05000259/LER-2013-006, Regarding 1B Standby Liquid Control Pump Inoperable for Longer than Allowed by the Technical Specifications

Regarding 1B Standby Liquid Control Pump Inoperable for Longer than Allowed by the Technical Specifications

ML13343A153
Person / Time
Site:	Browns Ferry
Issue date:	12/03/2013
From:	Polson K Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
LER 13-006-00
Download: ML13343A153 (9)

LER-2013-006, Regarding 1B Standby Liquid Control Pump Inoperable for Longer than Allowed by the Technical Specifications

Event date:
Report date:
Reporting criterion:	10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications 10 CFR 50.73(a)(2)(i) 10 CFR 50.73(a)(2)(vii), Common Cause Inoperability 10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded 10 CFR 50.73(a)(2)(viii)(A) 10 CFR 50.73(a)(2)(ii)(B), Unanalyzed Condition 10 CFR 50.73(a)(2)(viii)(B) 10 CFR 50.73(a)(2)(iii) 10 CFR 50.73(a)(2)(ix)(A) 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(x) 10 CFR 50.73(a)(2)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.73(a)(2)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown 10 CFR 50.73(a)(2)(v), Loss of Safety Function
2592013006R00 - NRC Website

text

Tennessee Valley Authority, Post Office Box 2000, Decatur, Alabama 35609-2000 December 3, 2013 10 CFR 50.73 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Browns Ferry Nuclear Plant, Unit 1 Renewed Facility Operating License No. DPR-33 NRC Docket No. 50-259

Subject:

Licensee Event Report 50-259/2013-006-00 The enclosed Licensee Event Report provides details of an event which resulted in the 1 B Standby Liquid Control pump being inoperable for longer than allowed by the Technical Specifications. The Tennessee Valley Authority is submitting this report in accordance with Title 10 of the Code of Federal Regulations (10 CFR) 50.73(a)(2)(i)(B).

There are no new regulatory commitments contained in this letter. Should you have any questions concerning this submittal, please contact J. L. Paul, Nuclear Site Licensing Manager, at (256) 729-2636.

Respectful K. J. ols r residen

Enclosure:

Licensee Event Report 50-259/2013-006 1 B Standby Liquid Control Pump Inoperable For Longer Than Allowed By The Technical Specifications cc (w/ Enclosure):

NRC Regional Administrator - Region II NRC Senior Resident Inspector - Browns Ferry Nuclear Plant

ENCLOSURE Browns Ferry Nuclear Plant Unit I Licensee Event Report 50-259/2013-006-00 1 B Standby Liquid Control Pump Inoperable For Longer Than Allowed By The Technical Specifications See Enclosed

NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB NO. 3150-0104 EXPIRES 10/31/2013 (10-2010)

, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

3. PAGE Browns Ferry Nuclear Plant, Unit 1 05000259 1 of 7

4. TITLE: 1 B Standby Liquid Control Pump Inoperable For Longer Than Allowed By The Technical Specifications

5. EVENT DATE

6. LER NUMBER

7. REPORT DATE

8. OTHER FACILITIES INVOLVED IFACILITY NAME DOKT NUMBER MONTH DAY YEAR YEAR SEQUENTIAL REV MONTH DAY YEAR N/A DOCKE M N H D Y EA YER NUMBER NO.N/05 0

FACILITY NAME DOCKET NUMBER 10 04 2013 2013 -

006 00 12 03 2013 N/A 05000

9. OPERATING MODE

11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR §: (Check all that apply)

[O 20.2201(b) 0l 20.2203(a)(3)(i)

[I 50.73(a)(2)(i)(C)

El 50.73(a)(2)(vii)

[o 20.2201(d)

[I 20.2203(a)(3)(ii)

[I 50.73(a)(2)(ii)(A)

El 50.73(a)(2)(viii)(A)

[1 20.2203(a)(1)

[I 20.2203(a)(4) 0l 50.73(a)(2)(ii)(B)

El 50.73(a)(2)(viii)(B)

El 20.2203(a)(2)(i)

El 50.36(c)(1)(i)(A) 0l 50.73(a)(2)(iii)

[I 50.73(a)(2)(ix)(A)

10. POWER LEVEL [I 20.2203(a)(2)(ii)

[I 50.36(c)(1)(ii)(A)

[I 50.73(a)(2)(iv)(A)

[I 50.73(a)(2)(x)

[I 20.2203(a)(2)(iii)

El 50.36(c)(2)

El 50.73(a)(2)(v)(A)

El 73.71(a)(4) 0l 20.2203(a)(2)(iv)

