennial written examination to assess the licensees effectiveness in conducting the examination, including the conduct of pre-examination briefings, evaluations of individual operator and crew performance, and post examination analysis.

The inspectors evaluated the performance of one operating crew (three simulator crews) in parallel with the facility evaluators during three dynamic simulator scenarios and evaluated various licensed crew members concurrently with facility evaluators during the administration of several JPMs.

(02.05)

• The inspectors assessed the adequacy and effectiveness of the remedial training conducted since the last requalification examinations and the training planned for the current examination cycle to ensure that they addressed weaknesses in licensed operator or crew performance identified during training and plant operations. The inspectors reviewed remedial training procedures and individual remedial training plans. (02.07)

Conformance with Examination Security Requirements (10 CFR 55.49):

The inspectors conducted an assessment of the licensees processes related to examination physical security and integrity (e.g., predictability and bias) to verify compliance with 10 CFR 55.49, Integrity of Examinations and Tests. The inspectors reviewed the facility licensees examination security procedure, and observed the implementation of physical security controls (e.g., access restrictions and simulator input/output (I/O) controls) and integrity measures (e.g., security agreements, sampling criteria, bank use, and test item repetition) throughout the inspection period. (02.06)

Conformance with Operator License Conditions (10 CFR 55.53):

The inspectors reviewed the facility licensee's program for maintaining active operator licenses and to assess compliance with 10 CFR 55.53(e) and (f). The inspectors reviewed the procedural guidance and the process for tracking on-shift hours for licensed operators and which control room positions were granted watch standing credit for maintaining active operator licenses. Additionally, medical records for seven licensed operators were reviewed for compliance with 10 CFR 55.53(I). (02.08)

Conformance with Simulator Requirements Specified in (10 CFR 55.46):

The inspectors assessed the adequacy of the licensees simulation facility (i.e., simulator) for use in operator licensing examinations and for satisfying experience requirements. The inspectors reviewed a sample of simulator performance test records (e.g., transient tests, malfunction tests, scenario based tests, post-event tests, steady state tests, and core performance tests), simulator discrepancies, and the process for ensuring continued assurance of simulator fidelity in accordance with 10 CFR 55.46.

The inspectors reviewed and evaluated the discrepancy corrective action process to ensure that simulator fidelity was being maintained. Open simulator discrepancies were reviewed for importance relative to the impact on 10 CFR 55.45 and 55.59 operator actions as well as on nuclear and thermal hydraulic operating characteristics. (02.09)

Problem Identification and Resolution (10 CFR 55.59(c); SAT Element 5 as defined in 10 CFR 55.4):

The inspectors assessed the licensees ability to identify, evaluate, and resolve problems associated with licensed operator performance (a measure of the effectiveness of its LORT Program and their ability to implement appropriate corrective actions to maintain its LORT Program up to date). The inspectors reviewed documents related to licensed operator performance issues (e.g., recent examination and inspection reports including cited and NCVs; NRC End of Cycle and Mid-Cycle reports; NRC plant issue matrix; licensee event reports; licensee condition/problem identification reports including documentation of plant events and review of industry operating experience). The inspectors also sampled the licensees quality assurance oversight activities, including licensee training department self-assessment reports. (02.10)

This inspection constituted one biennial licensed operator requalification program inspection sample as defined in IP 71111.11-05.

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:

• Residual heat removal (RHR) system;

• Meteorological monitoring system; and

• Residual heat removal service water (RHRSW) system.

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.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control 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:

• High pressure coolant injection (HPCI) steam leak (RC-94-1) Furmanite repair;

• 12 recirculation pump upper seal degradation; and

• Intake structure emergent icing condition.

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

These maintenance risk assessments and emergent work control activities constituted three 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:

• Dry storage canister (DSC) liquid penetrant examinations;

• Missed containment isolation valve (CIV) surveillance test; and

• Surveillance requirement (SR) 3.3.3.1.2 CIV post-accident monitoring (PAM)position indication surveillance questions.

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.

These operability inspections constituted three samples as defined in IP 71111.15-05.

b. Findings

Introduction The inspectors identified an unresolved item (URI) due to questions whether nondestructive examination (NDE) liquid penetrant examination (PT) techniques for DSC No. 16 met procedure and TS requirements.

