IR 05000259/2015007

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NRC Component Design Bases Inspection Report 05000259/2015007, 05000260/2015007 and 05000296/2015007
ML16033A462
Person / Time
Site: Browns Ferry  Tennessee Valley Authority icon.png
Issue date: 02/01/2016
From: Bartley J
NRC/RGN-II/DRS/EB1
To: James Shea
Tennessee Valley Authority
References
IR 2015007
Download: ML16033A462 (26)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ary 1, 2016

SUBJECT:

BROWNS FERRY NUCLEAR PLANT - NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000259/2015007, 05000260/2015007, AND 05000296/2015007

Dear Mr. Shea:

On December 18, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Browns Ferry Nuclear Plant, Units 1, 2, and 3 and discussed the results of this inspection with Mr. S. Bono and other members of your staff. Additional inspection results were discussed with Mr. L. Hughes and other members of the licensees staff on January 21, 2016. Inspectors documented the results of this inspection in the enclosed inspection report.

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

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

NRC inspectors documented two findings of very low safety significance (Green) in this report.

These findings involved violations of NRC requirements. The NRC is treating these violations as a non-cited violations (NCVs) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Browns Ferry Nuclear Plant.

If you disagree with the cross-cutting aspect assigned 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 II, and the NRC resident inspector at the Browns Ferry Nuclear Plant. In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Jonathan H. Bartley, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-259, 50-260, 50-296 License Nos.: DPR-33, DPR-52, DPR-68

Enclosure:

Inspection Report 05000259/2015007, 05000260/2015007 and 05000296/2015007 w/ Attachment: Supplementary Information

REGION II==

Docket Nos.: 50-259, 50-260, 50-296 License Nos.: DPR-33, DPR-52, DPR-68 Report Nos.: 05000259/2015007, 05000260/2015007 and 05000296/2015007 Licensee: Tennessee Valley Authority (TVA)

Facility: Browns Ferry Nuclear Plant, Units 1, 2, and 3 Location: Corner of Shaw and Nuclear Plant Road Athens, AL 35611 Dates: November 16, 2015 - December 18, 2015 Inspectors: W. Deschaine, Resident Inspector (Lead)

G. Ottenberg, Senior Reactor Inspector D. Terry-Ward, Construction Inspector R. Patterson, Reactor Inspector J. Chiloyan (Electrical)

M. Yeminy (Mechanical)

Approved by: Jonathan Bartley, Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY

IR 05000259/2015007, 05000260/2015007, 05000296/2015007; 11/16/2015 - 12/18/2015;

Browns Ferry Nuclear Plant, Units 1, 2 and 3; Component Design Bases Inspection.

This inspection was conducted by a team of three Nuclear Regulatory Commission (NRC)inspectors from Region II, one resident inspector, and two NRC contract personnel. Two Green non-cited violations (NCVs) were identified. The significance of inspection findings is indicated by their color (Green, White, Yellow, Red) using the NRC Inspection Manual Chapter (IMC)0609, Significance Determination Process, dated April 29, 2015. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green.

A NRC-identified non-cited violation (NCV) of Technical Specifications (TS)5.4.1 was identified for the failure to develop a preventive maintenance (PM) schedule that specified inspection of the Emergency Diesel Generators (EDG) neutral grounding resistor as recommended by Regulatory Guide (RG) 1.33, 9.b. Specifically, procedures failed to provide proper guidance to maintain the grounding resistor in accordance with design basis as described in the UFSAR and electrical calculations. Upon identification of the issue, the licensee performed a visual inspection of the resistor and determined that it was functional based on no signs of physical degradation or damage. The licensee entered this issue into the corrective action program (CAP) as CR1114779 to evaluate and implement appropriate corrective actions.

This performance deficiency was more than minor because if left uncorrected it could result in a more significant safety concern. Specifically, lack of inspections of the secondary grounding resistor could allow for an undetected condition which would cause transient voltages capable of damaging safety related equipment. The finding was screened for significance using the Mitigating Systems cornerstone column of IMC 0609,

Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, dated June 19, 2012, and was determined to be of very low safety significance (Green) using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding affected the design or qualification of a Mitigating SSC, and the SSC maintained its operability as documented in CR 1114779. No cross-cutting was assigned because it is not indicative of current licensee performance. (Section 1R21.2)

Cornerstone: Barrier Integrity

Green.