El 50.46(a)(3)(ii) 0l 50.73(a)(2)(v)(B) 0l 73.71(a)(5) 100 [1 20.2203(a)(2)(v) 0l 50.73(a)(2)(i)(A) 0l 50.73(a)(2)(v)(C) 0l OTHER El 20.2203(a)(2)(vi) 0 50.73(a)(2)(i)(B)

El 50.73(a)(2)(v)(D)

SpirlYcfiAbstract beloworin NRC Form1 368A

12. LICENSEE CONTACT FOR THIS LER FACILITY NAME TELEPHONE NUMBER (Include Area Code)

Eric Bates, Licensing Engineer 256-614-7180CA MANU-REPORTABLE MANU-REPORTABLE USE SYSTEM COMPONENT EPIXCAUSE SY FACTURER TO EPIX X

BR BKR G080 Y

14. SUPPLEMENTAL REPORT EXPECTED

15. EXPECTED MONTH DAY YEAR SUBMISSION U

YES (If yes, complete 15. EXPECTED SUBMISSION DATE)

[]

NO DATE N/A N/A N/A ABSTRACT (Limit to 1400 spaces, i.e., approximately 15 single-spaced typewritten lines)

On October 4, 2013, Browns Ferry Nuclear Plant (BFN) discovered, by performing a past operability evaluation, that the 1 B Standby Liquid Control (SLC) pump was inoperable from December 1, 2012, at approximately 0145 hours0.00168 days <br />0.0403 hours <br />2.397487e-4 weeks <br />5.51725e-5 months <br /> Central Standard Time (CST) to February 14, 2013 at approximately 0625 hours0.00723 days <br />0.174 hours <br />0.00103 weeks <br />2.378125e-4 months <br /> CST.

On February 13, 2013, during performance of surveillance instruction 1-SI-4.4.A.1, Standby Liquid Control Pump Functional Test, an Assistant Unit Operator manually tripped the 1 B SLC pump motor breaker when no water was observed flowing through the 1 B SLC pump and the 1 B SLC pump motor was producing a loud humming noise.

The root cause was determined to be an undetected crack in a 1 B SLC pump motor breaker's phase arc chute that fatigued over time, broke apart, and inadvertently insulated the contacts. The 1 B SLC pump was considered inoperable when the plant entered the mode of applicability on December 1, 2012, at approximately 0145 hours0.00168 days <br />0.0403 hours <br />2.397487e-4 weeks <br />5.51725e-5 months <br /> CST.

The corrective actions to prevent recurrence are: (1) revise procedures to include enhanced arc chute inspection to ensure sustainability, and (2) implement BFN, Units 1, 2, and 3, Engineering Change Packages to replace applicable safety related GE AK breakers.

NRC FORM 366 (10-2010)

1.

Plant Operating Conditions Before the Event

At the time of discovery, Browns Ferry Nuclear Plant (BFN), Unit 1, was in Mode 1 at approximately 100 percent power.

II.

Description of Events A. Event:

On February 13, 2013, during the performance of 1-SI-4.4.A.1, Standby Liquid Control Pump Functional Test, the 1 B SLC pump ran for approximately 25 seconds before water flow stopped. An Assistant Unit Operator (AUO) then turned the 1 B SLC pump off in the field by tripping the pump breaker [BKR]. Operations personnel had previously declared the 1 B SLC inoperable for the performance of surveillance instruction 1-SI-4.4.A. 1.

On February 14, 2013, at approximately 0625 hours0.00723 days <br />0.174 hours <br />0.00103 weeks <br />2.378125e-4 months <br /> CST, after successful repair and performance of surveillance instruction 1-SI-4.4.A.1, Operations personnel declared 1 B SLC pump Operable and exited Technical Specifications (TS) Limiting Conditions for Operation (LCO) 3.1.7 Condition A, one SLC subsystem inoperable.

On October 4, 2013, BFN discovered, by performing a past operability evaluation, that the 1 B Standby Liquid Control (SLC) [BR] pump [P] was inoperable from December 1, 2012, at approximately 0145 hours0.00168 days <br />0.0403 hours <br />2.397487e-4 weeks <br />5.51725e-5 months <br /> Central Standard Time (CST) to February 14, 2013 at approximately 0625 hours0.00723 days <br />0.174 hours <br />0.00103 weeks <br />2.378125e-4 months <br /> CST.

It was determined from the past operability evaluation that the last successful performance of the functional test of the 1 B SLC pump was on November 20, 2012, during a refueling outage. BFN, Unit 1, entered the applicability of TS LCO 3.1.7, Standby Liquid Control (SLC) System, on December 1, 2012, without the required SLC subsystem being Operable contrary to the requirements of TS LCO 3.0.4.