Description On October 17, 2013, the resident inspectors observed part of the NDE PT activities for the outer top cover plate on Transnuclear Model [Nutech Horizontal Modular Storage]

NUHOMS-61BTH DSC No. 16. The inspectors questioned whether the cleaning and dwell/development times for the penetrant and developer used by a contract NDE PT Level II examiner met procedure requirements demonstrating compliance with the ISFSI TS. The licensee initiated CAP 1402246 to document the inspectors questions. The CAP established actions to determine if procedure requirements had been met, to evaluate operability/reportability, conduct an apparent cause evaluation, and conduct an extent of condition review.

After initial evaluation of recorded video of the work location, the licensee determined that the dwell times for both the penetrant and developer for the outer top closure plate weld were not in compliance with procedure requirements. Further review of previous PT exams conducted on DSCs No. 11 through No. 16 revealed additional examinations may not have complied with dwell times specified by the procedure, as well as other potential discrepancies. All of the PT examinations for these DSCs were performed by two contract NDE PT Level II examiners. As a result, the licensees immediate operability determination declared DSCs Nos. 11 through 16 inoperable for the failure to satisfy TS 1.2.5, which specifies all DSC closure welds, except those subjected to full volumetric inspection be dye penetrant tested in accordance with the requirements of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section III. Inspectors reviewed the licensees immediate operability determination.

Additionally, the licensees initial investigation resulted in a written stop work on October 18, 2013. An extent of condition was initiated for five other DSCs (Nos. 11 through 15) processed during the 2013 campaign. Although extent of condition was still on-going upon close of the quarterly inspection period, initial results of the review determined that there was no reason to suspect the integrity of the closure welds for DSCs Nos. 11 through 16. Specifically, since helium leak testing was completed, with acceptable results, during the loading operations for each DSC by a vendor independent from the contract organization that supplied the PT inspectors.

Licensee review concluded the helium leak testing determined each of the DSCs to be leak tight and consequently no concern existed with the confinement function of the canisters. As a result, the licensee determined that 10 CFR 72.75 reportability was not required. Inspectors reviewed the licensees reportability evaluation.

Throughout the inspection period, the inspectors monitored licensee actions in regard to operability, reportability, and extent of condition reviews. Upon close of the inspection period, licensee actions continued in regard to finalizing the extent of condition, causal analysis, and corrective actions.

This issue will be categorized as an URI pending ongoing licensee actions and additional agency review of the event. The inspectors have consulted with regional management, including the Office of Nuclear Material Safety and Safeguards, as necessary to resolve this issue (URI 07200058/2013001-01: Dry Shielded Canister Liquid Penetrant Examination).

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:

• Reactor core isolation cooling (RCIC) testable check valve (AO-13-22) Furmanite repair;

• CV-6-13 Furmanite Injection; and

• RCIC downscale indication on control room turbine speed indicator.

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 three PM testing samples as defined in IP 71111.19-05.

b. Findings

Failure to Follow Procedure for AO 13-22 Furmanite Injection Introduction An inspector-identified finding of very low safety significance (Green) and NCV of TS 5.4.1 occurred on October 17, 2013, due to the failure to perform safety-related maintenance in accordance with documented instructions. Specifically, the improper control of safety-related maintenance on RCIC injection check valve AO 13-22 resulted in the injection of seven sticks of a leak sealing compound (e.g. Furmanite) instead of the maximum four called out in WO 486966.

Description On October 17, 2013, the licensee implemented safety-related WO 486966 to repair a steam leak on RCIC injection testable check valve AO 13-22. Step 7.12 of licensee WO 486966 delineated a maximum of four sticks of material to be injected. The licensee utilized contracted services of a Furmanite technician to perform the repair activities.

