IR 05000341/2014002

IR 05000341-14-002; on 01/01/2014 - 03/31/2014, Fermi Power Plant, Unit 2; Maintenance Effectiveness, Refueling and Other Activities, and Surveillance Testing

ML14114A741
Person / Time
Site:	Fermi
Issue date:	04/24/2014
From:	Michael Kunowski NRC/RGN-III/DRP/B5
To:	Plona J Detroit Edison, Co
References
IR-14-002
Download: ML14114A741 (52)

Text

UNITED STATES ril 24, 2014

SUBJECT:

FERMI POWER PLANT, UNIT 2 - NRC INTEGRATED INSPECTION REPORT 05000341/2014002

Dear Mr. Plona:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Fermi Power Plant, Unit 2. On April 9, 2014, the NRC inspectors discussed the results of this inspection with Mr. T. Conner and other members of your staff. The inspectors documented the results of the inspection in the enclosed inspection report.

The NRC inspectors documented 4 findings of very low safety significance (Green) in this report. These findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violations or significance of 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Fermi Power Plant.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement 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 Fermi Power Plant. Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last six months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter (IMC) 0310. Section 4OA5.2 of the enclosed report documents the conversion of these cross-cutting aspects, which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross-cutting aspect assigned, 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 Fermi Power Plant.

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, 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 NRCs Public Document Room or from the Publicly Available Records System (PARS)

component of NRCs Agencywide Documents 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/

Michael A. Kunowski, Chief Branch 5 Division of Reactor Projects Docket No. 50-341 License No. NPF-43

Enclosure:

Inspection Report 05000341/2014002 w/Attachment: Supplemental Information

REGION III==

Docket No: 50-341 License No: NPF-43 Report No: 05000341/2014002 Licensee: DTE Electric Company Facility: Fermi Power Plant, Unit 2 Location: Newport, MI Dates: January 1 through March 31, 2014 Inspectors: B. Kemker, Senior Resident Inspector P. Smagacz, Resident Inspector S. Bell, Health Physicist J. Jandovitz, Project Engineer Approved by: M. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000341/2014002; 01/01/2014 - 03/31/2014, Fermi Power Plant, Unit 2;

Maintenance Effectiveness, Refueling and Other Outage Activities, and Surveillance Testing.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Four Green findings, each of which had an associated non-cited violation (NCV), were identified. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP),

dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross-Cutting Areas, dated December 19, 2013. 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, December 2006.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance with an associated non-cited violation of 10 CFR 26.205(c) and (d) for the licensees failure to schedule and control the work hours of a covered worker directing and performing surveillance testing on a safety-related check valve during the refueling outage. Specifically, an engineer performing inservice testing was scheduled successive 12-hour shifts and was inappropriately excluded from the work hour limits specified in 10 CFR 26.205(d)(1) and (d)(2). As part of its corrective action, the licensee removed the engineer from covered work activities for the remainder of the refueling outage and reviewed the work activities of other engineers to ensure that any engineer performing covered work appropriately met work hour limits.

The finding was of more-than-minor significance since the failure to schedule and control the work hours of a worker performing covered work, if left uncorrected, would become a more significant safety concern because it could reasonably result in human performance errors that could affect the function of safety-related structures, systems, and components. Since the issue involved inservice testing on a safety-related emergency core cooling system check valve, the inspectors concluded this issue was associated with the Mitigating Systems Cornerstone. The finding was a licensee performance deficiency of very low safety significance because it: (1) was not a design or qualification deficiency; (2) did not represent an actual loss of function of a system; (3) did not represent an actual loss of function of a single train or two separate trains for greater than its Technical Specification (TS) allowed outage time; (4) did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant; and (5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors concluded this finding affected the cross-cutting area of human performance and the cross-cutting aspect of resources (H.1). Specifically, the engineer did not meet expectations regarding the performance of covered work activities because he did not challenge his role in directing the work activity and he assisted the maintenance craftsman while the craftsman attempted to exercise the check valve. In addition, licensee management inappropriately assigned the engineer responsibility for the test activity without ensuring he was in compliance with the 10 CFR 26.205 work hour requirements.

(Section 1R20.1.b.(1))

Cornerstone: Barrier Integrity

Green.

A finding of very low safety significance with an associated non-cited violation of 10 CFR 50.65(a)(2) was self-revealed on November 24, 2013, for the licensees failure to demonstrate that the performance of the temperature switches, steam traps, and drains of the reactor building heating, ventilation, and air conditioning (RBHVAC) system were effectively controlled through appropriate preventive maintenance or monitored as specified in 10 CFR 50.65(a)(1), such that the RBHVAC system remained capable of performing its intended function. The lack of preventive maintenance on these components for the RBHVAC system led to its failure and resulted in a loss of the safety function of secondary containment. Corrective actions included the creation of work orders to replace the remaining steam traps and reclassification of the steam traps and drains as Non-Critical in the licensees preventive maintenance program with annual preventive maintenance activities for cleaning scheduled prior to the heating season.

The finding was of more-than-minor significance since it was associated with the Structures,

Systems, and Components and Barrier Performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, inadequate preventive maintenance of the RBHVAC system components resulted in a trip of the system. Therefore, this performance deficiency had a direct effect on the licensees ability to maintain the safety function of secondary containment. The finding was a licensee performance deficiency of very low safety significance because it represented only a degradation of the radiological barrier function provided for the Reactor Building. This finding affected the cross-cutting area of problem identification and resolution and the cross-cutting aspect of trending (P.4). Specifically, over the past several years there were multiple trips of the RBHVAC system documented in the licensees corrective action program from failures of temperature switches, steam traps, and drains, including an event from January 22, 2013, that also resulted in a loss of the secondary containment function. The licensee failed to analyze this information in the aggregate to identify and correct the issue. (Section 1R12.1.b.(1))

Green.

The inspectors identified a finding of very low safety significance with an associated non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. The licensee failed to establish an adequate procedure to perform required stroke time testing for high pressure coolant injection turbine supply drain pot to main condenser drain line isolation valve E4100-F028. Specifically, the surveillance test procedure resulted in unacceptable preconditioning of the valve prior to the stroke time test measurement. The licensee entered this issue into its corrective action program for evaluation and initiated a corrective action to revise the test procedure.

The finding was of more-than-minor significance since it was associated with the Procedure Quality attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Because the preconditioning altered the as-found condition of the air-operated valve, the data collected through the performance of the surveillance test were not fully indicative of the true valve performance trend. Therefore, this performance deficiency had a direct effect on the licensees ability to trend as-found data for the purpose of assessing the reliability of the valve. The finding was a licensee performance deficiency of very low safety significance because it did not involve an actual open pathway in the physical integrity of the Auxiliary Building. The inspectors concluded that because the valve testing sequence that unacceptably preconditioned E4100-F028 had existed in the surveillance test procedure for greater than three years and no opportunity reasonably existed during that time to identify and correct it, this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified.

(Section 1R22.b.(1))

Green.

The inspectors identified a finding of very low safety significance with an associated non-cited violation of 10 CFR 50.55a. The licensee failed to perform required inservice testing of high pressure coolant injection and reactor core isolation cooling turbine supply drain pot to main condenser drain line isolation valves E4100-F029, E5150-F025, and E5150-F026. The licensee entered this issue into its corrective action program for evaluation, completed an immediate operability determination, and initiated a corrective action to revise applicable test procedures to incorporate inservice testing of the valves.

The finding was of more-than-minor significance since it was associated with the Structures,

Systems, and Components and Barrier Performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the licensees failure to perform required inservice testing had a direct effect on its ability to trend as-found performance data for the purpose of assessing the reliability of the three isolation valves, which are required by design to isolate seismically qualified portions of the piping systems from non-seismically qualified portions.

The finding was a licensee performance deficiency of very low safety significance because it did not involve an actual open pathway in the physical integrity of the Reactor and Auxiliary Buildings. The inspectors concluded that because the engineering evaluation that excluded the valves from inservice testing was completed in 1999 and no recent opportunity reasonably existed to identify and correct the error, this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified.

(Section 1R22.b.(2))

REPORT DETAILS

Summary of Plant Status

Fermi Power Plant, Unit 2, was operated at or near full power during the inspection period with the following exceptions:

• On January 13, the licensee reduced power to about 85 percent due to an elevated temperature on one of the two main power transformers.

• On January 18, the licensee reduced power to about 80 percent to perform control rod surveillance testing. The unit was returned to 85 percent power later that day.

• On February 10, the licensee removed the unit from service to commence the Cycle 16 refueling outage (F2RF16). Following a reactor power reduction to about 65 percent using flow, operators were not able to manually insert control rods due to a rod select logic circuit component failure in the reactor manual control system. The licensee completed the shutdown by inserting a manual reactor scram from about 65 percent power.

• On March 20, the licensee activated the Emergency Plan at the Alert level due to a small fire on an emergency diesel generator (EDG) exhaust manifold. Oil-soaked insulation on the exhaust manifold caught fire while the EDG was operating for testing. The fire was promptly extinguished. The unit remained stable during the event and no other plant systems were affected.

