IR 05000341/2013005

IR 05000341-13-005; 10/01/2013 - 12/31/2013; Fermi Power Plant, Unit 2; Heat Sink Performance, Maintenance Effectiveness, and Problem Identification and Resolution

ML14027A736
Person / Time
Site:	Fermi
Issue date:	01/27/2014
From:	Michael Kunowski NRC/RGN-III/DRP/B5
To:	Plona J Detroit Edison, Co
References
IR-13-005
Download: ML14027A736 (54)

Text

UNITED STATES ary 27, 2014

SUBJECT:

FERMI POWER PLANT, UNIT 2 NRC INTEGRATED INSPECTION REPORT 05000341/2013005

Dear Mr. Plona:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Fermi Power Plant, Unit 2. The enclosed report documents the results of this inspection, which were discussed on January 10, 2014, with Mr. M. Caragher and other members of your staff.

Based on the results of this inspection, two NRC-identified and two self-revealed findings of very low safety significance were identified. The four findings involved violations of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the violations or significance of these Non-Cited Violation, 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 the 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. As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to Inspection Manual Chapter (IMC) 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.

In accordance with 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 NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's 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 05000341/2013005 w/Attachment: Supplemental Information

REGION III==

Docket No: 50-341 License No: NPF-43 Report No: 05000341/2013005 Licensee: DTE Electric Company Facility: Fermi Power Plant, Unit 2 Location: Newport, MI Dates: October 1 through December 31, 2013 Inspectors: B. Kemker, Senior Resident Inspector R. Morris, Acting Senior Resident Inspector P. Smagacz, Resident Inspector K. Carrington, Acting Resident Inspector N. Adorno, Reactor Engineer M. Bielby, Senior Operations Engineer M. Jones, Reactor Engineer J. Laughlin, Emergency Preparedness Inspector J. Nance, Resident Inspector, Perry B. Palagi, Senior Operations Engineer C. Zoia, Operations Engineer Approved by: M. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000341/2013005; 10/01/2013 - 12/31/2013; Fermi Power Plant, Unit 2;

Heat Sink Performance, Maintenance Effectiveness, and Problem Identification and Resolution.

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 October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013.

The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the failure to demonstrate the cooling capability of the residual heat removal pump seal coolers.

Specifically, on December 4, 2013, the inspectors noted examples of missed and late inspections, and examples of as-found conditions not evaluated. This finding was entered into the licensees corrective action program, in part, to provide additional guidance in the preventive maintenance program database to ensure the Generic Letter 89-13 Program inspection requirements were implemented for these heat exchangers.

The performance deficiency was determined to be of more than minor safety significance because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the residual heat removal pumps to respond to initiating events to prevent undesirable consequences. The finding screened as very low safety significance because it did not result in the loss of operability or functionality. Specifically, the licensee reviewed the maintenance history of the coolers and determined it provided reasonable assurance of acceptable heat transfer. The inspectors did not identify a cross-cutting aspect associated with this finding because it was confirmed to not reflect current performance due to the age of the performance deficiency. (Section 1R07.1b.(1))

Green.

The inspectors identified a finding of very low safety significance with an associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to include appropriate acceptance criteria for ultimate heat sink level and temperature in surveillance procedures. Specifically, as of December 5, 2013, the inspectors identified that these acceptance criteria did not account for instrument uncertainties. This finding was entered into the licensees corrective action program, in part, to revise the acceptance criteria included in the associated surveillance procedure to account for instrument uncertainties.

The performance deficiency was determined to be of more than minor safety significance because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the ultimate heat sink to respond to initiating events to prevent undesirable consequences. The finding screened as very low safety significance because it did not result in the loss of operability or functionality. Specifically, a historic review did not find an example where the Technical Specification limits were exceeded when accounting for instrument uncertainties. The inspectors did not identify a cross-cutting aspect associated with this finding because it was confirmed to not reflect current performance due to the age of the performance deficiency. (Section 1R07.1b.(2))

Green.

A finding of very low safety significance with an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, was self-revealed on August 9, 2013, when operators had to manually shut down emergency diesel generator (EDG) 14 due to high air coolant system inlet temperature during a 24-hour surveillance test run. The high temperature condition occurred due to the licensees failure to adequately control the installation of the EDG 14 air coolant system control air pipe fitting between the relief valve and pressure regulator to prevent the use of materials that did not conform to design requirements. The licensee completed repairs to the EDG 14 air coolant system and returned the EDG to an operable status. The issue was entered into the licensees corrective action program for evaluation and additional corrective actions.

The finding was of more than minor safety significance since it was associated with the Design Control attribute and adversely affected the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the use of nonconforming materials led to failure of the EDG 14 air coolant system control air pipe fitting, which rendered the EDG inoperable. Although the finding involved an actual loss of function of a single train for greater than its Technical Specification allowed outage time, it was determined to be of very low safety significance during a detailed quantitative Significance Determination Process review since the delta core damage frequency was determined to be less than 1E-7/year using the NRC Standardized Plant Analysis Risk model. The inspectors concluded that because the nonconforming control air pipe fitting was installed in the EDG 14 air coolant system in 1988 and the most recent missed opportunity to correct the problem occurred in 2005 or 2006, this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified.

(Section 4OA2.4b.(1))

Cornerstone: Barrier Integrity

Green.

A finding of very low safety significance with an associated Non-Cited Violation of Technical Specification (TS) 5.4.1.a on procedures was self-revealed on August 30, 2013, when the Division 1 Reactor Core Isolation Cooling (RCIC) Equipment Room temperature input to the associated steam line isolation logic was discovered inoperable during a scheduled surveillance test. Maintenance craftsmen had failed to correctly terminate thermocouple wiring as specified by the work instructions during maintenance to replace terminal block knife switches two weeks earlier. As a result, the Division 1 RCIC Equipment Room temperature input to the associated steam line isolation logic for RCIC steam supply primary containment outboard isolation valve 1E51-F008 was rendered inoperable for greater than the TS 3.3.6.1 completion time. The licensee promptly corrected the wiring discrepancy and restored the Division 1 RCIC system steam line isolation logic to an operable status. The issue was entered into the licensees corrective action program for evaluation and additional corrective actions.

The finding was of more than minor safety significance since it was associated with the Human Performance 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, the Division 1 RCIC system steam line isolation logic was rendered inoperable for greater than the TS 3.3.6.1 completion time because maintenance craftsmen failed to correctly terminate thermocouple wiring as specified by the procedure when replacing terminal block knife switches. The finding was a licensee performance deficiency of very low safety significance because it only represented a degradation of the radiological barrier function provided for the Reactor Building and was not a complete loss of the barrier function provided by the RCIC system steam line isolation instrumentation since the Division 2 RCIC system steam line isolation logic remained operable. The inspectors concluded that this finding affected the cross-cutting area of human performance since adequate licensee personnel work practices did not support successful human performance. Specifically, human error prevention techniques, such as self and peer checking, were not adequately used to ensure the thermocouple wiring was correctly terminated upon replacing the terminal block knife switches (H.4(a)). (Section 1R12.1b.(1))

REPORT DETAILS

Summary of Plant Status

Fermi Power Plant, Unit 2, had just completed a planned maintenance outage and the licensee was returning the unit to 100 percent power at the beginning of the inspection period. Power ascension began on September 22 and the unit was returned to 100 percent (full) power on October 2. The unit was operated at or near full power during the inspection period with the following exceptions:

• On October 1, the licensee reduced power to about 68 percent to perform control rod sequence exchanges. The unit reached full power on October 2.