Contrary to these requirements, the Furmanite representative injected seven sticks of leak sealing compound into AO 13-22, instead of the maximum four sticks specified by WO 486966. On October 17, 2013, a pre-job brief was conducted with attendance by licensee and contract individuals involved with the work activity. Licensee maintenance supervision overseeing the work activity also attended the pre-job briefing. The pre-job brief discussed the job scope and procedure to be used, including discussions on how much leak sealant could be used. Sealant injection activities began after completion of a preliminary task to remove the valve actuator on AO 13-22. Specifically, the Furmanite technician started injecting sealant into the valve by using compound FSC-N-6B. During the injection, the technician noticed compound extruding from the gasket area due to the high leak pressure. With licensee management observing work activities through video feeds to the remote monitoring control room (RMCR), the Furmanite technician injected the four sticks of sealant compound allowed by procedure, but the check valve hinge pin cover gasket continued to leak. The technician calculated how much material had extruded and determined he could inject more compound because of a belief that the four sticks had not been actually injected into the valve. At this time, the technician made a request to the RMCR for three sticks of FSC-N-3B compound, since it has a stiffer composition and causes less blow out. The request for three sticks of FSC-N-3B was received in the RMCR and relayed to first-line supervision. The jobs first-line supervision delivered the three sticks of FSC-N-3B to the job site but did not ask for three sticks of the FSC-N-6B compound back. At this time seven sticks of compound were in the steam chase and the first-line supervisor returned to the RMCR and asked the maintenance manager how many sticks of compound had been used. No one in the RMCR knew the answer. Although multiple licensee personnel were observing the work activity, the maintenance oversight function did not identify the discrepancy in expectations.

The inspectors asked the maintenance manager how many sticks of compound had been injected with a reply that he didnt know. The maintenance manager used a head set to contact one of the mechanics at the work area to ask the Furmanite technician how many sticks of compound he had injected. The technician responded that he had used seven sticks. This was relayed back to the maintenance manager who informed the mechanic to not allow the technician to inject anymore compound into the valve. By this time, the leak had stopped.

The licensee initiated CAP 1402240 to document the AO 13-22 Furmanite injection process question raised by the inspectors. The licensee conducted an apparent cause evaluation for the event. Subsequent corrective actions included a site stand down; down-grade of the Furmanite technicians leak repair certification pending investigation and retraining; revise procedures requiring each Furmanite injection be observed by maintenance supervision, and development of a fleet procedure/process for oversight of supplemental personnel.

Analysis The inspectors determined that the failure to perform safety-related maintenance in accordance with documented instructions was a performance deficiency due to a failure to meet TS requirement 5.4.1 and the cause was reasonably within the licensees ability to foresee/correct and should have been prevented. Inspectors evaluated the issue using the SDP and determined that it was more than minor because, if left uncorrected, the failure to follow safety-related maintenance in accordance with documented work instructions could lead to more significant safety concerns.

Specifically, injecting too much leak sealing compound can enter the feedwater system and potentially cause chemistry issues or block small openings in fuel channels.

Furthermore, if left uncorrected the finding could impact the Human Performance attribute (foreign material exclusion (FME) loose parts) of the Barrier Integrity Cornerstone to maintain fuel cladding functionality.

The inspectors assessed the significance of this finding using IMC 0609, Appendix A, Exhibit 3, Barrier Integrity. The inspectors determined that the finding was of very low safety significance, since it did not impact the reactor coolant system (RCS) boundary; reactor containment; spent fuel pool (SFP); or control room, auxiliary, reactor building, or SFP building. The inspectors concluded that this finding was cross-cutting in the Human Performance, work practices area because the licensee failed to ensure supervisory and management oversight of work activities on AO 13-22, including contractors, such that nuclear safety is supported. Specifically, licensee management oversight was present but failed to properly manage the number of injection sticks brought into the area and control how many sticks were used (H.4(c)).

Enforcement Technical Specification 5.4.1 required that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978. Section 9 of RG 1.33, Revision 2, Appendix A, February 1978, requires that maintenance that can affect the performance of safety-related equipment be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstance.

Contrary to the above, on October 17, 2013, the licensee failed to implement procedures for safety-related maintenance on RCIC injection check valve AO 13-22. As a result, seven sticks of a leak sealing compound (e.g. Furmanite) were injected into AO 13-22 instead of the four called out in WO 486966. Because this violation was of very low safety significance and it was entered into the corrective action program as CAP 1402240, this issue is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000263/2013005-01: Failure to Follow Procedure for AO 13-22 Furmanite Injection). Corrective actions for this event included a site stand down; down-grade of the Furmanite technicians leak repair certification pending investigation and retraining; revise procedures requiring each Furmanite injection be observed by maintenance supervision; and development of a fleet procedure/process for oversight of supplemental personnel.