A NRC identified NCV of 10 Code of Federal Regulations (CFR) Part 50,

Appendix B, Criterion XI, Test Control, was identified for the failure to specify adequate test instrumentation for performing MSIV leak rate testing. Specifically, the licensee test procedure allowed the use of high range test instruments to measure low leakage rates while performing the combined leak rate testing on the Unit 1 B Main Steam Line. This resulted in instrument uncertainties large enough to impact the validity of the test results.

The licensee immediately entered this issue into their corrective action program as CR 1117381. The licensee performed an evaluation and determined that the latest test results provided reasonable assurance of operability.

This performance deficiency was more than minor because if left uncorrected had the potential to lead to a more significant safety concern by masking the failure to meet test acceptance criteria. The finding was screened for significance using the Barrier Integrity cornerstone column of IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, dated 7/1/2012, and IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated 7/1/2012, and was determined to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment.

This finding was assigned a cross-cutting aspect in the area of Problem Identification and Resolution because the licensee did not initiate a corrective action to identify the cause of the negative leak rate results obtained during the recent performance of the test procedure (P.1). (Section 1R21.2)

Licensee-Identified Violations

A violation of very low safety significance which was identified by the licensee was reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program (CAP). That violation and corrective action tracking number are listed in Section 4OA7 of this report.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R21 Component Design Bases Inspection

Main article: IP 71111.21M

.1 Inspection Sample Selection Process

The team selected risk-significant components and related operator actions for review using information contained in the licensees probabilistic risk assessment. In general, this included components and operator actions that had a risk achievement worth factor greater than 1.3 or Birnbaum value greater than 1E-6. The sample included 12 components, two of which were associated with containment large early release frequency (LERF), and two operating experience (OE) items.

The team performed a margin assessment and a detailed review of the selected risk-significant components and associated operator actions to verify that the design bases had been correctly implemented and maintained. Where possible, this margin was determined by the review of the design basis and Updated Final Safety Analysis Report (UFSAR) response times associated with operator actions. This margin assessment also considered original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for a detailed review. These reliability issues included items related to failed performance test results, significant corrective action, repeated maintenance, maintenance rule status, Manual Chapter 0326 conditions, NRC resident inspector input regarding problem equipment, system health reports, industry OE, and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, OE, and the available defense-in-depth margins. An overall summary of the reviews performed and the specific inspection findings identified is included in the following sections of the report.

.2 Component Reviews

a. Inspection Scope

Components

  • Unit 2 Main Bank Battery (B)
  • 480 Volt (V) Alternating Current (AC) Reactor Motor Operated Valve (RMOV)

Board 1B

  • 250 V RMOV Board 1A
  • Units 1 and 2 4160V Shutdown Board A
  • Unit 2 HPCI System Inboard Isolation Motor-Operated Valve (MOV)
  • Unit 1 & 2 EDG Ventilation System
  • Unit 1 C RHR Heat Exchanger Components with LERF Implications

For the 14 components listed above, the team reviewed the plant technical specifications (TS), UFSAR, design bases documents (DBDs), and drawings to establish an overall understanding of the design bases of the components. Applicable design calculations and procedures were reviewed to verify that the design and licensing bases had been appropriately translated into these documents. Test procedures and recent test results were reviewed against DBDs to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents, and that individual tests and analyses served to validate component operation under accident conditions.

Maintenance procedures were reviewed to ensure components were appropriately included in the licensees preventive maintenance program. System modifications, vendor documentation, system health reports, preventive and corrective maintenance history, and corrective action program documents were reviewed (as applicable) in order to verify that the performance capability of the component was not negatively impacted, and that potential degradation was monitored or prevented. Maintenance Rule information was reviewed to verify that the component was properly scoped, and that appropriate preventive maintenance was being performed to justify current Maintenance Rule status. Component walkdowns and interviews were conducted to verify that the installed configurations would support their design and licensing bases functions under accident conditions and had been maintained to be consistent with design assumptions.