• On October 3, the licensee reduced power to about 92 percent due to a main turbine high pressure control valve unitized actuator trip. The licensee replaced a failed fuse in the actuator control circuit and returned the unit to full power the following day.

• On October 4, the licensee reduced power to about 83 percent to adjust the limit settings for reactor recirculation motor generator sets (scoop tube adjustments). The unit was returned to full power on October 6.

• On October 19, the licensee reduced power to about 92 percent to perform control rod surveillance testing and planned maintenance on a main turbine high pressure control valve unitized actuator. The unit was returned to full power later that day.

• On October 25, the licensee reduced power to about 67 percent to perform full core power suppression testing to attempt to identify a fuel bundle with a small fuel element defect. The unit was returned to full power on October 29.

• On October 30, the licensee reduced power to about 69 percent to perform control rod sequence exchanges. The unit was returned to full power the following day.

• On November 7, the licensee reduced power to about 87 percent, fully inserted four control rods and removed them from service for maintenance to replace hydraulic control units.

The unit was returned to full power the following day.

• On November 8, the licensee reduced power to about 69 percent to perform control rod sequence exchanges, localized power suppression testing with two control rods to attempt to identify a fuel bundle with a small fuel element defect, scram time testing of four control rods following maintenance on hydraulic control units, and main turbine control and stop valve testing. The unit was returned to full power on November 10.

• On November 11, the licensee reduced power to about 70 percent to perform additional control rod sequence exchanges. The unit was returned to full power on November 13.

• On November 20, the licensee reduced power to about 87 percent following an unexpected trip of the south condensate pump. The licensee later reduced power to about 80 percent to restore the condensate pump to service after repairs were made to the pumps suction valve position indication limit switch. The unit was returned to full power the following day.

• On December 14, the licensee reduced power to about 65 percent to replace a power supply for vibration sensors for the north reactor feedwater pump and to perform control rod sequence exchanges. The unit was returned to full power the following day.

REACTOR SAFETY

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

Preparedness

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable.

In addition, the inspectors verified that adverse weather protection 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.

The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

• Trace Heat System; and

• Circulating Water (Cooling Towers) System.

This inspection constituted one seasonal readiness inspection sample as defined in Inspection Procedure (IP) 71111.01.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Conditions - Extreme Cold Conditions

a. Inspection Scope

Since extreme cold conditions were forecast in the vicinity of the plant during the first week of December, the inspectors evaluated the licensees preparations, focusing on the Circulating Water System, General Service Water System, the Residual Heat Removal Service Water (RHRSW) System, and the Fire Pumps. The inspectors focused on 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.

This inspection constituted one readiness for impending adverse weather conditions inspection sample as defined in 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:

• Emergency Diesel Generator (EDG) 13 following surveillance testing;

• Reactor Core Isolation Cooling (RCIC) System (single train risk-significant system); and

• Division 1 RHRSW System during Division 2 RHRSW System maintenance.

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.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

The inspectors performed a complete system alignment inspection of the Reactor Building Component Cooling Water System to verify the functional capability of the system. This system was selected because it was considered safety significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment lineups, electrical power availability, system pressure and temperature indications, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding work orders was performed to determine whether any deficiencies significantly affected the system function.

This inspection constituted one complete system walkdown inspection sample 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:

• Auxiliary Building Sub-Basement, High Pressure Coolant Injection (HPCI) Pump Room;

• Auxiliary Building First Floor, HPCI Hatch and Cable Area;

• Reactor Building Sub-Basement and Basement, Division 1 Core Spray and RCIC Pump Room;

• Reactor Building First Floor, Division 1 Residual Heat Removal (RHR) Heat Exchanger Room;

• Reactor Building First Floor Mezzanine; and

• Reactor Building Second Floor, South and Division 2 Emergency Equipment Cooling Water Areas.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees 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 six quarterly fire protection inspection samples as defined in IP 71111.05Q.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flooding analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the Fire Suppression or the Circulating Water Systems.

The inspectors performed a walkdown of accessible portions of the following plant area to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were functional, and the licensee complied with its commitments:

• Reactor Building Sub-Basement, Southwest Quadrant.

In addition, the inspectors verified internal flooding-related issues 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 internal flooding inspection sample as defined in IP 71111.06.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

.1 Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors reviewed completed surveillances, vendor manual information, calculations, performance test and inspection results, and procedures associated with the EDG 14 Air Cooler, Division 1 Emergency Equipment Cooling Water Heat Exchanger, and the RHR C Pump Seal Cooler. These heat exchangers were chosen based on their risk significance in the licensees probabilistic safety analysis, their important safety-related support functions, and their operating history.

For the selected heat exchangers, the inspectors reviewed testing, inspection, maintenance, and monitoring of biotic-fouling and macro-fouling programs relied upon to ensure proper heat transfer. This was accomplished by verifying:

(1) the selected test or inspection method was consistent with accepted industry practices or equivalent,

(2) the test or inspection conditions were consistent with the selected methodology, and

(3) the test or inspection acceptance criteria were consistent with the design basis values. In addition, the inspectors reviewed the results of heat exchanger performance testing and verified the test results considered:

(1) differences between testing conditions and design conditions, and

(2) test instrument inaccuracies. The inspectors also verified trending of test results to confirm the test frequency was sufficient to detect degradation prior to loss of heat removal capabilities below design basis values. In addition, the inspectors verified the condition and operation of the heat exchangers were consistent with design assumptions in heat transfer calculations and applicable descriptions in the UFSAR. The inspectors verified the licensee evaluated the potential for water hammer and established controls and operational limits to prevent heat exchanger degradation due to excessive flow-induced vibration during operation. In addition, eddy current test reports and visual inspection records were reviewed to determine the structural integrity of the heat exchangers.

The inspectors assessed the performance of the ultimate heat sink (UHS) and safety-related service water systems and their subcomponents by reviewing tests or other equivalent methods used by the licensee to ensure the availability and accessibility to cooling water systems. Specifically, the inspectors verified the licensees UHS inspection was comprehensive and of significant depth to ensure sufficient reservoir capacity. This included the review of licensees periodic monitoring and trending of sediment build-up and heat transfer capability calculations. In addition, the inspectors reviewed the licensees periodic performance monitoring of the UHS structural integrity and verified that adjacent non-seismic or nonsafety-related structures could not degrade or block safety-related flow paths during a severe weather or seismic event. In addition, the inspectors reviewed the licensees performance testing of the service water system and reviewed the UHS results.

This included the review of the licensees performance test results for key components. The inspectors also verified the licensee ensured adequate isolation during design basis events and consistency between testing methodologies and design basis leakage rate assumptions.

In addition, the inspectors reviewed a sample of CARDS related to the heat exchangers/coolers and heat sink performance issues to verify the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of the corrective actions.

These inspection activities constituted four triennial heat sink inspection samples as defined in IP 71111.07.

b. Findings

(1) RHR Pump Seal Cooler Testing Was Not Adequately Implemented

Introduction:

A finding of very low safety significance (Green) with an associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, was identified by the inspectors for the failure to demonstrate the cooling capability of the RHR pump seal coolers. Specifically, the inspectors noted examples of missed and late inspections, and examples of as-found conditions not evaluated.