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:

• 0255-17-IA-5; Alternate nitrogen system train A valve test (inservice test (IST));

• 0255-02-III; Standby liquid control (SBLC) quarterly pump and valve tests (routine);

• 0255-03-IA-1-2; Core spray loop B quarterly pump and valve tests (routine);

• 0533; Containment sump flow measurement instrumentation (RCS leakage); and

• 8215/8216; EPU dynamic test (routine).

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

• did preconditioning occur;

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

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

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

• as-left set points 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, 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 three routine surveillance testing samples, one IST sample, and one RCS leak detection inspection sample as defined in IP 71111.22, Sections

-02 and -05. The routine inspection sample for the 8215/8216, EPU dynamic test, also constituted a power uprate sample as defined in IP 71004.

b. Findings

Introduction The inspectors identified a finding of very low safety significance and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when the licensee failed to accomplish activities affecting quality in accordance with instructions, procedures, or drawings. Specifically, licensee personnel failed to abide by procedural requirements for pump discharge pressure limitations contained in 0255-02-III, SBLC Quarterly Pump and Valve Tests, when they imprecisely controlled the 11 SBLC flow control valve during the test.

Description On October 15, 2013, inspectors observed performance of Procedure 0255-02-III, SBLC Quarterly Pump and Valve Tests. Prior to performance of the procedure, inspectors noted that the pre-job brief for the activities specifically discussed steps that were deemed critical steps because their intent was to prevent lifting of the relief valve at the discharge of the SBLC pumps. The pre-job brief also highlighted Precaution D.1, which states, Do NOT exceed 1350 psig pump discharge pressure during the performance of this test because the relief valves could unseat. Inspectors also noted a continuous awareness step which directed notification of Shift Supervision if the relief valve lifts, for operability evaluation. The Procedure Bases section listed several considerations that could be used when determining pump operability if a relief valve were to lift.

During the test, inspectors witnessed performance of steps to place SBLC pump No. 11 within a pressure band required for IST testing. This was accomplished by operators manipulation of a test control valve downstream of the discharge of 11 SBLC.

During these activities, inspectors noted that the operator controlling the test control valve had manipulated the valve several turns in the wrong direction, which resulted in a quick lowering discharge pressure, reaching as low as approximately 550 psig. When the operator observed the low pressure on the pressure gage, the error was recognized, and the worker made several quick manipulations of the valve in the opposite direction.

As a result, pump discharge pressure increased rapidly, at which point several valve manipulations were made to arrest the pressure increase. Discharge pressure reached a maximum of 1400 psig at this point, which resulted in a procedural violation of Precaution D.1. Inspectors observed that the operator failed to control the valve precisely, failed to self-check, and continued to proceed in the face of uncertainty once the initial error and resultant low pressure was identified.

Once inspectors raised questions about the activities, the procedural limitations, and the impacts on the equipment, the test was stopped. Operations management evaluated the condition of the equipment affected, and determined that the relief valve had not lifted, and that the system was not damaged as a result of the inadequate pressure control. Operations management also validated set points and design of the relief valve, to ensure that the lack of relief valve lifting was expected. Ultimately, the licensee re-performed the test for the 11 SBLC pump; stood down the workers involved; increased operational oversight of the test; performed a human performance event review; and included communication of the error as part of a site-wide stand down.

Issues associated with the error were entered into the licensees corrective action program as CAP 1401816, CAP 1401816, and CAP 1401968.

Analysis The inspectors determined that the licensees failure to abide by SBLC procedural limitations was a performance deficiency, because it was the result of the failure to meet the requirements of 10 CFR 50, Appendix B, Criterion V; 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 using human error prevention techniques during performance of work activities H.4(a).

Specifically, licensee personnel failed to utilize human error prevention techniques, such as self and peer checking, and personnel proceeded in the face of uncertainty and unexpected circumstances during the improper manipulation of the control valve.