• On March 27, the licensee performed a reactor startup. The unit was operating at about 20 percent power at the end of the inspection period while the licensee performed troubleshooting of a problem affecting the main generator voltage regulator.

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition - Extreme Cold Conditions

a. Inspection Scope

Since extreme cold conditions were forecast in the vicinity of the plant for January and February 2014, the inspectors evaluated the licensees overall preparations/protection for the expected weather conditions focusing on the residual heat removal service water (RHRSW), diesel generator service water, emergency equipment service water, circulating water, general service water, and auxiliary boiler systems. The inspectors reviewed plant specific design features and implementation of procedures for responding to or mitigating the effects of extreme cold weather conditions on the operation of the plant. The inspectors observed insulation, heat trace circuits, space heater operation, and weatherized enclosures to ensure operability/functionality of affected systems. The inspectors also discussed potential compensatory measures with plant operators.

In addition, the inspectors verified adverse weather related problems were entered into the licensees corrective action program with the appropriate characterization and significance. Selected condition assessment resolution documents (CARDs) were reviewed to verify corrective actions were appropriate and implemented as scheduled.

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

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:

• Residual Heat Removal (RHR) Division 2 during planned maintenance on RHR Division 1;

• Non-Interruptible Air Supply (NIAS) Division 2 during planned maintenance on NIAS Division 1; and

• Division 1 RHR in the shutdown cooling mode of operation with Division 1 RHRSW and Emergency Equipment Cooling Water (EECW) in service.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones. The inspectors reviewed operating procedures, system diagrams, Technical Specification (TS) requirements, 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 available. The inspectors observed operating parameters and examined the material condition of the equipment to verify there were no obvious deficiencies.

In addition, the inspectors verified equipment alignment problems were entered into the licensees corrective action program with the appropriate characterization and significance. Selected CARDs were reviewed to verify corrective actions were appropriate and implemented as scheduled.

This inspection constituted three partial system walkdown inspection samples as defined in IP 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• RHR Complex - Division 1 Pump Room;

• RHR Complex - Division 2 Pump Room;

• RHR Complex - First Floor, EDG 14 and Fuel Oil Storage Tank Rooms; and

• Torus Room - Top of Torus.

The inspectors reviewed these 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 procedures. 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 that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. The inspectors verified fire hoses and extinguishers were in their designated locations and available for immediate use; fire detectors and sprinklers were unobstructed; transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition.

In addition, the inspectors verified fire protection related problems were entered into the licensees corrective action program with the appropriate characterization and significance. Selected CARDS were reviewed to verify corrective actions were appropriate and implemented as scheduled.

This inspection constituted four quarterly fire protection inspection samples as defined in IP 71111.05AQ.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From February 18 through February 28, the inspector conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system (RCS), risk-significant piping and components, and containment systems.

The inservice inspections described in Sections 1R08.1 and 1R08.2 below constituted one inspection sample as defined in IP 71111.08.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspector observed the following non-destructive examinations mandated by the American Society of Mechanical Engineer (ASME)Section XI Code to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• Ultrasonic examination of circumferential weld SW-E21-3147-15WG in the Containment Spray System, Report No. UT-S14-014;

• Visual, VT-3, examination of component support B31-5359-HB7 in the Feedwater System, Report No. VT-S14-027; and

• Magnetic particle examination of circumferential weld SW-E21-3147-15WG in the Containment Spray System, Report No. MT-S14-008.

The inspector reviewed the following examination record completed during the previous refueling outage with relevant/recordable conditions/indications accepted for continued service to determine if acceptance was in accordance with the ASME Code Section XI or an NRC-approved alternative:

• Spring load settings on support B21-5353-HB2 were found outside of tolerance (Report No. VT-S12-041 and CARD 12-23398).

The inspector reviewed records for the following pressure boundary weld repair completed for risk-significant systems during the last outage to determine if the licensee applied the pre-service non-destructive examinations and acceptance criteria required by the Construction Code, and/or the NRC-approved Code relief request. Additionally, the inspector reviewed the welding procedure specification and supporting weld procedure qualification records to determine whether the weld procedures were qualified in accordance with the requirements of the Construction Code and the ASME Code,Section IX.

• Work Order (WO) 32263661; Replace main steam drain line valve B21103F019.

b. Findings

No findings were identified.

.2 Identification and Resolution of Problems

a. Inspection Scope

The inspector performed a review of ISI-related problems entered into the licensees corrective action program and conducted interviews with licensee staff to determine if:

• the licensee had established an appropriate threshold for identifying ISI-related problems;

• the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

• the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspector performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

The inspectors observed licensed operators during simulator training on January 30. In preparation for the upcoming refueling outage, the licensee conducted just-in-time training of licensed operators for the plant shutdown evolution and transition to shutdown cooling operation. The inspectors assessed the operators performance focusing on alarm response, control board manipulations, command and control of crew activities, communication practices, and procedural adherence. An evaluated simulator training scenario for licensed operators was not performed during this quarter for the inspectors to observe.

This inspection constituted one quarterly licensed operator requalification program simulator inspection 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 February 10, the inspectors observed licensed operators in the Control Room performing a selected portion of the plant shutdown to begin the Cycle 16 refueling outage (F2RF16). On March 28, the inspectors observed licensed operators in the Control Room performing a selected portion of Infrequently Performed Test Evolution (IPTE) 13-11, North Reactor Feedwater Pump Testing, during plant startup at the conclusion of the refueling outage. The activities required heightened awareness and additional detailed planning, and involved increased operational 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 (or equipment) manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions.

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

This inspection constituted one quarterly licensed operator heightened activity/risk inspection 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 the licensee's handling of selected degraded performance issues involving the following risk-significant structures, systems, and components (SSCs):

• CARD 13-26959; Unable to Place Center Offgas Chiller in Service due to Probable Logic Card Problem (Repeat Issue); and

• CARD 13-28350; Reactor Building Heating, Ventilation, and Air Conditioning (RBHVAC) Trip on Low Freeze-Stat Temperature.

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the SSCs. Specifically, the inspectors independently verified the licensee's handling of SSC performance or condition problems in terms of:

• appropriate work practices;

• identifying and addressing common cause failures;

• scoping of SSCs in accordance with 10 CFR 50.65(b);

• characterizing SSC reliability issues;

• tracking SSC unavailability;

• trending key parameters (condition monitoring);

• 10 CFR 50.65(a)(1) or (a)(2) classification and reclassification; and

• appropriateness of performance criteria for SSC functions classified (a)(2) and/or appropriateness and adequacy of goals and corrective actions for SSC functions classified (a)(1).

In addition, the inspectors verified problems associated with the effectiveness of plant maintenance were entered into the licensee's corrective action program with the appropriate characterization and significance. Selected CARDS were reviewed to verify corrective actions were appropriate and implemented as scheduled.

This inspection constituted two maintenance effectiveness inspection samples as defined in IP 71111.12.

b. Findings

(1) Failure to Perform Appropriate Preventive Maintenance on Reactor Building Heating, Ventilation, and Air Conditioning Components

Introduction:

A finding of very low safety significance with an associated NCV of 10 CFR 50.65(a)(2) was self-revealed on November 24, 2013, for the licensees failure to demonstrate that the performance of the temperature switches, steam traps, and drains of the RBHVAC system were effectively controlled through appropriate preventive maintenance or monitored as specified in 10 CFR 50.65(a)(1), such that the RBHVAC system remained capable of performing its intended function. The lack of preventive maintenance on these components for the RBHVAC system led to its failure and resulted in a loss of the safety function of secondary containment.

Description:

On November 24, 2013, with the unit operating at or near full power, the RBHVAC system tripped. Secondary containment differential pressure rose above the TS limit of greater than or equal to 0.125 inch of vacuum water gauge (-0.125 inch water gauge.), reaching a maximum of +0.08 inch water gauge. Within about 3 minutes, operators manually started the standby gas treatment system (SGTS), and secondary containment differential pressure was restored below the TS limit.

The nonsafety-related RBHVAC system is used during normal plant operations to maintain secondary containment pressure. The RBHVAC system is not relied upon to mitigate the consequences of an accident. Secondary containment, in conjunction with the safety-related SGTS, is designed to minimize the release of radioactive material in the event of a significant accident. The RBHVAC system has 14 steam coil heaters and 14 corresponding low temperature switches. The temperature switches monitor the temperature of the heater coils to ensure they do not freeze. If any switch trips on low temperature, the RBHVAC system automatically trips.

The licensee initiated CARD 13-28350 to document the RBHVAC system trip and to identify the cause of the event. Due to improper drainage of a steam coil heater through its steam trap, the RBHVAC temperature switch tripped, resulting in a trip of the system.

The licensees investigation revealed a cracked drain seat with corrosion in the associated steam drain. Since the SGTS does not have an automatic initiation function on the loss of RBHVAC, secondary containment pressure began to rise, subsequently exceeding the TS limit of -0.125 inch water gauge and resulting in a loss of safety function of the secondary containment. The licensee replaced the failed steam trap, returned the RBHVAC system to operation, and returned the SGTS to a normal standby condition.