TS LCO 3.0.4 prohibits entering the mode of applicability when a LCO is not met, except when certain conditions exist that were not applicable to this event.

In addition, during the period from December 1, 2012 to February 14, 2013, when the 1 B SLC pump was inoperable, the IA SLC pump was also concurrently inoperable. From February 12, 2013, to February 13, 2013, the 1A SLC pump was inoperable and TS 3.1.7 Condition B was entered. The associated TS 3.1.7 Required Action B. 1, that requires one of the two SLC subsystems to be restored to Operable status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, was satisfied within the required 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time.

B. Status of structures, components, or systems that were inoperable at the start of the event and that contributed to the event

There were no structures, components, or systems that were inoperable at the start of the event and that contributed to the event.

1. Automatically and manually initiated safety system responses

There were no automatically or manually initiated safety system responses for this event.

Ill.

Cause of the event

A. The cause of each component or system failure or personnel error, if known:

Direct Cause The direct cause of the 1 B SLC pump motor breaker requiring to be manually tripped during surveillance instruction 1-SI-4.4.A. 1 was a piece of nonconductive foreign material. The nonconductive foreign material prevented contact closure between the contacts for one phase on the 1 B SLC pump motor breaker and its matching contacts on the 1 B SLC pump motor breaker cubicle.

Root Cause The root cause was determined to be an undetected crack in the 1 B SLC pump motor breaker's 'A' phase arc chute that fatigued over time.

B. The cause(s) and circumstances for each human performance related root

cause

There were no human performance related root causes for this event.

IV.

Analysis of the event

The Tennessee Valley Authority (TVA) is submitting this report in accordance with 10 CFR 50.73(a)(2)(i)(B), as any operation or condition which was prohibited by the plant's TS.

After inspection of the 1 B SLC pump breaker, the 'A' phase arc chute revealed it was discolored and damaged. The broken section of the 'A' phase arc chute was removed, breaker cleaned, and the 'A' phase arc chute replaced. The 1B SLC pump motor breaker was reinstalled and the performance of surveillance instruction 1 -SI-4.4.A. 1 was completed satisfactorily on February 14, 2013. Prior to the 1B SLC pump motor breaker failure, the last successful performance of surveillance instruction 1-SI-4.4.A.1 was performed on November 20, 2012.

The root cause analysis for the 1 B SLC pump motor breaker failure determined that the direct cause was nonconductive foreign material which broke off of the 'A' phase arc chute. This nonconductive foreign material became wedged between the contacts for one phase on the 1 B SLC pump motor breaker and its matching contacts on the 1 B SLC pump motor breaker cubicle which prohibited the 1B SLC pump motor from being supplied by its required three phase power. The blocked contacts only allowed single phase power to be supplied to the 1 B SLC pump motor.

Although the 1 B SLC pump motor breaker had been refurbished in 2004, the phase arc chutes are only visually inspected, i.e., inspection of the corona, cracks, chips, broke fins, and extensive burning or corrosion in the arc chutes. The phase arc chutes are not

replaced during the refurbishment process unless a defect is identified. Since the 1 B SLC pump motor breaker was scrapped and involved personnel offered little information, an investigation to determine how the crack was initiated yielded no results.

The vendor stated that visual inspections were adequate to detect a crack and there was no need to conduct inspections using any form of magnification. The arc chutes are visually inspected through the preventive maintenance program. The initial visual inspection occurred on April 26, 2005. The last visual inspection was completed in August 2009. It did not reveal any cracks. It is suspected that a hairline crack went undetected and propagated over time during quarterly operation of the 1 B SLC pump motor breaker during 1 B SLC pump testing.

V. Assessment of Safety Consequences

The SLC System is a standby system designed to bring the reactor from full power to a cold, Xenon free, shutdown condition, assuming none of the withdrawn control rods can be inserted. It operates by injecting a Boron-10 solution into the Reactor Coolant System. The SLC System may also be manually aligned as an alternate source of high-pressure makeup water to the reactor. The SLC System is not intended to be a backup for the reactor scram function, i.e., it is not designed to rapidly insert negative reactivity when a safety setpoint is exceeded. The SLC System is used to control Suppression Pool pH in the event of a Loss of Coolant Accident combined with High Radiation in the Drywell or Suppression Chamber.

Based on the presence of the nonconductive foreign material, the 1 B SLC pump would not have been able to perform its design function. The 1 B SLC subsystem is assumed to have been inoperable from the last surveillance on the 1 B SLC pump motor breaker, which was successfully performed on November 20, 2012.