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, if left uncorrected, it has the potential to lead to a more significant safety concern. Specifically, if pressure limitations had been further exceeded, the discharge relief valve would have lifted, which could result in inoperability of the 11 SBLC pump until repair or replacement of the relief. In addition, inadequately performing the SBLC surveillance and IST testing could have the potential to mask degraded conditions associated with the pump. The finding was evaluated under the Mitigating Systems Cornerstone. The inspectors applied IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, The SDP for Findings At-Power, to this finding. The inspectors utilized Exhibit 2, Section A, for Mitigating Systems to screen the finding. The finding was determined to have very low safety significance because the inspectors answered No to all four questions. (Green)

Enforcement Title 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings,"

requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.

Contrary to this requirement, on October 15, 2013, the licensee failed to accomplish activities affecting quality in accordance with instructions, procedures, or drawings.

Specifically, licensee personnel failed to abide by procedural requirements for pump discharge pressure limitations contained in 0255-02-III, SBLC Quarterly Pump and Valve Tests, when they imprecisely controlled the 11 SBLC flow control valve during the test. This led to the halting of the SBLC test while the equipment condition was evaluated and resulted in the validity of the IST test data being brought into question.

The licensee re-performed the IST surveillance test for the 11 SBLC pump; stood down the workers involved; increased operational oversight of the test; evaluated the condition of the equipment; performed a human performance event review; and included communication of the error as part of a site-wide stand down. Because the violation was of very low safety significance and was entered into the licensees corrective action program (CAP 1401816), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000263/2013005-02; SBLC Discharge Pressure Procedural Limits Exceeded)

1EP4 Emergency Action Level and Emergency Plan Changes

.1 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The Office of Nuclear Security and Incident Response headquarters staff performed an in-office review of the latest revisions to the Emergency Plan and various Emergency Plan Implementing Procedures (EPIPs) located under ADAMS Accession Numbers ML13014A044, ML13052A616, and ML123560180, as listed in the Attachment to this report.

The licensee transmitted the EPIP revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, Implementing Procedures. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment to this report.

This emergency action level and emergency plan change inspection constituted one sample as defined in IP 71114.04-05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated a licensee drive-in emergency drill on October 12, 2013; a table-top emergency drill on November 18, 2013; and a table-top emergency drill on November 25, 2013, to observe licensee response to emergency preparedness scenarios. For the drive-in drill, inspectors observed the responsiveness of licensee emergency responders to both the Onsite Support Center and the Technical Support Center. For the table-top emergency drills, the inspectors observed emergency response operations in the Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critiques 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.

These emergency preparedness drill inspections constituted three samples as defined in IP 71114.06-05.

b. Findings

No findings were identified.

2RS2 Occupational As-Low-As-Reasonably-Achievable Planning and Controls

These inspection activities supplement those documented in NRC IRs 05000263/2012004, 05000263/2012005, 05000263/2013002, and 05000263/2013004, and constitute one complete sample as defined in IP 71124.02-05.

.1 Radiological Work Planning (02.02)

a. Inspection Scope

The inspectors compared the results achieved (dose rate reductions, person-rem used)with the intended dose established in the licensees ALARA planning for the following work activities: Refueling outage (RFO) 26 drywell inservice ISI and RFO 26 containment snubber inspections. The inspectors compared the person hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements and evaluated the accuracy of these time estimates. The inspectors assessed the reasons for any inconsistencies between intended and actual work activity doses.

b. Findings

Introduction A finding of very low safety significance (Green) was self-revealed due to the licensee having unplanned and unintended occupational collective radiation dose because of deficiencies in the licensees radiological work planning and work control program.

Specifically, the licensee failed to properly incorporate ALARA strategies and insights while planning and executing two work activities during RFO 26. The first was the ISI examinations performed in the drywell. The initial dose estimate for this activity was 7.500 person-rem. However, 13.173 actual person-rem of dose was received. The second activity was associated with drywell snubber inspection activities within the drywell. The initial estimate for this activity was 3.600 person-rem. However, 7.243 actual person-rem of dose was received. These results were caused by poor radiological planning and work execution of these tasks.

Description During RFO 26, numerous work tasks were performed. Two of those were the ISI examinations and snubber inspections. Both of these tasks were performed within the drywell. The following table provides information for these tasks:

Task Work Order RWP(s) Initial Final Person-Rem Person-Rem Estimate ISI 443935 701 7.500 13.173 examinations Snubber 457787 814, 1446 3.600 7.243 Inspections Inservice Inspections: The licensee performed a number of work-in-progress (WIP) reviews for the ISI examinations between March 21, 2013, and April 23, 2013.