Description:

In 1989, the NRC issued Generic Letter (GL) 89-13, Service Water System Problems Affecting Safety-Related Equipment, in response to operating experience related to service water systems and requested licensees to supply information confirming the safety functions of its respective service water systems were met. As part of the licensees resolution efforts, the licensee created procedure MES52, GL 89-13 Safety-Related Service Water Monitoring Program, to describe, in part, the requirements of its GL 89-13 Program.

The licensee also credited procedure MES54, Heat Exchanger Component Monitoring Program, to provide guidance for inspection of its GL 89-13 Program heat exchangers.

On December 4, 2013, the inspectors noted multiple examples of the licensees failure to implement the test requirements contained in these procedures for the RHR pump seal coolers. These coolers were identified as GL 89-13 Program components by Enclosure A of MES54. Specifically, MES54, Step 3.1.7 stated, Each heat exchanger is inspected at a frequency as defined in the PM [Preventive Maintenance] Program. The PM task periodicity for the RHR pump seal coolers was 5 years, which is the maximum interval allowed by MES54. However, the inspectors noted the following examples of RHR pump seal cooler inspections exceeding the 5-year periodicity:

• The last A and D RHR pump seal cooler inspections were performed approximately 6 years after their previous inspections. Specifically, the last two A RHR pump seal cooler inspections were performed on February 2, 2004, and April 27, 2010, and the last two D RHR pump seal cooler inspections were performed on December 15, 2003, and March 9, 2010.

• The B and C RHR pump seal coolers have not been inspected for approximately 10 years. Specifically, the B and C RHR pump seal coolers were last inspected on December 17, 2003, and February 4, 2004, respectively.

In addition, the inspectors noted the 2010 inspections of the A and D RHR pump seal coolers did not include acceptance criteria, which was contrary to MES52. Specifically, Step 3.3.1 stated, Acceptance criteria is developed for critical monitored parameter (e.g.,

heat exchanger heat transfer capability, service water coupon corrosion rate, etc.) and included in applicable procedures or manuals. Acceptance criteria are necessary to evaluate the as-found condition to assess component performance and maintenance effectiveness. In fact, MES54 stated, After each inspection, the interval between inspections should be evaluated based on the results of the two previous inspections and the current inspection. The inspectors were particularly concerned because the 2010 as-found conditions of the A and D RHR pump seal coolers inspections were characterized as a 1-millimeter thick fouling covering 25 percent tubing surface area, while design calculations assumed fouling conditions typical of a clean system.

The licensee captured the inspectors concerns in its corrective action program as CARD 13-28550 and CARD 13-28590. As an immediate corrective action, the licensee reviewed the maintenance history of the coolers and determined it provided reasonable assurance of acceptable heat transfer performance until the next PM activity scheduled within 1.5 years from this inspection period. The proposed corrective actions to restore compliance were to provide additional guidance in the PM Program database to ensure the GL 89-13 Program inspection requirements were implemented for these heat exchangers.

Analysis:

The inspectors determined the failure to demonstrate the cooling capability of the RHR pump seal coolers was contrary to 10 CFR 50, Appendix B, Criterion XI, Test Control, and was a performance deficiency. The performance deficiency was determined to be of more than minor safety significance because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the RHR pumps to respond to initiating events to prevent undesirable consequences. Specifically, the failure to adequately monitor the thermal performance of the RHR pump seal coolers did not ensure their capacity to remove the required heat from the RHR pump seals during accident conditions. Inadequate testing of the coolers created the potential for unacceptable cooler performance to go undetected that could adversely affect the operability of the RHR pumps.

The inspectors determined the finding could be evaluated using the Significance Determination Process (SDP) in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012. Because the finding impacted the Mitigating Systems Cornerstone, the inspectors screened the finding through IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. The finding screened as very low safety significance (Green) because it did not result in the loss of operability or functionality.

Specifically, the licensee reviewed the maintenance history of the coolers and determined it provided reasonable assurance of acceptable heat transfer.

The inspectors did not identify a cross-cutting aspect associated with this finding because it was confirmed to not reflect current performance due to the age of the performance deficiency. Specifically, the licensee failed to inspect and clean the B and C RHR pump seal coolers during the associated PM activity implemented in 2009 and 2008 respectively.

In addition, the acceptance criteria for the A and D coolers were not developed for the inspections implemented at the beginning of 2010.

Enforcement:

10 CFR 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program be established to assure that 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.

Contrary to the above, as of December 4, 2013, the licensee failed to assure that testing required to demonstrate the RHR pump seal coolers would perform satisfactorily in service was identified and performed in accordance with written test procedures which incorporated the requirements and acceptance limits contained in applicable design documents as evidenced by the following examples:

• The RHR pump seal coolers were inspected at a periodicity that was not in accordance with the maximum inspection interval required by procedure MES54.

• The RHR pump seal coolers test procedures did not incorporate acceptance limits.

The licensee is still evaluating its planned corrective actions. However, the inspectors determined that the continued non-compliance does not present an immediate safety concern because the licensee reasonably demonstrated acceptable heat transfer performance.

Because this violation was of very low safety significance and was entered into the licensees corrective action program, as CARD 13-28550 and CARD 13-28590, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000341/2013005-01, RHR Pump Seal Cooler Testing Was Not Adequately Implemented).

(2) Acceptance Criteria for Ultimate Heat Sink Level and Temperature Did Not Consider Instrument Uncertainties

Introduction:

A finding of very low safety significance (Green) with an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure to include appropriate acceptance criteria for UHS level and temperature in surveillance procedures. Specifically, these acceptance criteria did not account for instrument uncertainties.

Description:

Technical Specification 3.7.2, Emergency Equipment Cooling Water/Emergency Equipment Service Water System and Ultimate Heat Sink, required, in part, that the UHS be operable in Modes 1, 2, and 3. In order to ensure UHS operability, Surveillance Requirement 3.7.2.1 required the licensee to verify UHS level was maintained greater than or equal to 25 feet. In addition, Surveillance Requirement 3.7.2.2 verified UHS water temperature was less than or equal to 80 degrees Fahrenheit (°F). The licensee implemented these surveillance requirements via procedure 24.000.02, Shiftly, Daily, and Weekly Required Surveillances.

The inspectors reviewed UHS performance calculations and noted they did not account for UHS level and temperature instrument uncertainties. In addition, the inspectors noted surveillance procedure 24.000.02 used the associated TS limit values as the acceptance criteria; thus, the procedure also did not consider instrument uncertainties. The inspectors were particularly concerned because they noted an instance where instrument uncertainties were greater than the available design margin. Specifically, the calibration leave alone tolerance of the UHS temperature instruments were 2.1°F and 1.2°F for Division 1 and 2, respectively. However, calculation DC-0182, Volume 1, RHR Service Water Mechanical Draft Cooling Towers - Heat Load and Water Losses, determined the design margin was 0.04°F for the worst condition expected during a design basis loss-of-coolant accident.

The licensee captured the inspectors concerns in its corrective action program as CARD 13-28624. As an immediate corrective action, the licensee performed a historic review and determined UHS level and temperature TS limits were not exceeded in the last two years when accounting for instrument uncertainties. The proposed corrective action to restore compliance was to revise the associated acceptance criteria included in surveillance procedure 24.000.02 to account for the instrument uncertainties. As an interim corrective action, the licensee created Tracking Limiting Condition for Operation 13-0562 to ensure UHS level and temperature remain within operability limits until the procedure is revised.