Additionally, the team performed the following component-specific reviews:

  • The team observed a simulator scenario involving the alignment of one train of the RHR system into the suppression pool cooling mode of operation following a loss of coolant accident to verify the design conditions assumed for the RHR loop II pump test return MOV were in alignment with the conditions imposed by the operating procedure.
  • The team reviewed the most recent MOV diagnostic testing results for the RHR loop II pump test return MOV and the HPCI inboard isolation MOV to verify current MOV parameters are bounded by their requirements and capability assumptions.
  • The team observed EECW system and check valve testing on 12/1/15, to verify appropriate system configurations were used to confirm the EECW north and south header check valves were meeting American Society of Mechanical Engineers (ASME) Operations and Maintenance (OM) Code testing requirements.
  • The team verified the licensee was testing the EECW check valves in accordance with their ASME OM Code of record requirements for the check valve condition monitoring program.
  • The team observed a performance test of the 1C RHR heat exchanger.
  • The team reviewed photographs of macro fouling (clam shells) found in March 2015 inside the 2C heat exchanger.
  • The team reviewed the validity of an uncontrolled MathCad analysis of heat exchanger test results which was used to determine Past Operability of the 2C RHR heat exchanger, including a review of a missing MathCad file that had to be resurrected during the inspection.
  • The team reviewed the adequacy of a third party (Zachry) analysis of the as tested fouling factors associated with the 2A and 2C RHR heat exchangers and assessed the magnitude of the error inherent in incorrect input of the number of plugged tubes.
  • The team reviewed the validity of methodology, assumptions and values used in 10 CFR 50, Appendix J testing.
  • The team reviewed the data used to ascertain that the Feedwater containment isolation valves have passed their inservice testing acceptance criteria.
  • The team performed independent calculations of available fault current contributions from the emergency diesel generator and from the offsite sources for postulated phase and ground faults and compared them with the relay settings calculations in Electrical Transient Analysis Program (ETAP) to verify the appropriateness of the applied overcurrent relay settings.
  • The team reviewed Shutdown Board A loss of voltage and bus overcurrent relay settings to ensure adequate coordination was maintained between the bus overcurrent and bus under voltage relay settings to ensure the overcurrent relays function as designed during postulated electrical bus faults.
  • The team reviewed the degraded voltage relay settings to verify whether they bounded the TS requirements.
  • Protective relay setpoint calculations and setpoint calibration test results were reviewed to assess the adequacy of protection during testing and emergency operations.
  • The permissive and interlocks associated with the EDG B output breaker were reviewed to determine whether the breaker opening and closing control circuits were consistent with design basis documents.
  • The team selectively reviewed board and breaker ratings, load flow calculations, degraded voltage calculations, and protective device settings, to confirm that the MOV board would be capable of supplying the necessary loads for mitigating design bases events and for achieving safe shutdown in accordance with the design bases.
  • The team selectively reviewed electrical one-line diagrams, loading calculations, voltage drop calculations, short-circuit calculations, and associated electrical protection to determine the capability of the 250 V direct current (DC) RMOV Board 1A to serve the required power to 250 VDC downstream loads in accordance with the design and licensing basis as well as for station blackout events.
  • Battery sizing, loading, and voltage calculations were reviewed, as were maintenance and operational procedures, in order to verify that design bases and design assumptions have been appropriately translated into design calculations and procedures.
  • Battery room temperature and ventilation for hydrogen gas during charging evaluations were reviewed to verify that the equipment qualification was suitable for the environment expected under all conditions.

b. Findings

.1 Failure to Specify Adequate Instrument Ranges for MSIV Leakage Testing

Introduction:

A Green, NRC-identified non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XI, Test Control, was identified for the failure to specify adequate test instrumentation for performing MSIV leak rate testing. Specifically, the licensee test procedure allowed the use of high range test instruments to measure low leakage rates while performing the combined leak rate testing on the Unit 1 B Main Steam Line. This resulted in instrument uncertainties large enough to impact the validity of the test results.

Description:

On October 25, 2014, the licensee performed MSIV combined leak rate testing in accordance with procedure 1-SR-3.6.1.3.10(B), Primary Containment Local Leak Rate Test Main Steam Line B: Penetration X-7B, revision 4, to satisfy the requirements in the sites Containment Leak Rate Program. 10 CFR 50, Appendix B, Criterion XI required that the licensee establish a test program to ensure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service was identified and performed in accordance with written test procedures and that test procedures include provisions for assuring that adequate test instrumentation was available and used.

The primary function of the MSIVs is to prevent damage to the fuel barrier and limit release of radioactive materials by closing the primary containment barrier. This local leak rate test (LLRT) was performed to quantify the leakage through Main Steam Line B primary containment isolation valves 1-FCV-1-26 and 1-FCV-1-27 and demonstrate the following:

1. Leakage through 1-FCV-1-26 and 1-FCV-1-27 was within the limit specified by Technical Specification Surveillance Requirement 3.6.1.3.10.