During this time period it became apparent to the licensee that the original work scope was not effectively communicated to the ALARA department as part of the original planning process. On April 23, 2013, the station ALARA committee revised the dose estimate for this task to 13.166 person-rem. The increase in the dose estimate for ISI was mainly driven by the initial failure to estimate the resources for removal of insulation and structural inferences necessary to perform the examinations. These examinations were previously performed during RFOs. The departments which performed these tasks did not provide complete information to the ALARA planning department. This resulted in an inaccurate initial dose estimate.

Snubber Inspections: The licensee performed a number of WIP reviews for the drywell snubber inspections between March 26, 2013, and April 26, 2013. During this time period, it became apparent to the licensee that the percentage of work completed was not tracking with original dose estimates. On March 28, 2013, the station ALARA committee revised the dose estimate for this task to 7.500 person-rem. The increase in the dose estimate for the drywell snubber inspections was driven by the initial failure to estimate and compensate for the reduced level of experience for the work crews performing this task compared to previous outages.

Analysis The failure to appropriately plan and coordinate outage activities, together with the failure to properly incorporate ALARA strategies or insights while planning and executing ISI examinations and snubber inspections during RFO 26, was a performance deficiency that was within the licensees ability to control and should have been prevented. The finding was more than minor because it was associated with the program and process attribute of the Occupational Radiation Safety Cornerstone. Additionally, this issue affected the cornerstone objective of ensuring the adequate protection of the workers health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Additionally, the finding is very similar to IMC 0612, Appendix E, Examples of Minor Issues, Example 6.i. This example provides guidance that an issue is not minor if the actual collective dose exceeded five person-rem and exceeded the planned, intended dose by more than 50 percent. The inspectors determined that this finding was of very low safety significance in accordance with IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process. This was a finding in the ALARA planning and work controls but not greater than the 240 person-rem/unit for a boiling water reactor. The licensees current collective 3-year rolling average was 110.633 person-rem (2010 - 2012). This finding had a cross-cutting aspect in the area of Human Performance, related to the cross-cutting aspect of work control, in that the outage plan did not adequately incorporate action to address the impact of work on different job activities [H3.(b)].

Enforcement No violation of regulatory requirements occurred. This is considered a finding (FIN) of very low safety significance (FIN 05000263/2013005-03; Failure to Maintain Radiation Exposure ALARA during RFO 26). The licensee has entered this issue into their corrective action program as CAPs 1404210 and 1404244.

.2 Verification of Dose Estimates and Exposure Tracking Systems (02.03)

a. Inspection Scope

The inspectors evaluated the licensees method of adjusting exposure estimates, or re-planning work, when unexpected changes in scope or emergent work were encountered. The inspectors assessed whether adjustments to exposure estimates (i.e., intended dose) were based on sound radiation protection and ALARA principles or if they were just adjusted to account for failures to control the work. The inspectors evaluated whether the frequency of these adjustments called into question the adequacy of the original ALARA planning process.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - RHR System performance indicator (PI) for the period from the fourth quarter 2012 through the third quarter 2013. 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 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 2012 through September 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI RHR system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems PI for the period from the fourth quarter 2012 through the third quarter 2013. 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 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 2012 through September 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI cooling water system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.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 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 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six-month period of July 2013 through December 2013, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in major equipment problem lists; repetitive and/or rework maintenance lists; departmental problem/challenges lists; system health reports; quality assurance audit/surveillance reports; self-assessment reports; and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Unit 1 Power Uprate Related Inspection Activities

a. Inspection Scope

During this inspection period, the inspectors observed several activities related to the power uprate amendment. Specific activities are documented below, and as referenced:

• Inspectors reviewed a list of power uprate related modification packages, procedure changes, licensed operator lesson plans, and simulator modifications during the 71111.11B licensed operator requalification inspection. The inspectors reviewed simulator testing associated with secondary plant modifications and also reviewed several lesson plans associated with licensed operator training performed as a result of the power uprate modifications. The inspectors also observed several activities in the simulator during the licensed operator annual examination where the licensed operators utilized the feed-water control system that had been modified during the power uprate project;

• Section 1R22 - This section documents specific inspector reviews of EPU procedures associated with power ascension testing, along with the conduct of control room observation of EPU power dynamic testing; and

• NRC IR 05000263/2013007 - Specifically documented two permanent modification baseline inspection samples relating to the licensees EPU amendment. These samples included review of EC 11444 (2R and 1R transformer upgrades) and EC 11445 (new 13.8 kV bus 11 and 12 switchgear upgrades).

b. Findings

No findings were identified.