Analysis:

The inspectors determined the failure to include appropriate acceptance criteria for UHS level and temperature in surveillance procedures was contrary to 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, and was a performance deficiency. The performance deficiency was determined to be of more than minor safety significance because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of the UHS to respond to initiating events to prevent undesirable consequences. Specifically, the failure to account for UHS temperature and level instrument uncertainties was significant enough to require revision of the associated surveillance procedures to ensure the validity of UHS performance calculations and compliance with TS limits.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012. Because the finding impacted the Mitigating Systems Cornerstone, the inspectors screened the finding through IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2102. The finding screened as very low safety significance (Green) because it did not result in the loss of operability or functionality. Specifically, a historic review did not find an example where TS limits were exceeded when accounting for instrument uncertainties.

The inspectors did not identify a cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. Specifically, the affected procedure was developed more than three years ago.

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that instructions, procedures, or drawings include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.

Contrary to the above, as of December 5, 2013, the licensee failed to include appropriate acceptance criteria in procedures. Specifically, the UHS level and temperature acceptance criteria included in surveillance procedure 24.000.02 did not account for instrument uncertainties to ensure compliance with TS limits and conformance with UHS design basis calculations.

The licensee is still evaluating its planned corrective actions. However, the inspectors determined that the continued non-compliance does not present an immediate safety concern because the licensee created Tracking Limiting Condition for Operation 13--0562 to ensure UHS level and temperature remain within the operability limits until procedure compliance is restored.

Because this violation was of very low safety significance and was entered into the licensees corrective action program, as CARD 13-28624, this violation is being treated as a Non-Cited Violation consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000341/2013005-02, Acceptance Criteria for UHS Level and Temperature Did Not Consider Instrument Uncertainties).

1R11 Licensed Operator Requalification Program

.1 Biennial Written and Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Biennial Written Examination and the Annual Operating Test, administered by the licensee from October 28 through November 29, as required by 10 CFR 55.59(a). The results were compared to the thresholds established in IMC 0609, Appendix I, Licensed Operator Requalification Significance Determination Process," dated December 6, 2011, to assess the overall adequacy of the licensees Licensed Operator Requalification Training Program to meet the requirements of 10 CFR 55.59. (02.02)

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

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

The inspectors observed licensed operators during annual operator requalification simulator examinations on November 19. The inspectors assessed the operators response to the simulated events focusing on alarm response, command and control of crew activities, communication practices, procedural adherence, and implementation of Emergency Plan requirements. The inspectors also observed the post-evaluation critique to assess the ability of licensee evaluators to identify performance deficiencies. The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements.

This inspection constituted one quarterly licensed operator requalification program simulator inspection sample as defined in IP 71111.11. The biennial portion of this IP was also completed this quarter and is documented below in Section 1R11.4.

b. Findings

No findings were identified.

.3 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On October 26 and 27, the inspectors observed licensed operators in the Control Room performing full core power suppression testing to attempt to identify the location of a small fuel element defect. The activity required heightened awareness, 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.

.4 Biennial Review

a. Inspection Scope

The following inspection activities were conducted during the week of November 4 - 8 to assess: 1) the effectiveness and adequacy of the facility licensees implementation and maintenance of its systems approach to training based Licensed Operator Requalification Training Program, put into effect to satisfy the requirements of 10 CFR 55.59; 2)conformance with the requirements of 10 CFR 55.46 for use of a plant-referenced simulator to conduct operator licensing examinations and for satisfying experience requirements; and, 3) conformance with the operator license conditions specified in 10 CFR 55.53.

• Licensee Requalification Examinations (10 CFR 55.59(c); Systems Approach to Training Element 4 as Defined in 10 CFR 55.4): The inspectors reviewed the licensees program for development and administration of the Licensed Operator Requalification Training biennial written examination and annual operating tests to assess the licensees ability to develop and administer examinations that are acceptable for meeting the requirements of 10 CFR 55.59(a).

- The inspectors conducted a detailed review of one biennial requalification written examination to assess content, level of difficulty, and quality of the written examination materials. (02.03)

- The inspectors conducted a detailed review of ten Job Performance Measures and six dynamic simulator scenarios to assess content, level of difficulty, and quality of the operating test materials. (02.04)

- The inspectors observed the administration of the annual operating test to assess the licensees effectiveness in conducting the examinations, including the conduct of pre-examination briefings, evaluations of individual operator and crew performance, and post-examination analysis. The inspectors evaluated the performance of two simulator crews in parallel with the facility evaluators during four dynamic simulator scenarios and evaluated various licensed crew members concurrently with facility evaluators during the administration of several Job Performance Measures. (02.05)

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

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

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

• Conformance with Simulator Requirements Specified in 10 CFR 55.46: The inspectors assessed the adequacy of the licensees simulation facility (simulator) for use in operator licensing examinations and for satisfying experience requirements. The inspectors reviewed a sample of simulator performance test records (e.g., transient tests, malfunction tests, scenario based tests, post-event tests, steady state tests, and core performance tests), simulator discrepancies, and the process for ensuring continued assurance of simulator fidelity in accordance with 10 CFR 55.46. The inspectors reviewed and evaluated the discrepancy corrective action process to ensure simulator fidelity was being maintained. Open simulator discrepancies were reviewed for importance relative to the impact on 10 CFR 55.45 and 55.59 operator actions, as well as on nuclear and thermal hydraulic operating characteristics. (02.09)

• Problem Identification and Resolution (10 CFR 55.59(c); Systems Approach to Training Element 5 as Defined in 10 CFR 55.4): The inspectors assessed the licensees ability to identify, evaluate, and resolve problems associated with licensed operator performance (a measure of the effectiveness of its licensed operator requalification program and their ability to implement appropriate corrective actions to maintain its Licensed Operator Requalification Training Program up to date). The inspectors reviewed documents related to licensed operator performance issues (e.g., recent examination and inspection reports including cited and Non-Cited Violations; NRC End-of-Cycle and Mid-Cycle reports; NRC plant issue matrix; licensee event reports; licensee condition/problem identification reports, including documentation of plant events and review of industry operating experience). The inspectors also sampled the licensees quality assurance oversight activities, including licensee training department self-assessment reports.

(02.10)

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

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):

• Division 1 RCIC Equipment Room Area Temperature Channel (E51N602A); and

• Diesel Fire Pump.

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 Correctly Connect Thermocouple Wiring During Maintenance Resulted in Inoperable RCIC System Isolation Instrumentation

Introduction:

A finding of very low safety significance (Green) with an associated NCV of TS 5.4.1.a on procedures was self-revealed on August 30, 2013, when the Division 1 RCIC Equipment Room temperature input to the associated steam line isolation logic was discovered inoperable. Maintenance craftsmen had failed to correctly terminate thermocouple wiring during maintenance two weeks earlier. As a result, the isolation logic for RCIC steam supply primary containment outboard isolation valve 1E51-F008 was rendered inoperable.