The licensee completed an equipment apparent cause evaluation (EACE) for the trip of the RBHVAC system. The EACE identified three causal factors:

• The RBHVAC steam coil traps were incorrectly classified as run-to-fail components in the licensees preventive maintenance program;

• There were no preventive maintenance activities performed on the RBHVAC steam drains; and

• Annual performance monitoring of the steam drains was not performed at the optimal times.

The licensee also completed an apparent cause evaluation (ACE). The ACE expounded on the conclusions of the EACE and identified two apparent causes:

• The most probable cause was that the drain seat was corroded closed.

• The maintenance strategy for the RBHVAC heating coils steam drains was inadequate due to an incorrect preventive maintenance classification.

The inspectors reviewed the licensees evaluations and concurred with the conclusions.

The inspectors noted that the RBHVAC system was included in the scope of the licensees Maintenance Rule Program and was monitored. However, not all RBHVAC system components were being effectively controlled through the process, such as the temperature switches, steam traps, and drains. Previous issues with these system components were identified, but mostly through their failure causing trips of the RBHVAC system. After each failure, the licensee performed broke/fix repairs, without further review of the preventive maintenance practices for the system, despite roughly one failure of these RBHVAC system components per year since 2006. As recently as January 2013, the licensee reported a loss of safety function of the secondary containment due to a trip of the RBHVAC system in Licensee Event Report (LER)05000341/2013-001-00, Loss of Secondary Containment Function.

Corrective actions completed by the licensee included the creation of work orders to replace the remaining steam traps and reclassification of the steam traps and drains as Non-Critical in its preventive maintenance program with annual preventive maintenance activities for cleaning scheduled prior to the heating season. The temperature switches were already classified as Non-Critical components.

The licensee submitted LER 05000341/2013-003-00, Loss of Secondary Containment Function Due to Exceedance of Technical Specification Required Vacuum Pressure, to report this event in accordance with 10 CFR 50.73(a)(2)(v)(C) as a loss of safety function of a structure required to control the release of radioactive material. Refer to Section 4OA3.2 of this inspection report for the inspectors review of the LER.

Analysis:

The inspectors determined the licensees failure to demonstrate the performance of the temperature switches, steam traps, and drains of the RBHVAC system were effectively controlled through appropriate preventive maintenance in accordance with 10 CFR 50.65(a)(2) or monitored as specified in 10 CFR 50.65(a)(1),was a performance deficiency warranting a significance evaluation. The inspectors assessed this finding using the Significance Determination Process (SDP). The inspectors reviewed the examples of minor issues in Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, dated August 11, 2009, and found no examples related to this issue.

Consistent with the guidance in IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined the finding was associated with the Structures, Systems, and Components and Barrier Performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, inadequate preventive maintenance of the RBHVAC system temperature switches, steam traps, and drains resulted in a trip of the system because of a corroded and cracked steam trap.

Therefore, this performance deficiency had a direct effect on the licensees ability to maintain the safety function of secondary containment. The inspectors performed a significance screening of this finding using the guidance provided in IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. In accordance with Exhibit 3, Barrier Integrity Screening Questions, the inspectors determined this finding was a licensee performance deficiency of very low safety significance (Green) because it represented only a degradation of the radiological barrier function provided for the Reactor Building.

The inspectors concluded this finding affected the cross-cutting area of problem identification and resolution and the cross-cutting aspect of trending (P.4). Specifically, over the past several years there were multiple trips of the RBHVAC system documented in the licensees corrective action program from failures of temperature switches, steam traps, and drains, including an event from January 22, 2013, that also resulted in a loss of the secondary containment function. The licensee failed to analyze this information in the aggregate to identify and correct the issue.

Enforcement:

10 CFR 50.65(a)(1) requires, in part, that each holder of an operating license monitor the performance or condition of SSCs within the scope of the monitoring program 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.

10 CFR 50.65(a)(2) states, in part, that monitoring as specified in paragraph (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, as of November 24, 2013, the licensee failed to demonstrate the performance or condition of the RBHVAC system had been effectively controlled through the performance of appropriate preventive maintenance and did not monitor against licensee-established goals. Specifically RBHVAC system temperature switches, steam traps, and drains were inappropriately treated as run-to-failure components in the licensees preventive maintenance program, resulting in inadequate and untimely maintenance being performed on these system components, causing multiple system failures. This demonstrates the performance or condition of the system was not being effectively controlled through the performance of appropriate preventive maintenance and, as a result, that goal setting and monitoring was required. Because of the very low safety significance, this violation is being treated as an NCV consistent with Section 2.3.2.a of the NRC Enforcement Policy (NCV 05000341/2014002-01, Failure to Perform Appropriate Preventive Maintenance on Reactor Building Heating, Ventilation, and Air Conditioning Components). The licensee entered this violation into its corrective action program as CARD 13-28350.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• CARD 14-20090, Reactor Recirculation Motor Generator Set B Exciter Overcurrent Relay Anomaly;

• CARD 14-20230, Hot Spot Developed on Gasket for Main Unit Transformer 2B; and

• CARD 14-20240, Water Leak Observed from Division 2 RHRSW.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each of the above activities, the inspectors reviewed the scope of maintenance work in the plants daily schedule, reviewed Control Room logs, verified plant risk assessments were completed as required by 10 CFR 50.65(a)(4) prior to commencing maintenance activities, discussed the results of the assessment with the licensees Probabilistic Risk Analyst and/or Shift Technical Advisor, and verified plant conditions were consistent with the risk assessment assumptions. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid, redundant safety-related plant equipment necessary to minimize risk was available for use, and applicable requirements were met.

In addition, the inspectors verified maintenance risk-related problems were entered into the licensees corrective action program with the appropriate significance characterization. Selected CARDs were reviewed to verify corrective actions were appropriate and implemented as scheduled.

This inspection constituted three maintenance risk assessments inspection samples as defined in IP 71111.13.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following issues:

• CARD 14-20055, Could Not Throttle P4400F633B to Establish Pressure Band;

• CARD 14-20053, EECW Cross-Tie Valve Stroke Time Outside IST [Inservice Testing] Limit; and

• CARD 14-22456, EDG 11 and EDG 12 Surveillances Will Exceed Critical Date.

The inspectors selected these potential operability/functionality issues based on the risk significance of the associated components and systems. The inspectors verified the conditions did not render the associated equipment inoperable or result in an unrecognized increase in plant risk. When applicable, the inspectors verified the licensee appropriately applied TS limitations, appropriately returned the affected equipment to an operable status, and reviewed the licensees evaluation of the issue with respect to the regulatory reporting requirements. 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 evaluation. When applicable, the inspectors also verified the licensee appropriately assessed the functionality of SSCs that perform specified functions described in the Updated Final Safety Analysis Report (UFSAR), Technical Requirements Manual, Emergency Plan, Fire Protection Plan, regulatory commitments, or other elements of the current licensing basis when degraded or nonconforming conditions were identified.

In addition, the inspectors verified problems related to the operability or functionality of safety-related plant equipment were entered into the licensees corrective action program with the appropriate characterization and significance. Selected CARDs were reviewed to verify corrective actions were appropriate and implemented as scheduled.

This inspection constituted three operability determination inspection samples as defined in IP 71111.15.

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

.1 Temporary Modifications

a. Inspection Scope

The inspectors reviewed the following plant temporary modification:

• Temporary Modification 14-002, Weld Repair on 24-Inch Elbow Downstream of RHR Division 2 Heat Exchanger on Return Line to the RHRSW Reservoir.

The inspectors reviewed the temporary modification and the associated 10 CFR 50.59 screening/evaluation against applicable system design basis documents, including the UFSAR and the TS, to verify whether applicable design basis requirements were satisfied. The inspectors reviewed the Control Room logs and interviewed engineering and operations department personnel to understand the impact that implementation of the temporary modification had on operability and availability of the affected system.

In addition, the inspectors verified problems related to the installation of temporary plant modifications were entered into the licensees corrective action program with the appropriate characterization and significance. Selected CARDs were reviewed to verify corrective actions were appropriate and implemented as scheduled.

This inspection constituted one temporary modification inspection sample as defined in IP 71111.18.

b. Findings

No findings were identified.

.2 Permanent Modifications

a. Inspection Scope

The inspectors reviewed the engineering analyses, modification documents, and design change information associated with the following permanent plant modification:

• Engineering Design Package (EDP) 37099, Install New High Point Vent on Division 1 Core Spray Piping.

