05000286/LER-2018-003, Manual Reactor Trip Due to a Steam Leak on a High Pressure Feedwater Heater

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Manual Reactor Trip Due to a Steam Leak on a High Pressure Feedwater Heater
ML18341A122
Person / Time
Site: Indian Point Entergy icon.png
Issue date: 11/19/2018
From: Vitale A
Entergy Nuclear Operations
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-18-083 LER 2018-003-00
Download: ML18341A122 (5)
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LER-2018-003, Manual Reactor Trip Due to a Steam Leak on a High Pressure Feedwater Heater
Event date:
Report date:
2862018003R00 - NRC Website
v • d • e

text

NL-18-083 November 19, 2018 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Mail Stop O-P1-17 Washington, D.C. 20555-0001 Indian Point Energy Center 450 Broadway, GSB P.O. Box249 Buchanan, N.Y. 10511-0249 Tel (914) 254-6700 Anthony J. Vitale Site Vice President

Subject:

Licensee Event Report# 2018-003-00 "Manual Reactor Trip Due To A Steam Leak On A High Pressure Feedwater Heater" Indian Point Unit No. 3 Docket No. 50-286 DPR-64

Dear Sir or Madam:

Pursuant to 10 CFR 50. 73(a)(1 ), Entergy Nuclear Operations Inc, hereby provides Licensee Event Report (LER) 2018-003-00. The attached LER identifies an event where the reactor was manually trip due to a steam leak on a high pressure feedwater heater, which is reportable under 10 CFR 50. 73(a)(2)(iv)(A). This event was recorded in the Entergy Corrective Action Program as Condition Report CR-IP3-2018-02773.

There are no commitments made or revised in this letter. Should you have any questions regarding this matter, please contact Mr. Robert Walpole, Manager, Regulatory Assurance, Indian Point Energy Center at (914) 254-6710.

Sincerely, cc:

Mr. David Lew, Regional Administrator, NRC Region I NRC Resident Inspector's Office Ms. Bridget Frymire, New York State Public Service Commission

NRCFORM366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY 0MB: NO. 3150-0104 EXPIRES: 03/31/2020 (04-2018)

, the NRG may not conduct or sponsor, and a oerson is not reauired to resoond to the information collection.

1. Facility Name
12. Docket Number

. Page INDIAN POINT UNIT 3 05000286 1 OF4

4. Title MANI IAI Rl=ACTC R TRIP nl II= TO A STi=AI\\A I !=AK ON A HIC: H PRl=~C::I IRE FEEDWATER Hl=ATER
5. Event Date
6. LER Number
7. Report Date
8. Other Facilities Involved Sequential Rev Facility Name Docket Number Month Day Year Year Number No.

Month Day Year

~5000 9

18 2018 2018

- 003
- 00 11 19 2018 Facility Name Docket Number 5000
9. Operating Mode ABSTRACT On September 18, 2018, with the reactor at 100 percent power, at approximately 0525 hours0.00608 days <br />0.146 hours <br />8.680556e-4 weeks <br />1.997625e-4 months <br /> Operators manually tripped the reactor and shut the Main Steam Isolation Valves due to a steam leak on the 6 inch elbow located upstream of the 36C Feedwater Heater. The steam leak was due to a failure of the 6 inch elbow. The cause of the failure was flow accelerated corrosion which lead to pipe wall thinning and subsequent pipe failure. Ultrasonic testing of the elbow showed flow accelerated corrosion thinning in the failed elbow and also in the adjacent upstream elbow..

This event was reported under 10 CFR 50.72(b)(2)(iv)(B) for any event or condition that results in actuation of the reactor protection system when the reactor is critical. This event was also reportable under 1 O CFR 50.72(b)(3)(iv)(A) for any event or condition that results in valid actuation of any of the systems listed in paragraph 1 O CFR 50.72(b)(3)(iv)(B). This included actuation of the Auxiliary Feedwater System as expected following manual reactor trip. Following the reactor trip, the plant was stabilized in hot standby with decay heat being removed from the steam generators via the Auxiliary Feedwater System and atmospheric steam dumps.