A probabilistic risk assessment (PRA) evaluation was performed to assess the safety significance of the 1 B SLC pump being inoperable from December 1, 2012, at approximately 0145 hours0.00168 days <br />0.0403 hours <br />2.397487e-4 weeks <br />5.51725e-5 months <br /> CST to February 14, 2013, at approximately 0625 hours0.00723 days <br />0.174 hours <br />0.00103 weeks <br />2.378125e-4 months <br /> CST.

The PRA evaluation also determined that both subsystems of SLC were unavailable from February 13, 2013, at approximately 0632 hours0.00731 days <br />0.176 hours <br />0.00104 weeks <br />2.40476e-4 months <br /> CST until February 13, 2013, at approximately 1318 hours0.0153 days <br />0.366 hours <br />0.00218 weeks <br />5.01499e-4 months <br /> CST. The analysis evaluated the cumulative risk when the SLC subsystem(s) were considered unavailable. The PRA evaluation concluded that the incremental Conditional Core Damage Probability (ICCDP) was 4.73E-7 and the Incremental Conditional Large Early Release Probability (ICLERP) was 3.1OE-8, which concludes that this event had low safety significance.

A. Availability of systems or components that could have performed the same function as the components and systems that failed during the event:

The SLC system consists of two 100 percent capacity positive displacement pumps.

With the loss of one pump, the alternate pump would fulfill the design function of the SLC system for the required mission time. There was one period of time when the 1A SLC pump was unavailable from February 13, 2013, at approximately 0632 hours0.00731 days <br />0.176 hours <br />0.00104 weeks <br />2.40476e-4 months <br /> CST until February 13, 2013, at approximately 1318 hours0.0153 days <br />0.366 hours <br />0.00218 weeks <br />5.01499e-4 months <br /> CST.

B. For events that occurred when the reactor was shut down, availability of systems or components needed to shutdown the reactor and maintain safe shutdown conditions, remove residual heat, control the release of radioactive material, or mitigate the consequences of an accident:

The BFN, Unit 1, was not shut down during this event.

C. For failure that rendered a train of a safety system inoperable, an estimate of the elapsed time from discovery of the failure until the train was returned to service:

The 1B SLC pump was determined to be inoperable from December 1, 2012, at approximately 0145 hours0.00168 days <br />0.0403 hours <br />2.397487e-4 weeks <br />5.51725e-5 months <br /> to February 14, 2013, at approximately 0625 hours0.00723 days <br />0.174 hours <br />0.00103 weeks <br />2.378125e-4 months <br />. This period of inoperability started when BFN, Unit 1, was placed into Mode 2 after refueling outage 9 to February 14, 2013, at approximately 0625 hours0.00723 days <br />0.174 hours <br />0.00103 weeks <br />2.378125e-4 months <br /> when Operations personnel declared 1 B SLC pump Operable and exited TS LCO 3.1.7 Condition A.

VI.

Corrective Actions

Corrective Actions are being managed by TVA's corrective action program under Problem Evaluation Reports 681667 and 791685.

Immediate Corrective Actions

The 1 B SLC pump motor breaker was racked out and disassembled for troubleshooting.

During the troubleshooting of the 1 B SLC pump motor breaker, the 'A' phase arc chute was found to be discolored with a piece broken off. The broken pieces were removed, breaker cleaned, the 'A' phase arc chute replaced, and the 1 B SLC pump motor breaker was returned to service.

Corrective Actions to Prevent Recurrence or to Reduce Probability of Similar Events Occurring in the Future

1. Revise procedures to include enhanced arc chute inspection to ensure sustainability.

2. Implement BFN, Units 1, 2, and 3, Engineering Change Packages to replace applicable safety related GE AK breakers.

VII. Additional Information

A. Previous similar events at the same plant:

A search of BFN Licensee Event Reports (LERs) for Units 1, 2, and 3 for the last five years identified LER 50-296/2013-002-00, A Subsystem of the Standby Liquid Control System was Inoperable Longer than Allowed by the Plant's Technical Specifications. This LER identified a similar condition concerning the inoperability of the 3B SLC pump motor breaker that was discovered when the pump failed to start.

The reason for the breaker failure and the corrective actions reported in LER 50-296/2013-002-00 do not directly relate to this event and would not have prevented this event from occurring.

A search was performed on the BFN corrective action program. There were no corrective action program documents that were similar to this event.

B. Additional Information

There is no additional information.

C. Safety System Functional Failure Consideration:

In accordance with Nuclear Energy Institute 99-02, this condition is not considered a safety system functional failure.

D. Scram with Complications Consideration:

This event did not result in an unplanned scram with complications.

VIII. COMMITMENTS

There are no commitments.