During this inspection, the inspectors evaluated the implementation of the design modification and verified, as appropriate:

• The compatibility, functional properties, environmental qualification, seismic qualification, and classification of materials and replacement components were acceptable;

• The structural integrity of the SSCs would be acceptable for accident/event conditions;

• The implementation of the modification did not impair key safety functions;

• No unintended system interactions occurred;

• The affected significant plant procedures, such as normal, abnormal, and emergency operating procedures, testing and surveillance procedures, and training were identified and necessary changes were completed;

• The design and licensing documents were either updated or were in the process of being updated to reflect the modification;

• The changes to the facility and procedures, as described in the UFSAR, were appropriately reviewed and documented in accordance with 10 CFR 50.59;

• The system performance characteristics, including energy needs affected by the modification continued to meet the design basis;

• The modification test acceptance criteria were met; and

• The modification design assumptions were appropriate.

Completed activities associated with the implementation of the modification, including testing, were also inspected, and the inspectors discussed the modification with the responsible engineering and operations staff.

In addition, the inspectors verified problems related to the installation of permanent plant modifications were entered into the licensees corrective action program with the appropriate characterization and significance. Selected CARDs were reviewed to verify corrective actions were appropriate and implemented as scheduled.

This inspection constituted one permanent modification inspection samples as defined in IP 71111.18.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

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

• WO 37056898, Perform 43.401.218 Local Leak Rate Testing for Relief Valve Flanges Test-2, E1100F025B, and WO 34462587, Perform ASME As-Found and As-Left Relief Valve Testing, E2100F011B;

• WO 37909435, Post Maintenance Test on Division 2 RHRSW after Temporary Code Repair, CARD 14-20240, Water Leak Observed from Division 2 RHRSW;

• WO 31870951, Replace Motor for T4804F603A;

• WO 3904983, Water Leak Observed from Division 2 RHRSW;

• WO 34357899, B2100F076B Disassemble and Inspect - Replace Disc Soft Seat, and WO 34357519, Perform 43.401.304 Local Leak Rate Testing for Penetration X-9B;

• WO 34690215, Replace Snubber B2113G001B, and WO 34590231, Replace Snubber B2113G002B;

• WO 34327217, SLC [Standby Liquid Control] Explosive (Squib) Valve, WO 4393614 and WO 34421946, SLC Pump C4103C001A/B Disc Press Relief Valve;

• WO 34372921, EECW Division 2 Miscellaneous Valve Operability Test;

• WO 38091156, Perform 43.401.516 RHR Pressure Isolation Valve Leakage Test; and

• WO 37878316, Perform 27.107.03; North Reactor Feedwater Pump Turbine Overspeed Trip Test.

The inspectors reviewed the scope of the work performed and evaluated the adequacy of the specified post-maintenance testing. The inspectors verified the post-maintenance testing was performed in accordance with approved procedures; the procedures contained clear acceptance criteria, which demonstrated operational readiness, and the acceptance criteria was met; appropriate test instrumentation was used; the equipment was returned to its operational status following testing; and the test documentation was properly evaluated.

In addition, the inspectors verified post-maintenance testing problems were entered into the licensees corrective action program with the appropriate characterization and significance. Selected CARDs were reviewed to verify corrective actions were appropriate and implemented as scheduled.

This inspection constituted ten post-maintenance testing inspection samples as defined in IP 71111.19.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Unit 2 Refueling Outage (F2RF16)

a. Inspection Scope

The inspectors evaluated the licensee's conduct of F2RF16 refueling outage activities to assess the control of plant configuration and management of shutdown risk. The inspectors reviewed configuration management to verify the licensee maintained defense-in-depth commensurate with the shutdown risk plan; reviewed major outage work activities to ensure correct system lineups were maintained for key mitigating systems; and observed refueling activities to verify fuel handling operations were performed in accordance with the TSs and approved procedures. Other major outage activities evaluated included the licensee's control of the following:

• containment penetrations in accordance with the TSs;

• SSCs that could cause unexpected reactivity changes;

• flow paths, configurations, and alternate means for RCS inventory addition;

• SSCs (e.g., control rod drive mechanism replacements) that could cause a loss of inventory;

• RCS level instrumentation;

• radiological work practices;

• fatigue management, as required by 10 CFR 26, Subpart I;

• spent fuel pool cooling during and after core offload;

• switchyard activities and the configuration of electrical power systems in accordance with the TSs and shutdown risk plan; and

• SSCs required for decay heat removal and for establishing alternate means for decay heat removal, including instrumentation.

The inspectors verified the licensee appropriately established plant conditions and satisfied TS requirements prior to and while performing operations with the potential to drain the reactor vessel activities.

The inspectors observed portions of the plant cooldown, including the transition to shutdown cooling, to verify the licensee controlled the plant cooldown in accordance with the TSs. The inspectors also observed portions of the restart activities including reactor startup and plant heat up to verify TS requirements and administrative procedure requirements were met prior to changing operational modes or plant configurations.

Major restart inspection activities performed included:

• verification that RCS boundary leakage requirements were met prior to entry into Mode 3 and subsequent operational mode changes;

• emergency core cooling system (ECCS) filling and venting to ensure no large air voids remained that could affect ECCS pump performance during loss-of-coolant accident conditions;

• verification that primary and secondary containment integrity was established prior to entry into Mode 3; and

• inspection of the drywell to assess material condition and search for loose debris, which, if present, could block floor drains or be transported to the containment suppression pool.

The inspectors interviewed operations, engineering, work control, radiological protection, and maintenance department personnel and reviewed selected procedures and documents.

In addition, the inspectors reviewed a sample of issues that the licensee entered into the corrective action program related to outage activities to verify identified problems were being entered with the appropriate characterization and significance. The inspectors also reviewed the licensee's corrective actions for refueling outage issues documented in selected CARDS.

This inspection constituted one refueling outage inspection sample as defined in IP 71111.20.

b. Findings

(1) Failure to Control the Work Hours of a Covered Worker

Introduction:

The inspectors identified a finding of very low safety significance with an associated NCV of 10 CFR 26.205(c) and

(d) for the licensees failure to schedule and control the work hours of a covered worker directing and performing surveillance testing on a safety-related ECCS check valve during the refueling outage. Specifically, an engineer performing inservice testing was scheduled successive 12-hour shifts and was inappropriately excluded from the work hour limits specified in 10 CFR 26.205(d)(1) and (d)(2).

Description:

On March 1, the inspectors observed inservice testing of Division 2 core spray injection check valve E2100-F006B, which was accomplished in accordance with procedure 43.401.712, Division 2 Core Spray Injection Check Valve Exercise Test, Revision 6. The inspectors noted there were several workers involved with the performance of the testing, including an engineer who exercised control of the work activity. The inspectors noted the engineer was directly involved in the execution of the maintenance activity and directly assisted a maintenance craftsman while the craftsman attempted to exercise the check valve with a socket wrench. Based on discussions with the engineer and direct observation of the testing, the inspectors questioned licensee management whether the engineers work hours were appropriately scheduled and controlled as required by 10 CFR 26.205(c) and (d), since it appeared he had been directing and performing work covered under 10 CFR 26.205(a).

In response to the inspectors questions, the licensee determined the engineer had been performing covered work, but had not been appropriately scheduled work hours to comply with the requirements of 10 CFR 26.205. The covered work involved both the direction and performance of the work activity. Upon discovery, the licensee removed the engineer from covered work activities for the remainder of the refueling outage and reviewed the work activities of other engineers to ensure any engineer performing covered work appropriately met work hour limits. The licensee concluded there were no other engineers whose work hours were not appropriately controlled while assigned to perform work covered under 10 CFR 26.205(a) and the inspectors identified no additional examples. During its review, the licensee determined the engineer had also directed and performed one other covered work activity (i.e., the Division 1 core spray injection check valve exercise test on February 23).

From February 7 through March 1, the engineer mostly worked successive 12-hour shifts. During this 23-day period, he worked an average of 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> and 40 minutes each day up to a maximum of 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> and 45 minutes. As a result, the engineers work hours exceeded 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour period, 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> in any 48-hour period, and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period. In addition, the engineer was not provided a 34-hour break every 9 days and on at least one occasion did not have a 10-hour break between successive work periods.

The inspectors reviewed the licensees condition evaluation of this issue. The licensee attributed the failure to appropriately control the engineers work hours to personal accountability. The licensee concluded the engineer did not meet expectations regarding the performance of covered work activities because he did not challenge his role in directing the work activity and he assisted the maintenance craftsman while the craftsman attempted to exercise the check valve. Prior to the refueling outage, the engineer was informed during an engineering department briefing of the expectation not to perform covered work.

Analysis:

The inspectors determined the failure to schedule and control the work hours of a worker performing work covered under 10 CFR 26.205(a) was a licensee performance deficiency warranting a significance evaluation. The inspectors assessed this finding using the SDP. The inspectors reviewed the examples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, and found two examples related to worker fatigue. However, both of these examples involved individual occurrences where waivers were inappropriately utilized rather than a failure to schedule and control the work hours for a covered worker.