This event had no effect on the public health and safety.

NRC FORM 366 (04-2018)

On September 18, 2018, with the reactor at 100 percent power, at approximately 0525 hours0.00608 days <br />0.146 hours <br />8.680556e-4 weeks <br />1.997625e-4 months <br /> Operators manually tripped the reactor and shut the Main Steam Isolation Valves due to a steam leak on the 6 inch elbow located upstream of the 36C Feedwater Heater. The steam leak was due to a failure of the 6 inch elbow. The cause of the failure was flow accelerated corrosion which lead to pipe wall thinning and subsequent pipe failure. Ultrasonic testing of the elbow showed flow accelerated corrosion thinning in the failed elbow and also in the adjacent upstream elbow. The piping containing the failure is in the drain path from the Moisture Separator Reheater Drain Tank to the 36A, B, and C Feedwater Heaters. This component is identified as RHD-02, 15A-06E. The failure occurred on the extrados of the elbow and was approximately 1.75 inches in length.

The flow accelerated corrosion program as described in Entergy procedure, EN-DC-315, "Flow Accelerated Corrosion Program" is designed to predict, detect, monitor and minimize degradation in single and two-phase flow piping (safety and non-safety related systems) to prevent failures while enhancing plant safety and reliability. Flow accelerated corrosion is monitored through the CHECKWORKS ' Steam/Feedwater Application database. This database was developed by the Electric Power Research Institute (EPRI) as a formal software plan and is used by the nuclear and fossil industries.

The CHECKWORKS TM Steam/Feedwater Application model is a predictive methodology tool used to predict the rate of wall thinning due to flow accelerated corrosion within piping and fittings under exact operating conditions. The predicted wear.

rate and remaining service life are based on factors such as component geometry, material, and operating conditions. The Indian Point flow accelerated corrosion program was developed consistent with the industry recommended program as outlined in EPRI procedure NSAC-202L.

The flow accelerated corrosion program was ineffective in detecting and correcting the flow accelerated corrosion on the elbow of 36C Feedwater Heater Branch prior to the failure because the flow accelerated corrosion engineers did not use system replacement history to identify differing wear rates resulting from differing operating conditions. In addition, there were weaknesses in the setup of the CHECKWORKS TM model for the affected system. Specifically, all six Re-Heater Drain branches were modeled in a single run and the internal fluid frictional losses in some branches of the system were being subjected to higher flow velocities than other branches. As a result, higher wear rates in the 36C Feedwater Heater piping were being masked by the lower wear rates in the 36A and 36B Feedwater Heater piping. These conditions will be corrected by revising the CHECWORKS models for multi branch systems and by improving the fleet procedure with additional actions.

This event was reported under 10 CFR 50.72(b)(2)(iv)(B) for any event or condition that results in actuation of the reactor protection system when the reactor is critical. This event was also reportable under 1 O CFR 50.72(b)(3)(iv)(A) for any event or condition that results in valid actuation of any of the systems listed in paragraph 1 O CFR 50.72(b)(3)(iv)(B).

This event was recorded in the Indian Point Energy.Center Corrective Action Program as CR-IPS-2018-02773.

NRC FOAM 3668 (02-201 B)

Page 2 of 4 (04-2018)

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LICENSEE EVENT REPORT (LER)

CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this fonTI http://www.nrc.gov/reading-nTI/doc-collections/nureqs/staff/sr1022/r3/l

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

3. LEA NUMBER Indian Point Unit 3 05000286 YEAR SEQUENTIAL NUMBER REV NO.

2018

- 003
- 00

CAUSE OF EVENT

Root Cause The qualified flow accelerated corrosion program engineers did not use the system replacement history to identify the fact that the Re-Heater Drain piping to the 36C feedwater heater was more susceptible to the flow accelerated corrosion then the Re-Heater Drain piping to the 36A and 368 feedwater heaters. Plant operating experience showed failures had occurred in 2007 on the 36C feedwater heater branch. As a result of this, additional inspections should have been performed during subsequent refueling outages on the 36C train, compared to the 36A and 368 trains to monitor for subsequent wall thinning.