2. The combined main steam line path leak rate was within the limits specified by Technical Specification SR 3.6.1.3.10.

Leak rates obtained by the performance of this procedure were tabulated to demonstrate whether or not the combined main steam line path leak rate was within the limits specified in the technical specification when primary containment is being established or maintained. The team identified that the B Main Steam Isolation Valve testing indicated that the inboard valve had a negative leak rate which wasnt possible. For the test results the licensee evaluated the negative leak rates as being zero leakage. The licensee did not initiate a corrective action to evaluate the cause of the negative leakage rate test results. During the teams review of the tabulated test results, the team questioned whether or not the licensee considered instrument uncertainties when evaluating test results. The team identified that, while performing the combined leakage test on the B Main Steam Line, a 0-800 standard cubic feet per hour (scfh) gauge was used to measure a leak rate of 25 scfh and the test evaluator did not account for the

+/- 2% (16scfh) error associated with the test instrument when evaluating the test results. Using larger range instruments yield higher uncertainties and present testing results that can potentially mask the failure to meet the test acceptance criteria. The team concluded that the licensee failed to establish adequate measures to ensure that testing equipment used to perform combined leak rate test was appropriate for the application and therefore, had adversely affected the ability to accurately characterize the as-found condition. The licensee immediately entered this issue into their corrective action program as CR 1117381. The licensee performed an evaluation and determined that the latest test results provided reasonable assurance of operability.

Analysis:

The licensees failure to specify adequate instrument test ranges was a performance deficiency. Specifically, while performing the combined leakage test on the B Main Steam Line a 0-800 scfh gauge was used to measure leak rate of 25 scfh. The significant uncertainty of the gauge could mask the failure to meet the test acceptance criteria. This performance deficiency was more than minor because if left uncorrected had the potential to lead to a more significant safety concern by masking the failure to meet test acceptance criteria. The finding was screened for significance using the Barrier Integrity cornerstone column of IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, dated 7/1/2012, and IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated 7/1/2012, and was determined to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment.

This finding was assigned a cross-cutting aspect in the area of Problem Identification and Resolution because the licensee did not initiate a correct action to identify the cause of the negative leak rate results obtained during the recent performance of the test procedure (P.1).

Enforcement:

10 CFR 50, Appendix B, Criterion XI, Test Control requires, in part, that a test program shall 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 and that test procedures include provisions for assuring that adequate test instrumentation is available and used.

Contrary to the above, on July 16, 2014, the licensee did not establish written procedures that included provisions to assure that adequate test instrumentation was used. Specifically, MSIV LLRT test procedures did not specify the appropriate range of test instrumentation to ensure instrument uncertainty did not mask the failure to meet test acceptance criteria. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees CAP as CR 1117381. (NCV 05000259, 260, 296/2015007: Failure to Specify Adequate Instrument Ranges for MSIV Leakage Testing)

.2 Failure to develop a PM schedule that specified inspection of the EDG neutral grounding

resistor

Introduction:

A Green NRC-identified non-cited violation (NCV) of TS 5.4.1 was identified for the licensees failure to develop a PM schedule that specified inspection of the Emergency Diesel Generators (EDG) neutral grounding resistor as recommended by RG 1.33, 9.b. Specifically, procedures failed to provide proper guidance to maintain the grounding resistor in accordance with design basis as described in the UFSAR and electrical calculations.

Description:

As described in the BFN UFSAR Section 8.5.3.2, each diesel generator is wye-connected with its neutral grounded through a distribution transformer and secondary resistor. This method of grounding is to provide a high-resistance grounding system to limit ground fault current contribution from the EDGs for postulated ground faults on the 4160V safe shutdown boards and associated feeders. The ground fault current is limited to a few amperes to minimize equipment damage due to transient overvoltages present in an ungrounded system, and to allow uninterrupted operation of EDG and connected loads under the presence of a single fault to ground. In the event the secondary resistor was degraded to the point that it would look like an open circuit the EDG would become an ungrounded system, and it may not reveal its condition during routine surveillance testing. This would allow transient voltages to exist on the system that would be capable of damaging safety related equipment. A failure of this resistor could go undetected and result in damage to safety related equipment.

Technical Specifications 5.4.1, Procedures, requires the licensee to establish implement and maintain the applicable procedures recommended in Regulatory Guide (RG) 1.33.