Consistent with the guidance in IMC 0612, Appendix B, Issue Screening, the inspectors determined the failure to schedule and control the work hours of a worker performing covered work, if left uncorrected, would become a more significant safety concern because it could reasonably result in human performance errors that could affect the function of safety-related SSCs. Since the issue involved inservice testing on a safety-related ECCS check valve, the inspectors concluded this issue was associated with the Mitigating Systems Cornerstone. The inspectors performed a significance screening of this finding using the guidance provided in IMC 0609, Significance Determination Process, Appendix A, The SDP for Findings At-Power. In accordance with Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined this finding was a licensee performance deficiency of very low safety significance (Green)because the finding:

(1) was not a design or qualification deficiency;

(2) did not represent an actual loss of function of a system;

(3) did not represent an actual loss of function of a single train or two separate trains for greater than its TS allowed outage time;

(4) did not represent an actual loss of function of one or more non-TS trains of equipment designated as high safety significant; and

(5) did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

The inspectors concluded this finding affected the cross-cutting area of human performance and the cross-cutting aspect of resources (H.1). Specifically, the engineer did not meet expectations regarding the performance of covered work activities because he did not challenge his role in directing the work activity and he assisted the maintenance craftsman while the craftsman attempted to exercise the check valve. In addition, licensee management inappropriately assigned the engineer responsibility for the test activity without ensuring he was in compliance with the 10 CFR 26.205 work hour requirements.

Enforcement:

10 CFR 26.205(a) states, in part, Any individual who performs duties identified in Paragraphs 26.4(a)(1) through (a)(5) shall be subject to the requirements of this section.

10 CFR 26.4(a)(4) identifies individuals who are Performing maintenance or onsite directing of the maintenance of SSCs that a risk-informed evaluation process has shown to be significant to public health and safety.

10 CFR 26.205(c) states, in part, Licensees shall schedule the work hours of individuals who are subject to this section consistent with the objective of preventing impairment from fatigue due to the duration, frequency, or sequencing of successive shifts.

10 CFR 26.205(d)(1) states, in part, Licensees shall ensure that any individuals work hours do not exceed the following limits:

(i) 16 work hours in any 24-hour period;

(ii) 26 work hours in any 48-hour period; and (iii) 72 work hours in any 7-day period.

10 CFR 26.205(d)(2) states, in part, Licensees shall ensure that individuals have, at a minimum,

(i) A 10-hour break between successive work periods; and

(ii) A 34-hour break in any 9-day period.

Contrary to the above, on March 1, 2014, an individual who performed duties identified in 10 CFR 26.4(a)(4) was not subject to the requirements of 10 CFR 26.205(a) and, therefore, not accordingly scheduled work hours as required by 10 CFR 26.205(c).

Specifically, the individual performed and directed maintenance on safety-related check valve E2100-F006B and was inappropriately excluded from the work hour limits specified in 10 CFR 26.205(d)(1)(i) thru (iii) and 10 CFR 26.205(d)(2)(i) thru (ii). As a result, the individuals work hours exceeded 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour period, 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> in any 48-hour period, and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period. In addition, the individual was not provided a 34-hour break every 9 days and, on at least one occasion, did not have a 10-hour break between successive work periods. Because of the very low safety significance, this violation is being treated as an NCV consistent with Section 2.3.2.a of the NRC Enforcement Policy (NCV 05000341/2014002-02, Failure to Control the Work Hours of a Covered Worker). The licensee entered this violation into its corrective action program as CARD 14-21866.

1R22 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:

• Unresolved Item (URI)05000341/2013005-04, Evaluation of Apparent Unacceptable Preconditioning of High Pressure Coolant Injection System Air Operated Valve Prior to Stroke Time Testing (inservice testing);

• Procedure 43.401.711, Division 1 Core Spray Injection Check Valve Exercise Test (inservice testing);

• Procedure 43.401.712, Division 2 Core Spray Injection Check Valve Exercise Test (inservice testing);

• Procedure 44.030.051, ECCS - RHR (LPCI [Low Pressure Coolant Injection]

Mode), Division 2 Logic Functional Test (routine surveillance);

• Procedure 43.401.500, Local Leak Rate Testing for Penetration X-7A, X-7B, X-7C, and X-7D (primary containment isolation valve testing);

• Procedure 47.000.84, Local Leak Rate Testing for Equipment and Floor Drain Check Valves (Sump Floor Drain Check Valves) (inservice testing);

• Procedure 43.401.514, HPCI [High Pressure Coolant Injection] Pressure Isolation Valve Leakage Test (primary containment isolation valve testing);

• Procedures 43.401.303, Local Leak Rate Testing for Penetration X-9A; and 43.401.304, Local Leak Rate Testing for Penetration X-9B (primary containment isolation valve testing);

• Procedure 43.401.306, Local Leak Rate Testing for Penetration X-11 (primary containment isolation valve testing);

• Procedure 24.307.03, EDG 13 - Loss of Offsite Power and ECCS Start with Loss of Offsite Power Test, (routine surveillance); and

• Procedure 24.206.04; RCIC [Reactor Core Isolation Cooling] System Automatic Actuation and Flow Test, Section 5.1, RCIC Flow Test at 150 psig, (routine surveillance).

The inspectors observed selected portions of the test activities to verify the testing was accomplished in accordance with plant procedures. The inspectors reviewed the test methodology and documentation to verify equipment performance was consistent with safety analyses and design basis assumptions, 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, and appropriate testing acceptance criteria were satisfied. When applicable, the inspectors also verified test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable.

In addition, the inspectors verified surveillance testing problems were entered into the licensees corrective action program with the appropriate characterization and significance. Selected CARDs were reviewed to verify that corrective actions were appropriate and implemented as scheduled.

This inspection constituted three routine surveillance tests, four inservice tests, and four primary containment isolation valve tests for a total of eleven surveillance testing inspection samples as defined in IP 71111.22.

b. Findings

(1) Unacceptable Preconditioning of HPCI Air-Operated Valve Prior to Stroke Time Test Measurement (Closed) URI 05000341/2013005-04, Evaluation of Apparent Unacceptable Preconditioning of High Pressure Coolant Injection System Air-Operated Valve Prior to Stroke Time Testing

Introduction:

The inspectors identified a finding of very low safety significance with an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. The licensee failed to establish an adequate procedure to perform required stroke time testing for HPCI turbine supply drain pot to main condenser drain line isolation valve E4100-F028. Specifically, the surveillance test procedure resulted in unacceptable preconditioning of the valve prior to the stroke time test measurement.

Description:

On August 26, 2013, the inspectors observed portions of surveillance test procedure 24.202.01, HPCI Pump and Valve Operability Test at 1025 PSI [Pounds per Square Inch], and subsequently reviewed the test results. This surveillance test procedure was performed, in part, to satisfy the IST program requirements in TS 5.5.6 and 10 CFR 50.55a(f), Inservice testing requirements.

The inspectors noted that the redundant HPCI turbine supply drain pot to main condenser drain line isolation valves (E4100-F028 and E4100-F029) automatically close when the HPCI turbine was started. These two normally open valves were required by design to close upon HPCI turbine start to isolate seismically qualified portions of the piping system from non-seismically qualified portions to mitigate the consequences of an accident since the HPCI system was considered to be a closed system in connection with the RCS outside of the containment. The valves were verified closed at step 5.1.49 of the test procedure after the HPCI turbine was started. After the HPCI turbine was secured, E4100-F028 and E4100-F029 were then reopened at steps 5.1.104 and 5.1.105, respectively. At step 5.1.109, E4100-F028 was then closed and its stroke time measured. No stroke time testing of E4100-F029 was performed since the licensee had excluded the valve from its IST program because it had concluded the valve did not perform a safety function in either the open or closed position.

The inspectors questioned whether the test sequence inappropriately preconditioned E4100-F028 prior to its stroke time measurement since the valve closed when the HPCI turbine started and was then manually reopened after the HPCI turbine was secured.

Cycling this air-operated valve (AOV) prior to measuring its stroke time masked the as-found condition and did not appear necessary to place the system in the configuration for testing. It also appeared to the inspectors that a stroke time measurement could have been performed prior to running the HPCI turbine by manually cycling the valve closed and open. In addition, the inspectors questioned the exclusion of the redundant isolation valve (E4100-F029) from the licensees IST program since it appeared to have the same design function as E4100-F028.

The inspectors noted that Inspection Manual Technical Guidance Part 9900 defines unacceptable preconditioning, in part, as: The alteration, variation, manipulation, or adjustment of the physical condition of an SSC before or during TS surveillance or ASME Code testing that will alter one or more of an SSCs operational parameters, which results in acceptable test results. Such changes could mask the actual as-found condition of the SSC and possibly result in an inability to verify the operability of the SSC. In addition, unacceptable preconditioning could make it difficult to determine whether the SSC would perform its intended function during an event in which the SSC might be needed. The Part 9900 Technical Guidance further states that influencing a test outcome by performing valve stroking does not meet the intent of the as-found testing expectations described in NUREG-1482, Guidelines for Inservice Testing at Nuclear Power Plants, (April 1995), and may be unacceptable. The NUREG-1482 guidance has not changed in this respect with the latest revision in October 2013.