Description:

On August 30, while performing channel functional testing of the Division 1 RCIC Equipment Room Area Temperature Channel (E51N602A), maintenance craftsmen discovered one of two associated temperature switch thermocouple leads was not correctly terminated to the terminal block knife switch. Two weeks earlier, on August 16, maintenance craftsmen had failed to correctly terminate thermocouple wiring as specified by the work instructions (Work Order [WO] 33734802, Replace Knife Switches for Temperature Switch E51N602A in Panel H11P614) during maintenance to replace terminal block knife switches. The error was not discovered during post-maintenance testing. Both thermocouple leads had been terminated to the same terminal point (TT-4) inside Relay Room Panel H11P614. However, one thermocouple lead should have been terminated at TT-4 and the other lead terminated at TT-3. As a result, the temperature switch that this thermocouple fed was not monitoring the RCIC Equipment Room temperature, but was instead monitoring the temperature inside of Relay Room Panel H11P614. The post-maintenance test was simply to read and record the temperature indicated for E51N602A on the temperature monitor. As it was, the temperature in the Relay Room was about the same as the temperature in the RCIC Equipment Room and, therefore, the as-found temperature was as expected. The post-maintenance test was not adequate to identify the wiring discrepancy before the temperature switch was returned to service. Operators declared the Division 1 RCIC Equipment Room temperature input to the associated steam line isolation logic inoperable upon discovering the problem. The wiring discrepancy was promptly corrected and the Division 1 RCIC Equipment Room temperature input to the associated steam line isolation logic was returned to an operable status on August 30.

The licensee completed an apparent cause evaluation for the mis-wired thermocouple and concluded that maintenance craftsmen had failed to use sufficient rigor and diligence during concurrent verification for interim alterations of electrical circuitry during the performance of maintenance to replace terminal block knife switches in the panel. The inspectors reviewed the evaluation and concurred with the licensees conclusion. However, the inspectors noted the evaluation did not consider the inadequate post-maintenance test to be a contributing cause for the event and, therefore, no corrective actions were identified to address it. The wiring discrepancy should have been found and corrected prior to returning E51N602A to service. While the inadequate post-maintenance test was not the direct cause of the event and it should not excuse the human performance error, discovery of the wiring discrepancy prior to returning the instrument to service would have precluded a reportable event. The licensee wrote CARD 13-27975 to evaluate the inspectors concern with the inadequate post-maintenance test and revised the standard work order post-maintenance testing instructions to include a positive verification of instrument response.

Corrective actions identified by the licensee in the apparent cause evaluation included:

• Correcting the wiring discrepancy and satisfactorily completing channel functional testing for E51N602A;

• Disqualification and re-training of the maintenance craftsmen involved with the error;

• Instrument Maintenance Department stand-down and training on this event; and

• Focused management field observations of verification practices to reinforce expectations for properly performing the verification process with a subsequent review of the results to verify performance standards are being met.

For an inoperable steam leak detection input, TS 3.3.6.1, Primary Containment Isolation Instrumentation, required the affected channel be placed in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or isolation of the affected penetration within 1 additional hour. Inoperability of E51N602A affected the isolation function of RCIC steam supply primary containment outboard isolation valve 1E51-F008. The isolation function was inoperable for approximately 14 days, which exceeded the TS 3.3.6.1 completion time.

The licensee submitted Licensee Event Report (LER) 05000341/2013-002-00, Reactor Core Isolation Cooling Isolation Instrumentation Misconfigured Wiring, in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TSs for the RCIC system isolation channel being inoperable for longer than the TS completion time. Refer to Section 4OA3.1 of this inspection report for the inspectors review of the LER.

Analysis:

The inspectors determined the licensees failure to correctly implement WO 33734802 to replace knife switches for temperature switch E51N602A was a performance deficiency warranting a significance evaluation. The inspectors reviewed the examples of minor issues in IMC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, dated August 11, 2009, and noted in Example 4b that a procedure performance error would not be considered of minor safety significance when there is an adverse consequence resulting from it. Consistent with the guidance in IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined the finding was associated with the Human Performance 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, the Division 1 RCIC Equipment Room temperature input to the associated steam line isolation logic was rendered inoperable for greater than the TS 3.3.6.1 completion time because maintenance craftsmen failed to correctly terminate thermocouple wiring as specified by the procedure when replacing terminal block knife switches. 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, dated June 19, 2012, 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 and was not a complete loss of the barrier function provided by the RCIC system steam line isolation instrumentation since the Division 2 RCIC system steam line isolation logic remained operable.

The inspectors concluded this finding affected the cross-cutting area of human performance since adequate licensee personnel work practices did not support successful human performance. Specifically, human error prevention techniques, such as self and peer checking, were not adequately used to ensure the thermocouple wiring was correctly terminated upon replacing the terminal block knife switches (H.4(a)).

Enforcement:

Technical Specification 5.4.1.a requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978.

Section 9.a of Regulatory Guide 1.33 recommends procedures for performing maintenance that can affect the performance of safety-related equipment. Maintenance procedure WO 33734802, Replace Knife Switches for Temperature Switch E51N602A in Panel H11P614, implements the requirements of Regulatory Guide 1.33, Revision 2, Appendix A, Section 9.a, and contains instructions for replacing knife switches for safety-related temperature switch E51N602A in Panel H11P614. Step 9 of WO 33734802 specifies, in part, for licensee maintenance craftsmen to install the new terminal block knife switches and terminate thermocouple wiring at TT-3 and TT-4.

Contrary to the above, while performing WO 33734802 on August 16, 2013, the licensee failed to correctly terminate the thermocouple wiring at TT-3 and TT-4. Both thermocouple leads were instead terminated at TT-4, with no lead terminated at TT-3. Consequently, the Division 1 RCIC Equipment Room temperature input to the associated steam line isolation logic was rendered inoperable for greater than the TS 3.3.6.1 completion time. Because of the very low safety significance, this violation is being treated as a Non-Cited Violation consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000341/2013005-03, Failure to Correctly Connect Thermocouple Wiring During Maintenance Resulted in Inoperable Reactor Core Isolation Cooling System Isolation Instrumentation). The licensee entered this violation into its corrective action program as CARD 13-26096.

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:

• Planned maintenance during the week of September 30 - October 4 on the Division 2 UHS and Control Complex Heating, Ventilation, and Air Conditioning System;

• Planned maintenance during the week of October 7-11 on the Standby Feedwater System;

• Planned maintenance during the week of November 4-8 on the Division 2 Non-Interruptible Air Supply and Emergency Equipment Cooling Water Systems; and

• Planned maintenance during the week of December 2-6 on the Division 2 RHR/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 four 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:

• Operational Decision-Making Issue (ODMI)13-004, Spurious Half Main Steam Isolation Valve Isolation Alarms and Potential Trip;

• CARD 13-25574, EDG 14 Was Manually Shutdown During 24-Hour Surveillance Run due to High Air Temperature;

• CARD 13-25992, RCIC Suction Pressure High Alarm Following Start of HPCI System During Surveillance Test; and

• CARD 13-25859, Evaluate for Operability P50F416.

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 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 four operability determination inspection samples as defined in IP 71111.15.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Temporary Modifications

a. Inspection Scope

The inspectors reviewed the following plant temporary modification:

• CARD 13-27288, NRC Concern - Request Engineering Evaluation Regarding Configuration Control for ODMI 13-004.

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 TSs 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.

The inspectors also reviewed a sample of CARDs pertaining to temporary modifications to verify problems were entered into the licensees corrective action program with the appropriate significance characterization, and the corrective actions were appropriate.