.2 Operation of an Independent Spent Fuel Storage Facility Installation (ISFSI) at

Operating Plants (60855.1) Operations of an ISFSI

a. Inspection Scope

The inspectors observed and evaluated select licensee loading operations during the fourth NUHOMS 61BTH canister of the licensees 2013 dry fuel storage campaign to verify compliance with the applicable Certificate of Compliance (CoC) conditions, the associated TS, and ISFSI procedures.

The licensee maintains an ISFSI at the Monticello Nuclear Generating Plant. The ISFSI stores both NUHOMS 61 BT and BTH canisters in horizontal storage modules (HSM). The inspectors performed tours of the ISFSI to assess the material condition of the pad, and HSMs. The inspectors reviewed the licensees evaluations of flammable materials near the ISFSI and radiation monitoring program. Additionally, the inspectors performed independent radiation surveys around the ISFSI pad and HSMs. The inspectors reviewed methodology associated with TS required daily temperature monitoring of the HSMs. The inspectors reviewed procedures used to perform ISFSI preparation, loading, sealing, transfer, monitoring, and storage activities.

The inspectors reviewed the licensees procedures for compliance with their control of heavy loads program and associated crane standards. The inspectors reviewed the licensees certificate of conformance for the transfer cask and associated lift yoke. The inspectors reviewed the licensees evaluations of cask lay down areas within the reactor building.

The inspectors reviewed the licensees evaluations associated with fuel characterization and selection for storage. The inspectors reviewed the licensees evaluation to characterize fuel as fuel debris, damaged, or intact fuel. The licensee did not plan to load any damaged fuel assemblies or fuel debris during this campaign. The inspectors reviewed the campaign cask fuel selection packages to verify that the licensee was loading fuel in accordance with the CoC approved contents.

The inspectors reviewed condition reports, and the associated corrective actions. The inspectors reviewed the licensees 10 CFR 72.48 screenings and the changes to the licensees 10 CFR 72.212 evaluations since the last ISFSI inspection.

b. Findings

No findings of significance were identified. Reference Section 1R15 of this report for a URI associated with resident office questions regarding dry cask liquid PTs.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 8, 2014, the inspectors presented the inspection results to Ms. Karen Fili 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:

• On October 4, 2013, the results for Operation of an ISFSI Inspection were presented to Lee Samson, Dry Fuel Storage Project Manager;

• On October 31, 2013, the inspectors presented Licensed Operator Requalification Inspection results to Mr. T. Shortell, Training Manager, and other members of the licensee staff. The licensee acknowledged the issues presented;

• On November 21, 2013, the inspection results for the area of Occupational ALARA Planning and Controls were presented to Mr. Alan Ziele, Radiation Protection Manager (via teleconference); and

• On December 10, 2013, the 2013 Licensed Operator Requalification Training Biennial Written Examination and Annual Operating Test results were presented to Mr. G. Allex, Licensed Operator General Training Supervisor (via teleconference).

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

The following violations of very low significance (Green) or Severity Level IV were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as NCVs.

• Title 10 CFR 55.21, Medical Examination, requires, in part, that licensed operators shall have a medical examination and a physician shall determine that the licensed operator meets specified requirements every two years. The licensee typically conducts annual medical examinations of their licensed operators in October. A reactor operator initially received a medical examination and results evaluated by a physician on October 15, 2010. The reactor operator was enrolled in an initial license class in June 2011 in order to obtain an upgrade license to senior reactor operator. This circumstance resulted in the individual not being scheduled to have a physical examination in October 2011. The next medical examination was performed in October 2012; however, the physician did not complete evaluation of the medical examination until November 2, 2012, which exceeded the 2-year requirement. As such, this was a violation of 10 CFR 55.21.