The inspectors also noted that cycling an AOV prior to performing an as-found stroke time test measurement would not be in accordance with the licensees procedural guidance. MOP03, Operations Conduct Manual, Enclosure E, Position Paper Defining the Fermi 2 Policy on Preconditioning, Revision 35, states, in part, AOVs shall be stroke timed on the first stroke of a functional surveillance test .... Basis: Timing a stroke other than the first one constitutes preconditioning because the first stroke of an air operated valve after an extended period is typically longer than the following strokes.

The Part 9900 Technical Guidance states that some types of preconditioning may be considered acceptable, but this preconditioning should have been evaluated and documented in advance of the surveillance. Since the licensee had not performed an evaluation to justify that preconditioning of the valve was acceptable prior to completing the testing, the inspectors questioned whether the licensees surveillance testing sequence that cycled the valve prior to obtaining stroke time data constituted unacceptable preconditioning of the valve.

In response to the inspectors questions, the licensee wrote CARD 13-26877 to evaluate the preconditioning concern. The licensee then completed an engineering evaluation and concluded that E4100-F028 was unacceptably preconditioned by the test procedure since it was not tested in the as-found condition. The inspectors reviewed the licensees evaluation and concurred with this conclusion. Based on the performance of functional testing that verified E4100-F028 properly closed and opened during the quarterly pump and valve surveillance test, the inspectors concluded that a reasonable basis existed to support continued operability of the valve.

The licensee also reviewed the inspectors questions regarding testing E4100-F029 under its IST program and determined this valve should also have been tested. Refer to Section 1R22.b.(2) below for further discussion of this issue.

The licensee initiated a corrective action to revise surveillance test procedure 24.202.01 to perform stroke time measurements of E4100-F028 and E4100-F029 prior to starting the HPCI turbine.

Analysis:

The inspectors determined the licensees failure to establish an adequate surveillance test procedure to perform required stroke time testing for HPCI turbine supply drain pot to main condenser drain line isolation valve E4100-F028 under suitable environmental conditions was a performance deficiency warranting a significance evaluation. The inspectors assessed this finding using the SDP. The inspectors reviewed the examples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, and found no examples related to this issue. Consistent with the guidance in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined the finding was associated with the Procedure Quality attribute and adversely affected the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Specifically, cycling the AOV prior to performing the stroke time measurement masked the actual as-found condition of the valve, invalidating the test results. Because the preconditioning altered the as-found condition of the valve, the data collected through the performance of the surveillance test were not fully indicative of the true valve performance trend. Therefore, this performance deficiency had a direct effect on the licensees ability to trend as-found data for the purpose of assessing the reliability of the valve. The inspectors performed a significance screening of this finding using the guidance provided in IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process for Findings At-Power. In accordance with Exhibit 3, Barrier Integrity Screening Questions, the inspectors determined this finding was a licensee performance deficiency of very low safety significance (Green) because it represented only a degradation of the radiological barrier function provided for the Auxiliary Building and was not an actual loss of the barrier function provided by the HPCI system pressure boundary as a closed system outside containment.

The inspectors concluded that because the valve testing sequence that unacceptably preconditioned E4100-F028 had existed in the surveillance test procedure for greater than three years and no opportunity reasonably existed during that time to identify and correct it, this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified.

Enforcement:

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality 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.

10 CFR 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program be established to assure all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents.

Test procedures shall include provisions for assuring all prerequisites for the given test have been met and the test is performed under suitable environmental conditions.

Contrary to the above, surveillance test procedure 24.202.01, HPCI Pump and Valve Operability Test at 1025 PSI, Revision 102, was not appropriate to the circumstances because it did not ensure stroke time testing of HPCI turbine supply drain pot to main condenser drain line isolation valve E4100-F028 on August 26, 2013, was performed under suitable environmental conditions. Specifically, step 5.1.109 of the test procedure directed stroke time measurement of the valve in the closed position after it had already cycled closed during testing of the HPCI turbine. This preconditioned E4100-F028 prior to conducting the stroke time measurement. Because of the very low safety significance, this violation is being treated as an NCV consistent with Section 2.3.2.a of the NRC Enforcement Policy (NCV 05000341/2014002-03, Unacceptable Preconditioning of High Pressure Coolant Injection System Air-Operated Valve Prior to Stroke Time Test Measurement). The licensee entered this violation into its corrective action program as CARD 13-26877.

URI 05000341/2013005-04 is closed.

(2) Failure to Perform Inservice Testing of HPCI and RCIC Valves

Introduction:

The inspectors identified a finding of very low safety significance with an associated NCV of 10 CFR 50.55a. The licensee failed to perform required inservice testing of HPCI and RCIC turbine supply drain pot to main condenser drain line isolation valves E4100-F029, E5150-F025, and E5150-F026.

Description:

On August 26, 2013, the inspectors observed portions of surveillance test procedure 24.202.01, HPCI Pump and Valve Operability Test at 1025 PSI, and subsequently reviewed the test results. In addition, on November 13, 2013, the inspectors observed portions of surveillance test procedure 24.206.01, RCIC System Pump and Valve Operability Test, and subsequently reviewed the test results.

These surveillance test procedures were performed, in part, to satisfy the IST program requirements in TS 5.5.6 and 10 CFR 50.55a(f), Inservice testing requirements.

During review of the surveillance test procedures, the inspectors posed numerous questions to the licensee regarding the sequence of valve stroke time testing and the scoping of HPCI and RCIC system components within its IST program. The inspectors initiated URI 05000341/2013005-04, Evaluation of Apparent Unacceptable Preconditioning of High Pressure Coolant Injection System Air Operated Valve Prior to Stroke Time Testing, specific to questions with the HPCI system surveillance test. The Unresolved Item was reviewed and closed in Section 1R22.b.(1) of this inspection report.

While stroke time testing of HPCI turbine supply drain pot to main condenser drain line isolation valve E4100-F028 was performed during the surveillance test, the inspectors noted that no stroke time testing of the redundant isolation valve (E4100-F029) was performed. Initially, in response to the inspectors questions, the licensee stated that E4100-F029 was excluded from its IST program because it had concluded the valve did not perform a safety function in either the open or closed position. The inspectors challenged this answer because both E4100-F028 and E4100-F029 are ASME Code Class 2 valves and E4100-F029 appeared to have the same function as E4100-F028, which was tested. The inspectors noted that 10 CFR 50.55a(f)(4) requires valves which were classified as ASME Code Class 1, Class 2, and Class 3 to meet the inservice test requirements set forth in the ASME OM [Operations and Maintenance] Code. As described in Table 6.2-14 and Section 6.3 of the UFSAR, the two normally open valves were required by design to close upon HPCI turbine start to isolate seismically qualified portions of the piping system from non-seismically qualified portions to mitigate the consequences of an accident since the HPCI system was considered to be a closed system in connection with the RCS outside of the containment. Upon further review, the licensee concluded that E4100-F028 and E4100-F029 were both required to be tested in accordance with the IST requirements.

Similarly, the inspectors noted that neither of the RCIC turbine supply drain pot to main condenser drain line isolation valves (E5150-F025 and E5150-F026) was scoped within the licensees IST program and that the valves were therefore not tested in accordance with the IST requirements. Both E5150-F025 and E5150-F026 are ASME Code Class 2 valves. Initially, in response to the inspectors questions, the licensee stated that the only RCIC system valves included within the scope of its IST program were those with a containment isolation function. Later, the licensee determined that E5150-F025 and E5150-F026 should also be included for testing within the scope of its IST program because these two valves were also required by design to close upon RCIC turbine start to isolate seismically qualified portions of the piping system from non-seismically qualified portions to mitigate the consequences of an accident for a closed system in connection with the RCS outside of containment.

The licensee initiated CARD 14-20673 to document its failure to perform the required inservice testing of HPCI and RCIC turbine supply drain pot to main condenser drain line isolation valves E4100-F029, E5150-F025, and E5150-F026 and to evaluate appropriate corrective actions including revisions to applicable test procedures to incorporate inservice testing of the valves. The licensees evaluation of this issue found the reason for excluding the valves from its IST program was apparently based upon an engineering evaluation completed in 1999. The licensee documented an immediate operability determination in CARD 14-20673, which concluded the three valves remained operable based on the performance of functional testing that verified the valves properly closed and opened during quarterly pump and valve surveillance testing. The inspectors concluded that this provided a reasonable basis to support continued operability of the valves.

Analysis:

The inspectors determined the licensees failure to perform required inservice testing of HPCI and RCIC turbine supply drain pot to main condenser drain line isolation valves E4100-F029, E5150-F025, and E5150-F026 was a performance deficiency warranting a significance evaluation. The inspectors assessed this finding using the SDP. The inspectors reviewed the examples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, and found no examples related to this issue. Consistent with the guidance in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, the inspectors determined the finding was associated with the SSC and Barrier Performance attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the licensees failure to perform required inservice testing had a direct effect on its ability to trend as-found performance data for the purpose of assessing the reliability of the three isolation valves, which were required by design to isolate seismically qualified portions of the piping systems from non-seismically qualified portions. The inspectors performed a significance screening of this finding using the guidance provided in IMC 0609, Significance Determination Process, Appendix A, The Significance Determination Process for Findings At-Power.