This inspection constituted one temporary modification inspection sample 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 33936868, Test of T-626 Division 1 Control Complex Heating, Ventilation, and Air Conditioning Chiller Oil Cooler Outlet Temperature Control Valve;

• WO 34380744, Defective Closed Indication in Main Control Room for N2103F001 Standby Feedwater Discharge Valve; and

• WO 37715224, HPCI Booster Pump Suction from Torus Valve Stroke Times.

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 reviewed corrective action program documents associated with post-maintenance testing to verify identified problems were entered into the licensee's corrective action program with the appropriate characterization. Selected CARDs were reviewed to verify the corrective actions were appropriate and implemented as scheduled.

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

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

.1 New Fuel Receipt Inspection

a. Inspection Scope

The inspectors observed new fuel receipt inspection, observed fuel handling operations, and reviewed the licensees fuel handling procedures involving the receipt of new fuel assemblies in preparation for the upcoming refueling outage.

This inspection was not considered to be a completed inspection sample as defined in IP 71111.20.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether safety-related or 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:

• Division 1 Core Spray Pump and Valve Operability Test (inservice testing);

• Standby Feedwater Pump A Quarterly Surveillance (routine); and

• RCIC System Pump and Valve Operability Test (inservice testing).

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 analysis 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 corrective actions were appropriate and implemented as scheduled.

This inspection constituted one routine surveillance test and two inservice tests, for a total of three surveillance testing inspection samples as defined in IP 71111.22.

b. Findings

(1) Apparent Unacceptable Preconditioning of HPCI System Air Operated Valve (AOV) Prior to Stroke Time Testing

Introduction:

The inspectors opened an Unresolved Item (URI) pending review of the licensees evaluation of apparent unacceptable preconditioning of the HPCI turbine supply drain pot to main condenser drain line isolation valve (E4100-F028) during surveillance testing. In addition, the inspectors have questioned whether the redundant drain line isolation valve (E4100-F029) should also be tested within the scope of the licensees Inservice Testing (IST) Program requirements.

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, Paragraph 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 closed 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. 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 5.105, respectively. At step 5.1.109, E4100-F028 was then closed and its stroke time was measured. No stroke time testing of E4100-F029 was performed since the licensee excluded the valve from its IST Program because it concluded the valve does 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 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 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

[American Society of Mechanical Engineers] 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 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 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 that this preconditioning should have been evaluated and documented in advance of the surveillance. Since the licensee had not performed an evaluation to justify preconditioning of the valve was acceptable prior to completing the testing, the inspectors have questioned whether the licensees surveillance testing sequence that cycled the valve prior to obtaining stroke time data constituted unacceptable preconditioning of the valve. The licensee initiated CARD 13-26877 to evaluate the apparent preconditioning concern.

This issue is considered to be an Unresolved Item pending additional review by the inspectors (URI 05000341/2013005-04, Evaluation of Apparent Unacceptable Preconditioning of High Pressure Coolant System Air Operated Valve Prior to Stroke Time Testing).

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The Office of Nuclear Security and Incident Response headquarters staff performed an in-office review of the latest revisions to the Emergency Plan and various Emergency Plan Implementing Procedures as listed in the Attachment to this report.

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

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

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on October 19 to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. This drill was planned to be evaluated and was included in performance indicator data regarding drill and exercise performance. The inspectors observed emergency response operations in the Control Room Simulator and the Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensees drill critique to compare any inspector-observed weaknesses with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensees staff was properly identifying weaknesses and entering them into the corrective action program.

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

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Review of Submitted Quarterly Data

a. Inspection Scope

The inspectors performed a review of the data submitted by the licensee for the third quarter 2013 performance indicators for any obvious inconsistencies prior to its public release in accordance with IMC 0608, "Performance Indicator Program."

This inspection was not considered to be an inspection sample as defined in IP 71151.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Residual Heat Removal Systems

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported Mitigating Systems Performance Index (MSPI) - RHR Systems Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, Licensee Event Reports, and maintenance and test data from October 2012 through September 2013, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees corrective action program database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator.

This inspection constituted one MSPI - RHR Systems Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors reviewed a sample of plant records and data against the reported MSPI -

Cooling Water Systems Performance Indicator. To determine the accuracy of the performance indicator data reported, performance indicator definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed the MSPI derivation reports, Control Room logs, Maintenance Rule database, LERs, and maintenance and test data from October 2012 through September 2013, to validate the accuracy of the performance indicator data reported. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees corrective action program database to determine if any problems had been identified with the performance indicator data collected or transmitted for this performance indicator.

This inspection constituted one MSPI - Cooling Water Systems Performance Indicator verification inspection sample as defined in IP 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.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.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors reviewed repetitive or closely related issues documented in the licensees corrective action program to look for trends not previously identified. This included a review of the licensees quarterly trend coding and analysis reports to assess the effectiveness of the licensees trending process. The inspectors also reviewed selected CARDs regarding licensee-identified potential trends to verify corrective actions were effective in addressing the trends and implemented in a timely manner commensurate with the significance.

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

b. Assessment and Observations No findings were identified.

(1) Overall Effectiveness of Trending Program The inspectors determined the licensees trending program was generally effective at identifying, monitoring, and correcting adverse performance trends. This has been reflected in the licensees quarterly trend coding and analysis reports. The inspectors reviewed several common cause evaluations performed by the licensee to evaluate potential adverse performance and equipment trends. In general, these evaluations were performed well and identified appropriate corrective actions to address adverse trends that were identified.

As discussed below, the inspectors identified one adverse performance trend during their review that was not already identified and adequately addressed by the licensees corrective action program.

(2) Adverse Performance Trend in Housekeeping Issues Identified During Plant Walkdowns by the Inspectors During periodic plant walkdowns over the past several months, the inspectors identified multiple housekeeping issues indicative of an emerging adverse performance trend.

Throughout the months of August - October 2013, the inspectors toured many areas of the plant, some of which were not frequently accessed by plant staff, and found improper housekeeping, material restraint, fire loading, lighting, and equipment storage issues that had not been identified by the licensees staff and corrected. Plant areas walked down included the Torus Room, Auxiliary Building Mezzanine, Cable Spreading Room, Drywell, and Reactor Building. In response to the inspectors identification of these housekeeping issues, the licensee captured this adverse performance trend in CARD 13-26082, Emerging Trend, for evaluation and identification of corrective actions. As stated in CARD 13-26082:

Site standards have slipped in work practices which result in plant cleanliness issues. Site standards have degraded in supervisory oversight of cleanliness and housekeeping.

Employees have accepted sub-standard conditions as normal.

.3 Annual Review of Operator Workarounds

a. Inspection Scope

The inspectors performed an in-depth review of operator workarounds and assessed the cumulative effect of existing workarounds and other operator burdens. The inspectors reviewed operator workarounds, Control Room deficiencies, temporary modifications, and lit annunciators. The inspectors verified operator workarounds were being identified at an appropriate threshold; the workarounds did not adversely impact operators ability to implement abnormal and emergency operating procedures; and, the cumulative effect of operator burdens did not adversely impact mitigating system functions. The inspectors also reviewed selected CARDs to verify appropriate corrective actions were proposed or implemented in a timely manner commensurate with the significance of the issue.