The NRC determined this issue was a very low safety significance issue (Green). The inspectors determined that the failure to complete the operators medical examination review within the two-year timeframe did not adversely affect the safety of the facility because the October 2010 and 2012 physical examination results were satisfactory, with no change in medical status. In addition, during the operators time in initial license training, the individual was administratively restricted from license duties until completing the class and did not attend requal training or perform on-shift proficiency watches. As such, the NRC determined this to be an NCV.

The corrective actions included revising the licensee policy to disallow exemptions from the yearly license operator medical examination requirement for attendance in the Initial License Training class, documenting the issue in condition report (CAP 1392377), and performing an apparent cause evaluation.

• Title 10 CFR 55.25, Incapacitation Because Of Disability or Illness, requires, in part, that the licensee shall notify the NRC of a permanent change in medical status of licensed operators. Title 10 CFR 50.74(c), Notification of Change in Operator or Senior Operator Status, requires, in part, that the NRC shall be notified within 30 days of a permanent disability or illness. A licensed operator had a no-solo prescribed medication restriction on his license based on a medical condition. Subsequently, on November 12, 2012, the operators personal physician directed the individual to start decreasing intake of the medication over a three-month period. The operator notified the licensee medical department of the plan. A follow-up examination with the operators physician was to be scheduled on February 13, 2013, but was never made. In March 2013, as part of the treatment, the operator was directed to stop taking the medication by his physician. The operator notified the licensees medical department; however, the licensee made a late notification to the NRC on September 25, 2013. As such, this was a violation of 10 CFR 50.74(c).

The NRC determined this issue was a very low safety significance issue (Green). The inspectors determined that failure to report the stoppage of medication did not adversely affect the safety of the facility because the no-solo restriction was maintained on the license, the operator remained under the care of his/her personal physician and kept the licensee medical staff informed. As such, the NRC determined this to be an NCV.

The corrective actions included documenting the issue in a condition report (CAP 1398749), performing an apparent cause and completing an extent of condition review of all licensed operator medical records on September 27, 2013, to determine if additional shortfalls in recordkeeping had occurred as part of related medical issues documented in condition report (CAP 1384691).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

K. Fili, Site Vice President

H. Hanson. Jr., Plant Manager

P. Albares, Operations Manager

N. Haskell, Site Engineering Director

K. Jepson, Assistant Plant Manager

K. Petersen, Maintenance Manager

M. Holmes, Chemistry Manager

A. Zelie, Radiation Protection Manager

P. Kissinger, Regulatory Affairs Manager

T. Shortell, Training Manager

G. Allex, General Supervisor Operations Training

R. Becker, Operations Training Instructor

J. Jackson, Operations Training Instructor

B. Koenig, Operations Shift Manager

S. OConnor, Regulatory Affairs Analyst

M. Slack, Operations Training Supervisor

S. Spillum, Operations Training Supervisor

J. Yarbrough, Simulator Instructor

M. ODonnell, Project Engineer

J. Billard, Project Engineer

J. Becka, Project Supervisor

S. OConnor, Regulatory Analyst

L. Samson, Manager Spent Nuclear Fuel

• Licensee and Contractor Employees in Attendance during the October 4, 2013, ISFSI

Operational Interim Exit Meeting

Nuclear Regulatory Commission

K. Riemer, Chief, Branch 2, Division of Reactor Projects

Attachment

LIST OF ITEMS

Opened

200058/2013001-01 URI Dry Shielded Canister Liquid Penetrant Examination (Section 1R15)

05000263/2013005-01 NCV Failure to Follow Procedure for AO 13-22 Furmanite Injection (Section 1R19)

05000263/2013005-02 NCV SBLC Discharge Pressure Procedural Limits Exceeded (Section 1R22)

05000263/2013005-03 FIN Failure to Maintain Radiation Exposure ALARA During RFO 26 (Section 2RS2)

Closed

05000263/2013005-01 NCV Failure to Follow Procedure for AO 13-22 Furmanite Injection (Section 1R19)

05000263/2013005-02 NCV SBLC Discharge Pressure Procedural Limits Exceeded (Section 1R22)

05000263/2013005-03 FIN Failure to Maintain Radiation Exposure ALARA During RFO 26 (Section 2RS2)

Discussed

None.