In accordance with Exhibit 3, Barrier Integrity Screening Questions, the inspectors determined this finding was a licensee performance deficiency of very low safety significance (Green) because it represented only a degradation of the radiological barrier function provided for the Reactor and Auxiliary Buildings and was not an actual loss of the barrier function provided by the HPCI or RCIC system pressure boundaries as closed systems outside containment.

The inspectors concluded that because the engineering evaluation that excluded the valves from inservice testing was completed in 1999 and no previous opportunity reasonably existed to identify and correct the error, this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified.

Enforcement:

10 CFR 50.55a(f)(4) states, in part, Throughout the service life of a boiling or pressurized water-cooled nuclear power facility, pumps and valves which are classified as ASME Code Class 1, Class 2, and Class 3 must meet the inservice test requirements...set forth in the ASME OM Code.

10 CFR 50.55a(f)(4)(ii) states, in part, Inservice tests to verify operational readiness of pumps and valves, whose function is required for safetymust comply with the requirements of the latest edition and addenda of the Code incorporated by reference in paragraph

(b) of this section.

The applicable Code for the current Fermi 2 inservice testing program interval for testing valves is the 2004 Edition of the ASME, Code for Operation and Maintenance of Nuclear Power Plants, (OM Code), Subsection ISTC, Inservice Testing of Valves in Light-Water Reactor Nuclear Power Plants.

Paragraph ISTC-3200, Inservice Testing, states: Inservice testing in accordance with this Subsection shall commence when the valves are required to be operable to fulfill their required function(s) (see ISTA-1100). Paragraph ISTA-1100, Scope, states, in part, The requirements apply to

(a) pumps and valves that are required to perform a specific function ... in mitigating the consequences of an accident.

Paragraph ISTC-3500, Valve Testing Requirements, states, in part: Active and passive valves in categories defined in ISTC-1300 shall be tested in accordance with the paragraphs specified in Table ISTC-3500-1 and the applicable requirements of ISTC-5100. Pneumatically operated valves E4100-F029, E5150-F025, and E5150-F026 are Active Category B valves as defined by paragraph ISTC-1300 with remote position indicators.

For Active Category B valves, Table ISTC-3500-1, Inservice Test Requirements, requires exercise testing in accordance with paragraph ISTC-3510 and position indication verification testing in accordance with paragraph ISTC-3700. Paragraph ISTC-3510, Exercising Test Frequency, states, in part: Active Category A, Category B, and Category C check valves shall be exercised nominally every 3 months.

Paragraph ISTC-3700, Position Verification Testing, states, in part: Valves with remote position indicators shall be observed locally at least once every 2 years to verify that the valve operation is accurately indicated.

Paragraph ISTC-5130, Pneumatically Operated Valves, subparagraph ISTC-5131, Valve Stroke Testing, states, in part:

(a) Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.

Contrary to the above, prior to identification by the inspectors and entry into the licensees corrective action program on January 31, 2014, the licensee failed to perform exercise testing, position verification testing, and stroke time measurement testing of ASME Code Class 2 pneumatically (air)-operated valves E4100-F029, E5150-F025, and E5150-F026 in accordance with Subsection ISTC of the ASME OM Code as required by 10 CFR 50.55a(f)(4) and (f)(4)(ii). Because of the very low safety significance, this violation is being treated as an NCV consistent with Section 2.3.2.a of the NRC Enforcement Policy (NCV 05000341/2014002-04, Failure to Perform Inservice Testing of High Pressure Coolant Injection and Reactor Core Isolation Cooling System Valves). The licensee entered this violation into its corrective action program as CARD 14-20673.

2RS1 Radiological Hazard Assessment and Exposure Controls

This inspection constituted a partial inspection sample as defined in IP 71124.01.

.1 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspector 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 inspector 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 inspector 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 inspector 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 inspector selected the following radiologically risk-significant work activities that involved exposure to radiation:

• Radiation Work Permit (RWP) 143012, ISI Inspections;

• RWP 143015, CRD [Control Rod Drive] Exchange; and

• RWP 145001, Perform Refuel Activities RB-5.

For these work activities, the inspector assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspector 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 inspector observed work in potential airborne areas and evaluated whether the air samples were representative of the breathing air zone. The inspector evaluated whether continuous air monitors were located in areas with low background to minimize false alarms and were representative of actual work areas. The inspector 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.

.2 Instructions to Workers (02.03)

a. Inspection Scope

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

• RWP 143012, ISI Inspections;

• RWP 143015, CRD Exchange; and

• RWP 145001, Perform Refuel Activities RB-5.

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

b. Findings

No findings were identified.

.3 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

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

The inspector 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.

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

This inspection constituted a partial inspection sample as defined in IP 71124.02.

.1 Radiological Work Planning (02.02)

a. Inspection Scope

The inspector selected the following work activities of the highest exposure significance:

• RWP 143012, ISI Inspections;

• RWP 143015, CRD Exchange; and

• RWP 145001, Perform Refuel Activities RB-5.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

This inspection constituted a partial inspection sample as defined in IP 71124.03.

.1 Use of Respiratory Protection Devices (02.03)

a. Inspection Scope

The inspector assessed whether respiratory protection devices used to limit the intake of radioactive materials were certified by the National Institute for Occupational Safety and Health/Mine Safety and Health Administration or have been approved by the NRC per 10 CFR 20.1703(b). The inspector selected work activities where respiratory protection devices were used. The inspector evaluated whether the devices were used consistent with their National Institute for Occupational Safety and Health/Mine Safety and Health Administration certification or any conditions of their NRC approval.

The inspector reviewed records of air testing for supplied-air devices and self-contained breathing apparatus bottles to assess whether the air used in these devices meets or exceeds Grade D quality. The inspector reviewed plant breathing air supply systems to determine whether they meet the minimum pressure and airflow requirements for the devices in use.

b. Findings

Introduction:

The inspector identified an Unresolved Item concerning the use of the Delta Suit respirator during control rod drive exchanges.

Description:

The inspector observed the use of tape placed over one of the designed escape features of the respirator during the control rod drive exchange performed under the reactor vessel. The use of tape was not referenced in the licensees procedure for this respirator. This issue is considered to be an Unresolved Item (URI 05000341/2014003-05, Use of Delta Suit Respirator) pending completion of the NRCs review of the issue to determine whether it is a performance deficiency of more-than-minor significance.

2RS4 Occupational Dose Assessment

This inspection constituted a partial inspection sample as defined in IP 71124.04.

.1 Special Dosimetric Situations (02.04)

Dosimeter Placement and Assessment of Effective Dose Equivalent for External Exposures

a. Inspection Scope

The inspector reviewed the licensee's methodology for monitoring external dose in non-uniform radiation fields or where large dose gradients existed. The inspector evaluated the licensee's criteria for determining when alternate monitoring, such as use of multi-badging, was to be implemented.

The inspector reviewed dose assessments performed using multi-badging to evaluate whether the assessment was performed consistently with the licensees procedures and dosimetric standards.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors verified the Unplanned Scrams per 7000 Critical Hours Performance Indicator (PI). To determine the accuracy of the PI data reported, definitions and guidance contained in Nuclear Energy Institute (NEI) document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, were used. The inspectors reviewed each LER from January 1 through December 31, 2013, determined the number of scrams that occurred, and verified the licensee's calculation of critical hours. The inspectors also reviewed the licensee's corrective action program database to determine if any problems had been identified with the data collected or transmitted for this indicator and none were identified. The inspectors noted that there were no unplanned scrams in 2013.

This inspection constituted one Unplanned Scrams per 7000 Critical Hours PI verification inspection sample as defined in IP 71151.

b. Findings

No findings were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors verified the Unplanned Scrams with Complications PI. To determine the accuracy of the PI data reported, definitions and guidance contained in NEI 99-02 were used. The inspectors reviewed each LER from January 1 through December 31, 2013, determined the number of scrams that occurred, and evaluated each of the scrams against the PI definition. The inspectors also reviewed the licensee's corrective action program database to determine if any problems had been identified with the data collected or transmitted for this indicator and none were identified. The inspectors noted that there were no unplanned scrams with complications in 2013.

This inspection constituted one Unplanned Scrams with Complications PI verification inspection sample as defined in IP 71151.

b. Findings

No findings were identified.

.3 Unplanned Power Changes per 7000 Critical Hours

a. Inspection Scope

The inspectors verified the Unplanned Power Changes per 7000 Critical Hours PI. To determine the accuracy of the PI data reported, definitions and guidance contained in NEI 99-02 were used. The inspectors reviewed power history data from January 1 through December 31, 2013, determined the number of power changes greater than 20 percent of full power that occurred, evaluated each of the power changes against the PI definition, and verified the licensee's calculation of critical hours. The inspectors also reviewed the licensee's corrective action program database to determine if any problems had been identified with the data collected or transmitted for this indicator. The inspectors noted that there were no unplanned power changes in 2013.