Regulatory Guide 1.33, Section 9.b states that preventative maintenance schedules be developed to specify inspections of equipment. The team identified that the licensee had not implemented preventative maintenance (PM) schedules to inspect the secondary resistor for degradation that could impact its design function. Upon the teams identification of the issue, the licensee performed a visual inspection of the resistor and determined that it was functional based on no signs of physical degradation or damage.

The licensee entered this issue into the corrective action program (CAP) as CR1114779 to evaluate and implement appropriate corrective actions.

Analysis:

The licensees failure to develop a PM schedule that specified inspection of the EDG neutral grounding resistor as recommended by RG 1.33, 9.b was a performance deficiency. This performance deficiency was more than minor because if left uncorrected it could result in a more significant safety concern. Specifically, lack of inspections of the secondary grounding resistor could allow for an undetected condition which would cause transient voltages capable of damaging safety related equipment.

The finding was screened for significance using the Mitigating Systems cornerstone column of IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, dated June 19, 2012, and was determined to be of very low safety significance (Green) using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, because the finding affected the design or qualification of a Mitigating SSC, and the SSC maintained its operability as documented in CR 1114779. No cross-cutting was assigned because it is not indicative of current licensee performance.

Enforcement:

Technical Specification 5.4.1 required that, written procedures shall be established, implemented, and maintained covering applicable procedures recommended in Regulatory Guide 1.33, revision 2, appendix A, February 1978.

Regulatory Guide 1.33, appendix A, Section 9.b states, in part, that preventive maintenance schedules should be developed to specify inspections of equipment.

Contrary to the above, since 1995 the licensee failed develop a PM schedule that specified inspection of the EDG neutral grounding resistor to assure that the EDG grounding resistor would be able to maintain its safety function and ensure the operability of safety-related EDGs during a design basis event. Upon the teams identification of the issue, the licensee performed a visual inspection of the grounding resistor to verify its current functionality and entered the issue in their CAP to evaluate and implement appropriate monitoring measures. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees CAP as CR 1114779. (NCV 05000259, 260, 296/2015007-02, Failure to develop a PM schedule that specified inspection of the EDG neutral grounding resistor)

.3 (Opened) Procurement of Electrical Equipment for Ungrounded Electrical Systems

Introduction:

The team identified an unresolved item (URI) related to the licensees procurement of electrical equipment for ungrounded electrical systems.

Description:

The 480 VAC system for each unit consists of 480-V Load Center Unit Substations with each substation consisting of 4160-480-V transformers, primary terminal box, and close-coupled or bus duct connected 480-V, metal-enclosed switchgear. The 480-VAC distribution system is three-phase ungrounded. Each substation bus is normally fed from its own transformer, with an alternate source consisting either of an adjacent 480-VAC bus section or of another transformer serving as standby. Ventilated dry-type transformers are three-phase, delta-delta configuration so that the 480 VAC system is ungrounded.

Ungrounded systems are susceptible to overvoltage conditions resulting from a single line to ground fault. A line to ground fault will result in a sustained higher voltage to ground on the ungrounded phases. Industry standard IEEE 242 (Buff Book) Protection and Coordination of Industrial and Commercial Power Systems, section 8.2.5 Ungrounded Systems stated if this ground fault is intermittent or allowed to continue, the system could be subjected to possible severe overvoltages to ground, which can be high(cause line to ground voltages several times normal voltage on all three phases).

Because of the potential for overvoltage conditions, specifications, purchase orders or procurement documents for equipment such as motors, cables, and switchgear should identify that the equipment is intended for use on an ungrounded system.

The team requested the original specifications for the installed BFN safety-related motors BFN-2-MTR-068-0003; 2-FCV-68-3 (Recirc Pump 2A Disch VLV) fed from the 480V Reactor MOV Board 2E and, BFN-3-MTR-073-0002; 3-FCV-73-2 (HPCI Steam Line INBD Isolation VLV) fed from the 480V Reactor MOV Board 3A to determine if the intended service condition as a 480 VAC ungrounded system was appropriately identified. The team reviewed Procurement Engineering Group packages CRP205J -

PO 733602 and CFK570P - PO 836093 for the safety-related motors and determined that the ungrounded system requirement was not identified.