This action could have identified the thinning prior to failure.

Contributing Causes

The Entergy flow accelerated corrosion program was ineffective in detecting and correcting flow accelerated corrosion in the elbow prior to failure because of weaknesses in the setup of the CHECKWORKS ' model.

Specifically, all six Re-Heater Drain branches were modeled in a single run and the internal fluid frictional losses in some branches of the system were resulting in higher flow velocities than other branches. As a result of this, higher wear rates in the 36C Feedwater Heater piping were being masked by the lower wear rates in the 36A and 368 Feedwater Heaters piping.

Inadequate procedural guidance in Entergy procedure EN-DC-315, "Flow Accelerated Corrosion Program" for scope *expansion. At the time of the 2007 failure, EN-DC-315 Revision O} Paragraph 5.12[2](a) required scope expansion to include, "components within two diameters downstream" to be inspected but does not include the next downstream fitting which would have identified thinning on the failed elbow.

CORRECTIVE ACTIONS

The following corrective actions have been or will be performed under the Entergy Corrective Action program to address the causes of this event.

Revise the CHECKWORKS model to split the six Re-Heater Drain branches into three separate runs, one run per heater. Apply the best estimate thermo-hydraulic conditions to each of the three runs.

Revise fleet procedure EN-DC-315 to provide more guidance for scope expansion to ensure the extent of the worn area is known.

Revise fleet procedure EN-DC-315 to give the flow accelerated corrosion engineer a visual of the system replacement history in order.. to see overall system impact and determine appropriate inspectior, scope. Page 3 of 4 (04-2018)

U.S. NUCLEAFt REGULATORY COMMISSION APPROVED BY 0MB: NO. 3150-0104 EXPIRES: 3/31/2020 p>*

l LICENSEE EVENT REPORT (LER)

CONTINUATION SHEET (See NUREG-1022, R.3 for instruction and guidance for completing this fonn http://www.nrc.gov/readinq-nn/doc-colleclions/nuregs/staff/sr1022/r30

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

  • 3. LEA NUMBER YEAR Indian Point Unit 3 05000286 2018

EVENT ANALYSIS

SEQUENTIAL NUMBER

- 003 REV NO.
- 00 Due to a steam leak on the reheater drain line to the 36C Feedwater Heater, operators initiated a manual trip of the reactor, verified the reactor trip, and closed all Main Steam Isolation Valves. The plant was stabilized in Mode 3 with the steam leak isolated.

This event was reported under 1 O CFR 50.72(b}(2}(iv)(B) for any event or condition that results in actuation of the reactor protection system when the reactor is critical. This event was also reportable under 10 CFR 50.72(b}(3)(iv)(A) for any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B). This included actuation of the Auxiliary Feedwater System as expected following manual reactor trip. Following the reactor trip, the plant was stabilized in hot standby with decay heat being removed from the steam generators via the Auxiliary Feedwater System and atmospheric steam dumps.

PAST SIMILAR EVENT A review was performed of the past five year for Indian Point Unit 2 and Unit 3 License~ Event Reports for flow accelerated corrosion flaws. There were no past similar events. Plant operating experience showed that a pin hole leak occurred in 2007 on the 36C Feedwater Heater Branch but no failures similar to the one described here. However, this leak did not result in a reactor trip.

SAFETY SIGNIFICANCE

This event has no effect on the health and safety of the public. There were no actual safety consequences for the event because it was an uncomplicated manual reactor trip. The required primary safety systems performed as designed.

For the event, all control rods inserted as required upon initiation of the reactor trip. The reactor coolant system remained below the setpoint for pressurizer power operated relief valve and code safety valve operation, and above the setpoint for automatic Safety Injection actuation. Following the reactor trip, the plant was stabilized in hot standby with decay heat being remoyed from the steam generators via the Auxiliary Feedwater System and atmospheric steam dumps. Page 4 of 4

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