This inspection constituted one Unplanned Power Changes per 7000 Critical Hours PI verification inspection sample as defined in IP 71151.

b. Findings

No findings were identified.

.4 Safety System Functional Failures

a. Inspection Scope

The inspectors verified the Safety System Functional Failures PI. To determine the accuracy of the PI data reported, definitions and guidance contained in NEI 99-02 were used. The inspectors reviewed each LER from April 1 through December 31, 2013, determined the number of safety system functional failures that occurred, evaluated each LER against the PI definition, and verified the number of safety system functional failures reported. The inspectors also reviewed the licensee's corrective action program database to determine if any problems had been identified with the data collected or transmitted for this indicator. The inspectors noted that there were no safety system functional failures reported during the last three quarters of 2013.

This inspection constituted one Safety System Functional Failures PI verification inspection sample as defined in IP 71151.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As 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 corrective action program at an appropriate threshold, adequate attention was being given to timely corrective actions, and adverse trends were identified and addressed. Some minor issues were entered into the licensees corrective action program as a result of the inspectors observations; however, they are not discussed in this report.

This inspection was not considered to be an inspection sample as defined in IP 71152.

b. Findings

No findings were identified.

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

.1 Response to EDG 11 Exhaust Manifold Fire

a. Inspection Scope

On March 20, at around 1:59 p.m. (EDT), a small fire started on the EDG 11 exhaust manifold while the engine was running for surveillance testing; the reactor was shutdown in Mode 4 at the time. Operators immediately shut down the EDG and extinguished the fire with a hand-held carbon dioxide extinguisher. Subsequent investigation determined that the fire was caused by an external oil leak that had soaked insulation on the exhaust manifold at the exhaust extension from the turbocharger. The licensee activated its Emergency Plan at 2:05 p.m. at the Alert level because the fire potentially affected the operability of plant safety systems required to establish or maintain safe shutdown. The licensee terminated the Alert at 3:32 p.m.

The inspectors assessed plant conditions and evaluated the licensees actions in response to the event, including the classification of the event and appropriate notifications made to the State of Michigan and NRC.

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

b. Findings

No findings were identified.

.2 (Closed) LER 05000341/2013-003-00, Loss of Secondary Containment Function Due to

Exceedance of Technical Specification Required Vacuum Pressure On November 24, 2013, with the unit operating at or near full power, the RBHVAC system tripped. Secondary containment differential pressure rose above the TS limit of greater than or equal to 0.125 inch of vacuum water gauge (-0.125 inch water gauge),reaching a maximum of +0.08 inch water gauge. Within about 3 minutes, operators manually started the SGTS, and secondary containment differential pressure was restored below the TS limit. The licensee completed an apparent cause evaluation that concluded the RBHVAC system temperature switches, steam traps, and drains were inappropriately treated as run-to-failure components in the preventive maintenance program, resulting in inadequate and untimely maintenance being performed on these system components, causing multiple RBHVAC system failures during the past several years.

The licensee submitted LER 05000341/2013-003-00 to report this event in accordance with 10 CFR 50.73(a)(2)(v)(C) as a loss of safety function of a structure required to control the release of radioactive material. The inspectors reviewed this issue and documented a NCV of 10 CFR 50.65(a)(2) for the licensees failure to demonstrate that the performance of the temperature switches, steam traps, and drains of the RBHVAC system were effectively controlled through appropriate preventive maintenance or monitored as specified in 10 CFR 50.65(a)(1), such that the RBHVAC system remained capable of performing its intended function. The performance issue related to this event, the safety significance, the cause, and the corrective actions are discussed in more detail in Section 1R12.1.b.(1) of this inspection report. The inspectors determined the information provided in LER 05000341/2013-003-00 did not raise any new issues or change the conclusion of the initial review.

LER 05000341/2013-003-00 is closed.

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

4OA5 Other Activities

.1 (Closed) URI 0500341/2013003-02, Respirator Cartridge Storage Life

The inspectors determined that the licensee had not established a change-out program for respirator cartridges in accordance with Occupational Safety and Health regulations.

The inspectors determined that these cartridges were used for purposes other than to reduce exposure to airborne radioactive material. Further, the inspectors determined that no finding or violation occurred.

URI 05000341/2013003-02 is closed.

.2 Cross-Cutting Aspects Cross-Reference

The table below provides a cross-reference from the 2013 and earlier findings with associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014 will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305, Operating Reactor Assessment Program, starting with the 2014 mid-cycle assessment review.

Finding Old Cross-Cutting Aspect New Cross-Cutting Aspect 05000341/2013005-03 NCV H.4(a) H.12 05000341/2013008-03 NCV H.1(a) H.13 05000341/2013008-05 NCV P.1(c) P.2 05000341/2013201-01 NCV H.4(a) H.12

4OA6 Management Meetings

.1 Resident Inspectors Exit Meeting

The inspectors presented the inspection results to Mr. T. Conner and other members of the licensees staff at the conclusion of the inspection on April 9, 2014. The licensee acknowledged the findings presented. Proprietary information was examined during this inspection, but is not specifically discussed in this report.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The Radiological Hazard Assessment and Exposure Controls, Occupational ALARA [As Low As Is Reasonably Achievable] Planning and Controls, and In-plant Airborne Radioactivity Control and Mitigation inspection with Ms. J. Ford and other members of the licensees staff at the conclusion of the inspection on February 28, 2014.

• The ISI program inspection with Ms. J. Ford and other members of the licensees staff at the conclusion of the inspection on February 28, 2014.

The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. Auler, Engineering Programs

S. Berry, Manager, Outage & Work Management

R. Breymaier, Supervisor, Engineering Programs

M. Brooks, Engineering Programs

M. Caragher, Director, Nuclear Engineering

T. Conner, Vice-President, Nuclear Generation

D. Coseo, Supervisor, Regulatory Compliance

P. Crane, Superintendent, Production

J. Davis, Manager, Nuclear Training

J. Davis, Production Superintendent, Outage Scheduling

J. Ford, Director, Organization Effectiveness

S. Hassoun, Supervisor, Licensing and Environment

D. Hemmele, Superintendent, Operations

E. Kokosky, Manager, Nuclear Quality Assurance

R. LaBurn, Manager, Radiation Protection

A. Mann, Production Superintendent, Outage Management

A. Manoharan, Engineer, Regulatory Compliance

B. Mayes, Engineering Supervisor

C. McKinney, Engineering Programs

H. Michael, Engineering Programs

D. Moss, Operations Support

D. Netzel, Manager, Engineering 1st Team

G. Patzsch-Velaquez, Engineering Programs

J. Pendergast, Principal Engineer, Regulatory Compliance

L. Petersen, Manager, Plant Support Engineering

G. Piccard, Manager, Systems Engineering

Z. Rad, Manager, Licensing

W. Raymer, Assistant Manager, Maintenance

K. Scott, Director, Nuclear Production

G. Strobel, Manager, Operations

J. Thorson, Manager, Performance Engineering

B. Weber, Principal Technical Specialist

H. Yeldell, Manager, Maintenance

LIST OF ITEMS

Opened

05000341/2014002-01 NCV Failure to Perform Appropriate Preventive Maintenance on Reactor Building Heating, Ventilation, and Air Conditioning Components (Section 1R12.1.b.(1))

05000341/2014002-02 NCV Failure to Control the Work Hours of a Covered Worker (Section 1R20.1.b.(1))

05000341/2014002-03 NCV Unacceptable Preconditioning of High Pressure Coolant Injection System Air-Operated Valve Prior to Stroke Time Test Measurement (Section 1R22.b.(1))

05000341/2014002-04 NCV Failure to Perform Inservice Testing of High Pressure Coolant Injection and Reactor Core Isolation Cooling System Valves (Section 1R22.b.(2))

05000341/2014002-05 URI Use of Delta Suit Respirator (Section 2RS3.1.b)

Closed

05000341/2014002-01 NCV Failure to Perform Appropriate Preventive Maintenance on Reactor Building Heating, Ventilation, and Air Conditioning Components (Section 1R12.1.b.(1))

05000341/2014002-02 NCV Failure to Control the Work Hours of a Covered Worker (Section 1R20.1.b.(1))

05000341/2014002-03 NCV Unacceptable Preconditioning of High Pressure Coolant Injection System Air-Operated Valve Prior to Stroke Time Test Measurement (Section 1R22.b.(1))

05000341/2013005-04 URI Evaluation of Apparent Unacceptable Preconditioning of High Pressure Coolant System Air-Operated Valve Prior to Stroke Time Testing (Section 1R22.b.(1))

05000341/2014002-04 NCV Failure to Perform Inservice Testing of High Pressure Coolant Injection and Reactor Core Isolation Cooling System Valves (Section 1R22.b.(2))

05000341/2013-003-00 LER Loss of Secondary Containment Function Due to Exceedance of Technical Specification Required Vacuum Pressure (Section 4OA3.2)

05000341/2013003-02 URI Respirator Cartridge Storage Life (Section 4OA5.1)