Equipment intended for service on ungrounded systems is designed to withstand the sustained higher line to ground voltages than can occur on grounded systems. These insulation systems are not typically provided unless the purchaser specifies an ungrounded system. Industry standard NEMA MG 1 Motors and Generators, section 14.31 Machines Operating On An Ungrounded System stated:

Alternating-current machines are intended for continuous operation with the neutral at or near ground potential. Operation on ungrounded systems with one line at ground potential should be done only for infrequent periods of short duration, for example as required for normal fault clearance. If it is intended to operate the machine continuously or for prolonged periods in such conditions, a special machine with a level of insulation suitable for such operation is required.

The motor manufacturer should be consulted before selecting a motor for such an application.

The NRC will review the licensees responses to follow-up questions asked during a conference call with the licensee on January 21, 2016. Based on this future review, the NRC will make a determination if the licensee properly procured electrical components for ungrounded systems. More information is needed to determine if more than a minor performance deficiency or violation exists associated with this issue, thus a URI is being opened. (URI 05000259, 260, 296/2015007-03, Procurement of Electrical Equipment for Ungrounded Electrical Systems).

.3 Operating Experience

a. Inspection Scope

The team reviewed two operating experience issues for applicability at the Browns Ferry Nuclear Power Station. The team performed an independent review of these issues and, where applicable, assessed the licensees evaluation and dispositioning of each item. The issues that received a detailed review by the team included:

  • NRC IN 90-43, Mechanical Interference with Thermal Trip Function in GE Molded-Case Circuit Breakers

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On December 18, 2015, the team presented the inspection results to Mr. S. Bono and other members of the licensees staff. Additional inspection results were discussed with Mr. L. Hughes and other members of the licensees staff on January 21, 2016. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

4OA7 Licensee-identified Violations

The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

Technical Specification 5.4.1, required, in part, that written procedures shall be established, implemented, and maintained covering the following activities: a. the applicable procedures recommended in Regulatory Guide (RG) 1.33, Rev 2, Appendix A. Procedures recommended in Appendix A to RG 1.33, included procedures for performing maintenance, and specifically, preventive maintenance schedules should be developed to specifyinspections of equipment. 0-TI-522, Program for Implementing NRC Generic Letter 89-13 required in part, in section 7.2, that BFN will maintain an inspection and cleaning program in accordance with the BFN PM Program to verify the heat transfer capability of the safety related Heat Exchangers cooled by EECW an RHRSW, and the PMs provide for reassessing this inspection frequency based on the results of inspections, not to exceed 5 years. Contrary to this requirement, since January 22, 2013, the licensee did not implement their PM schedule for inspections of the 3C RHR HX appropriately, because they allowed the PM to extend beyond the maximum of 5 years. Consequently, when the heat exchanger was opened, it failed the acceptance criterion of no more than 77 tubes plugged. This finding was not greater than very low safety significance (Green) because it was a deficiency affecting the design of a Mitigating SSC, and the SSC maintained its operability or functionality (as demonstrated by past operability evaluation for PERs 750848 and 750858). The licensee entered this issue into their CAP as CR 674040.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

S. Bono, Site Vice President
L. Hughes, General Plant Manager
P. Summers, Director of Safety and Licensing
J. Paul, Nuclear Site Licensing Manager
M. McAndrew, Manager of Operations
D. Campbell, Superintendent of Operations
M. Kirschenheiter, Assistant Director for Site Engineering
K. Groom, Design Engineering Manager
R. Jarrett, Corp Design
P. Wilson, Corp Licensing
T. Scott, QA Manager
W. Anderson, Plant Support
P. Derriso, Engineering
M. Acker, Licensing Engineer
T. Cole, Radiation Protection
J. Smith, System Engineer
P. Campbell, System Engineer
K. Skinner, System Engineer
L. Holland, System Engineer
D. Ford, System Engineer
D. Jackson, RHRSW/EECW System Engineer
J. Lacasse, RHR System Engineer
C. McDonald, Site MOV Program Engineer
E. Ridgell, IST Program Engineer

NRC personnel

M. Farnan, Mechanical Engineer, Office of Nuclear Reactor Regulation (NRR)

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened and Closed

05000259,260,296/2015007-01: NCV Failure to Specify Adequate Instrument Ranges for MSIV Leakage Testing [Section 1R21.2]
05000259,260,296/2015007-02: NCV Failure to develop a PM schedule that specified inspection of the EDG neutral grounding resistor [Section 1R21.2]

Opened

05000259,260,296/2015007-03: URI Procurement of Electrical Equipment for Ungrounded Electrical Systems [Section 1R21.2]

LIST OF DOCUMENTS REVIEWED

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