This inspection constituted one annual operator workaround review inspection sample as defined in IP 71152.

b. Findings

No findings were identified.

.4 Annual In-depth Review Samples

a. Inspection Scope

The inspectors selected the following issues for in-depth review:

• CARD 13-25574, EDG 14 Was Manually Shutdown During 24-Hour Run Surveillance; and

• CARD 13-21875, Design Stroke Time of E2150F015A/B Does Not Support Intent of USFAR Section 7.3.1.2.3.5.

As appropriate, the inspectors verified the following attributes during their review of the licensee's corrective actions for the above CARDs and other related CARDs:

• Complete and accurate identification of the problem in a timely manner commensurate with its safety significance and ease of discovery;

• Consideration of the extent of condition, generic implications, common cause, and previous occurrences;

• Evaluation and disposition of operability/reportability issues;

• Classification and prioritization of the resolution of the problem, commensurate with safety significance;

• Identification of the root and contributing causes of the problem; and

• Identification of corrective actions, which were appropriately focused to correct the problem.

The inspectors discussed the corrective actions and associated evaluations with licensee personnel.

This inspection constituted two annual in-depth review inspection samples as defined in IP 71152.

b. Findings

(1) Nonconforming Materials Used in EDG Air Coolant Piping System

Introduction:

A finding of very low safety significance (Green) with an associated NCV of 10 CFR 50, Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, was self-revealed on August 9, 2013, when operators had to manually shut down EDG 14 due to high air coolant system inlet temperature during a 24-hour surveillance test run. The high temperature condition occurred due to the licensees failure to adequately control the installation of the EDG 14 air coolant system control air pipe fitting between the relief valve and pressure regulator to prevent the use of materials that did not conform to design requirements.

Description:

On August 9, during the performance of a 24-hour surveillance test run of EDG 14, operators found that the engine air coolant control header relief valve (R3000F048D) was lifting and reseating very rapidly and the air cooler pressure regulator valve (R30FA01D) was oscillating between 0 - 30 pounds-per-square-inch-gage (psig).

These components are part of the EDG blowers air coolant system, which normally maintains temperature at the inlet of the blower at about 125°F. At the time, operators observed blower inlet temperature at 180°F. Operators subsequently lowered load on the engine from 2800 kilowatts to 2500 kilowatts in an attempt to lower temperature. Operators then observed the temperature had risen to about 210°F and manually shut down the engine to prevent damage. After the engine was shut down, operators found the control air fitting between the relief valve and pressure regulator had sheared, causing pressure oscillations in the control air system. The engine had been running for about 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> into the 24-hour test when the problem occurred. The licensee completed repairs to the EDG 14 air coolant system and returned the EDG to an operable status on August 11.

The EDG air coolant system is designed to maintain EDG blower air inlet temperature using an air cooler, blower, and heat exchanger. The intake air discharged from the turbocharger is cooled by the air cooler before entering the in-series blower. Heat is removed from the air cooler via the heat exchanger. A blower air inlet temperature transmitter (R30NA18D)provides a control input signal to a pneumatic temperature controller for a 3-way bypass cooling valve that modulates the volume of air cooler cooling flow through the heat exchanger to maintain the desired blower air inlet temperature. The air control system is designed such that a loss of control air should fail the system to full cooling. However, on August 9, failure of the transmitter caused the system to fail in full bypass (i.e., no cooling flow), which caused blower air inlet temperature to rise above engine design limits.

The licensee completed an equipment apparent cause evaluation for the EDG air coolant system failure and concluded the direct cause was that the control air pipe fitting between the relief valve and pressure regulator had sheared, which created pressure oscillations in the control air system that resulted in failure of the air cooler temperature transmitter. The licensee sent the temperature transmitter to a vendor laboratory for failure analysis. The vendor laboratory discovered a small amount of debris plugging the input-to-collector port of the transmitter. The debris material could not be identified due to the small amount available. The licensee surmised that the rapid 0-30 psig pressure oscillations in the control air system due to the sheared pipe fitting dislodged debris within the air system, which clogged the collector nozzle of the transmitter and forced the air coolant system into full bypass.

The licensee also sent the broken pipe fitting to a vendor laboratory for failure analysis.

The vendor laboratory determined the fitting failed due to high bending fatigue caused by the use of Schedule 40 pipe as opposed to Schedule 80 pipe along with the U-bolt mounting configuration of the relief valve and pressure regulator contributing to the thin wall pipe failing. The licensees design requirements (Drawing 6M721-N-2154 and Design Specification 3071-517) specified that all EDG air start and air coolant system control air piping 2 inches and smaller be Schedule 80. The licensee had previously found the pipe fitting broken during maintenance when it replaced the pressure regulator in 1988. The licensees engineering staff determined the pipe fitting was replaced with Schedule 40 pipe at that time under WO 013B881201. The pressure regulator was again replaced in 2005.

The licensees maintenance records reflect that the installed fitting was reused. Both the relief valve and pressure regulator were relatively large in size and were only supported by the use of one U-bolt on each valve. According to the vendors report, tightening of these U-bolts, especially the one around the pressure regulator, would likely cause front-to-back bending stresses in the pipe fitting. The U-bolt configuration that supported the connecting valves was installed as a design change in 1984. The licensees evaluation suggested that the new mounting configuration was possibly installed with a slight bending stress on the pipe fitting, which could have contributed to the failure. The originally installed relief valve was replaced in 2000 and again in 2006 during which time additional stresses could have been applied. The use of Schedule 40 vice Schedule 80 pipe and the U-bolt support configuration were each identified as apparent causes in the licensees evaluation.

Corrective actions identified in the licensees equipment apparent cause evaluation included:

• Completion of EDG 14 blower inspection and cylinder liner inspections following high blower air temperatures during the 24-hour run. No damage was found.

• Replacement of the failed EDG 14 air coolant inlet temperature transmitter.

• Replacement of the EDG 14 engine air coolant control header relief valve.

• Replacement of the EDG 14 air cooler pressure regulator valve.

• Replacement of the broken EDG 14 air cooling system control air fitting between the relief valve and pressure regulator pipe with a Schedule 80 fitting.

• Completion of EDG 14 post-maintenance testing and the 24-hour surveillance test run.

• Completion of failure analyses of the EDG 14 air coolant inlet temperature transmitter, relief valve, and broken Schedule 40 pipe fitting.

• Completion of extent-of-cause/condition evaluations and actions for EDGs 11, 12, 13, and 14. Actions included non-destructive examination of the air fittings between the relief valve and pressure regulator on EDGs 11, 12 and 13; and, non-destructive examination of other carbon steel piping in the EDG control air systems on all four EDGs.

The inspectors noted the licensee had not performed a detailed engineering evaluation of the EDG 14 air coolant system failure to determine the potential risk significance of the performance issue or to support its past operability/reportability conclusion. Operators declared EDG 14 inoperable after it was shut down on August 9. The EDG was last demonstrated operable about five weeks earlier during surveillance testing on July 3.

In response to the inspectors questions, the licensee initiated CARD 13-27974 and prepared a risk evaluation.

Analysis:

The inspectors determined the licensees failure to adequately control installation of the EDG 14 air coolant system control air pipe fitting between the relief valve and pressure regulator to prevent the use of materials which did not conform to design requirements was a performance deficiency warranting a significance evaluation. 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, Appendix B, Issue Screening, the inspectors determined the finding was associated with the Design Control attribute and adversely affected the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the EDG 14 air coolant system control air pipe fitting failure rendered the EDG inoperable. 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 would require a detailed risk evaluation because it represented an actual loss of function of a single train for greater than its TS allowed outage time.

The Region III Senior Reactor Analyst (SRA) evaluated the finding using the Fermi 2 Plant Standardized Plant Analysis Risk Model Version 8.22, Systems Analysis Programs for Hands-on Integrated Reliability Evaluations Version 8.0.9. The SRA determined that EDG 14 was not able to run for its 24-hour mission time due to the performance deficiency.

Since the degradation of the system was related to run time and the EDG ran for approximately 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> on August 9, the SRA concluded the exposure time for the finding should be from the time of the last surveillance test when the EDG successfully operated until the EDG failed to run on August 9. This exposure period was 39 days, which also includes the time the EDG was out of service for repair after it failed to run. The SRA modeled the finding as an EDG failure to run for 39 days. The delta core damage frequency (CDF) estimate was less than 1E-7/year, which is a finding of very low safety significance.

The dominant sequence involved the loss of an alternating current bus followed by the failure of decay heat removal systems and the failure of late injection. The finding was not evaluated for delta large early release frequency or external events since the internal events CDF was less than 1E-7/year. Based on the above, the SRA concluded the total risk increase to the plant due to this finding based on CDF was very low (Green).

The inspectors concluded that because the nonconforming control air pipe fitting was installed in the EDG 14 air coolant system in 1988 and the most recent missed opportunity to correct the problem occurred in 2005 or 2006, this issue would not be reflective of current licensee performance and no cross-cutting aspect was identified.

Enforcement:

10 CFR 50, Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, requires, in part, that measures be established to control materials, parts, or components which do not conform to requirements in order to prevent their inadvertent use or installation. The licensees design requirements for the EDG 14 safety-related small diameter air coolant system control air piping are contained, in part, in Drawing 6M721-N-2154, 2-Inch & Under Piping Material Specifications RHR Complex, Revision C, which specifies the use of Schedule 80 materials for the application.

Contrary to the above, during the performance of maintenance procedure WO 013B881201 on December 2, 1988, the licensee replaced the EDG 14 air coolant system control air pipe fitting between the relief valve and pressure regulator with a fitting made from Schedule 40 materials. This led to the failure of the pipe fitting on August 9, 2013, due to high bending fatigue. Because of the very low safety significance, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000351/2013005-05, Nonconforming Materials Used in EDG Air Coolant Piping System). The licensee entered this violation into its corrective action program as CARD 13-25574.

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

.1 (Closed) LER 05000341/2013-002-00, Reactor Core Isolation Cooling Isolation

Instrumentation Misconfigured Wiring The licensee submitted LER 05000341/2013-002-00 to report this event in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by the plants TSs due for an inoperable RCIC system isolation channel for longer than the TS completion time. The performance issue related to this event, the safety significance, the cause, and the corrective actions are discussed in detail in Section 1R12.1b.(1) of this inspection report. The inspectors determined the information provided in LER 05000341/2013-002-00 did not raise any new issues or change the conclusion of the initial review. Therefore, the violation of TS 3.3.6.1 described in Section 1R12.1b.(1) and in the LER will not be separately documented, and the LER is closed.

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

4OA5 Other Activities

.1 Review of Institute of Nuclear Power Operations (INPO) / World Association of Nuclear

Operators (WANO) Assessment Report The inspectors completed a review of the INPO/WANO Evaluation Report for the Fermi Power Plant, Unit 2 assessment conducted in May 2013. During this review, the inspectors did not identify any new safety significant issues.

.2 Review of INPO Training Accreditation Reports

The inspectors completed a review of the INPO Operations Training Accreditation Board Report dated October 17, 2013, and the INPO Maintenance and Technical Training Accreditation Board Report dated December 14, 2011. During this review, the inspectors did not identify any new safety significant issues.

4OA6 Management Meetings

.1 Resident Inspectors Exit Meeting

The inspectors presented the inspection results to Mr. M. Caragher and other members of the licensees staff on January 10, 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 inspection results from the Biennial Licensed Operator Requalification Program area assessment with Mr. J. Davis and other members of the licensees staff at the conclusion of the inspection on November 8, 2013;

• The inspection results from the Triennial Heat Sink Performance inspection with Mr. T. Conner and other members of the licensees staff on December 6, 2013; and

• The licensed operator requalification training biennial written examination and annual operating test results with Mr. J. Davis via telephone on December 16, 2013.

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

T. Barrett, Operations Training

S. Bollinger, Manager, Performance Improvement

M. Caragher, Director, Nuclear Engineering

T. Conner, Vice-President, Nuclear Generation

D. Coseo, Supervisor, Operations Training

J. Davis, Manager, Training

J. Ford, Director, Organization Effectiveness

S. Hassoun, Supervisor, Licensing and Environment

D. Hemmele, Superintendent, Operations

L. Keiser, Superintendent, I&C Maintenance

B. Mayes, Engineering Supervisor

C. McKinney, Engineering

H. Michael, Engineering

J. Pendergast, Principal Engineer, Licensing

L. Petersen, Manager, Plant Support Engineering

G. Piccard, Manager, Systems Engineering

Z. Rad, Manager, Licensing

W. Raymer, Assistant Manager, Maintenance

R. Salmon, Supervisor, Regulatory Compliance

K. Scott, Director, Nuclear Production

G. Strobel, Manager, Operations

J. Thorson, Manager, Performance Engineering

B. Weber, Principal Technical Specialist

H. Yeldell, Manager, Maintenance

Attachment

LIST OF ITEMS

Opened

05000341/2013005-01 NCV RHR Pump Seal Cooler Testing Was Not Adequately Implemented (Section 1R07.1b.(1))

05000341/2013005-02 NCV Acceptance Criteria for UHS Level and Temperature Did Not Consider Instrument Uncertainties (Section 1R07.1b.(2))

05000341/2013005-03 NCV Failure to Correctly Connect Thermocouple Wiring During Maintenance Resulted in Inoperable Reactor Core Isolation Cooling System Isolation Instrumentation (Section 1R12.1b.(1))

05000341/2013005-04 URI Evaluation of Apparent Unacceptable Preconditioning of High Pressure Coolant System Air Operated Valve Prior to Stroke Time Testing (Section 1R22b.(1))

05000341/2013005-05 NCV Nonconforming Materials Used in EDG Air Coolant Piping System (Section 4OA2.4b.(1))

Closed

05000341/2013005-01 NCV RHR Pump Seal Cooler Testing Was Not Adequately Implemented (Section 1R07.1b.(1))

05000341/2013005-02 NCV Acceptance Criteria for UHS Level and Temperature Did Not Consider Instrument Uncertainties (Section 1R07.1b.(2))

05000341/2013005-03 NCV Failure to Correctly Connect Thermocouple Wiring During Maintenance Resulted in Inoperable Reactor Core Isolation Cooling System Isolation Instrumentation (Section 1R12.1b.(1))

05000341/2013005-05 NCV Nonconforming Materials Used in EDG Air Coolant Piping System (Section 4OA2.4b.(1))

05000341/2013-002-00 LER Reactor Core Isolation Cooling Isolation Instrumentation Misconfigured Wiring (Section 4OA3.1)

Discussed

None