05000366/LER-2008-003, For Edwin I. Hatch, Unit 2 Regarding Crack in Reactor Pressure Boundary Piping Due to High Cycle Fatigue Results in Leakage

For Edwin I. Hatch, Unit 2 Regarding Crack in Reactor Pressure Boundary Piping Due to High Cycle Fatigue Results in Leakage

ML081900101
Person / Time
Site:	Hatch
Issue date:	07/07/2008
From:	Madison D Southern Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-08-1042 LER 08-003-00
Download: ML081900101 (6)

LER-2008-003, For Edwin I. Hatch, Unit 2 Regarding Crack in Reactor Pressure Boundary Piping Due to High Cycle Fatigue Results in Leakage

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
3662008003R00 - NRC Website

text

D. R. Madison (Dennis)

Southern Nuclear Vice President - Hatch Operating Company, Inc.

Plant Edwin I. Hatch 11028 Hatch Parkway, North Baxley, Georgia 31513 Tel 912.537.5859 Fax 912.366.2077 SOUIHERN'\\

COMPANY Energy to Serve }'Our Wor/d'U July 7, 2008 Docket Nos.: 50-366 NL-08-1042 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Edwin I. Hatch Nuclear Plant - Unit 2 Licensee Event Report Crack in Reactor Pressure Boundary Piping Due to High Cycle Fatigue Results in Leakage Ladies and Gentlemen:

In accordance with the requirements of 10 CFR 50.73(a)(2)(i)(B), Southern Nuclear Operating Company is submitting the enclosed Licensee Event Report (LER) concerning an unisolable leak in the reactor pressure boundary.

This letter contains no NRC commitments. If you have any questions, please advise.

Sincerely,

$~m~

D. R. Madison Vice President - Hatch DRM/mjk

Enclosure:

LER 2-2008-003

U. S. Nuclear Regulatory Commission Log:

Page 2 cc:

Southern Nuclear Operating Company Mr. J. T. Gasser, Executive Vice President Mr. D. R. Madison, Vice President - Hatch Mr. D. H. Jones, Vice President - Engineering RTYPE: CHA02.004 U. S. Nuclear Regulatory Commission Mr. L. A. Reyes, Regional Administrator Mr. R. E. Martin, !\\JRR Project Manager - Hatch Mr. J. A. Hickey, Senior Resident Inspector - Hatch

iNRc FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 3150-0104 EXPIRES: 08/3112010 9-2(07)

Estimated burden per response to comply with this mandatory collection request: 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br />. Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Records and FOlNPrivacy Service Branch (T-5 F52), U.S. Nuclear Regulatory Commission, LICENSEE EVENT REPORT (LER)

Washington, DC 20555-0001, or by internet e-mail to infocollects@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150 0104), Office of Management and Budget, Washington, DC 20503. Ifameans used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and aperson is not required to respond to, the information collection.

13. PAGE Edwin L Hatch Nuclear Plant Unit 2 05000366 1 OF 4

~. TITLE Crack in Reactor Pressure Boundary Piping Due to High Cycle Fatigue Results in Leakage

5. EVENT DATE

6. LER NUMBER

7. REPORT DATE

8. OTHER FACILITIES INVOLVED FACILITY NAME DOCKET NUMBER MONTH DAY YEAR YEAR SEQUENTIAL REV MONTH DAY YEAR 05000 NUMBER NO FACILITY NAME DOCKET NUMBER 5

19 2008 2008 003 -

0 07 07 2008 05000

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

D 20.2201(b)

D 20.2203(a)(3)(i)

D 50.73(a)(2)(i)(C)

D 50.73(a)(2)(vii) 1 D 20.2201(d)

D 20.2203(a)(3)(ii)

D 50.73(a)(2)(ii)(A)

D 50.73(a)(2)(viii)(A) o 20.2203(a)(I)

D 20.2203(a)(4)

D 50.73(a)(2)(ii)(B)

D 50.73(a)(2)(viii)(B) o 20.2203(a)(2)(i)

D 50.36(c)( l)(i)(A)

D 50.73(a)(2)(iii)

D 50.73(a)(2)(ix)(A)

10. POWER LEVEL D 20.2203(a)(2)(ii)

D 50.36(c)(l )(ii)(A) o 50.73(a)(2)(iv)(A)

D 50.73(a)(2)(x)

D 20.2203(a)(2)(iii) o 50.36(c)(2) o 50.73(a)(2)(v)(A)

D 73.71(a)(4)

D 20.2203(a)(2)(iv) o 50.46(a)(3)(ii) o 50.73(a)(2)(v)(B)

D 73.71(a)(5) 99.9 D 20.2203(a)(2)(v) o 50.73(a)(2)(i)(A)

D 50.73(a)(2)(v)(C)

D OTHER D 20.2203(a)(2)(vi) 181 50.73(a)(2)(i)(B)

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

Specify in Abstract below or in NRC Form 366A

12. LICENSEE CONTACT FOR THIS LER fACILITY NAME ITELEPHONE NUMBER (Include Area Code)

~dwin L Hatch / Kathy Underwood, Performance Analysis Supervisor 912-537-5931 CAUSE SYSTEM COMPONENT MANU REPORTABLE

CAUSE

SYSTEM COMPONENT MANU REPORTABLE FACTURER TO EPIX FACTURER TO EPIX B

BN N/A N/A Yes

14. SUPPLEMENTAL REPORT EXPECTED

15. EXPECTED SUBMISSION MONTH DAY YEAR DyES (lfyes. complete 15. EXPECTED SUBMISSION DATE) 181 NO DATE ABSTRACT (Limit to 1400 spaces, i.e., approximately 15 single-spaced typewritten lines)

On March 19, 2008, it was determined that a condition discovered on March 8, 2005, consisting of a leak on a non-isolable portion of the reactor coolant boundary identified during the reactor vessel leakage test was reportable under 10 CFR 50.73. The leak was located in a section of one inch stainless steel instrumentation piping associated with the four inch steam supply to the reactor core isolation cooling (RCIC) system. The Technical Specification (TS) definition of pressure boundary leakage is "leakage through a non-isolable fault in the reactor coolant system." Due to its location, the leak met this definition. Pressure boundary leakage in modes 1, 2, or 3 is not allowed by the plant's TS. Although the leak was discovered when the unit was in Mode 4, review of the failure analysis report provided indication that the leak most likely started at some point during the run cycle (i.e. during Modes 1,2 and/or 3) leading up to the time of discovery.

The piping was sent to an independent testing facility which determined the cause of the leak was failure of the pipe due to High Cycle Fatigue.

Corrective actions for this event included replacing the failed weld, evaluating similar small bore class 1 piping for additional action, and revising The Corrective Action Program to elevate t.he severit~.level even if the unit is in an operating mode at the time of condition discovery that does not reqUire operabIlity, and regardless of how the condition was discovered_

PRINTED ON RECYCLED PAPER NRC FORM 366 (9-2007)

(Ifmore space is required, use additional copies ofNRC Form 366A)

PLANT AND SYSTEM IDENTIFICAnON General Electric - Boiling Water Reactor Energy Industry Identification System codes appear in the text as (EllS Code XX).

DESCRIPTION OF EVENT

On March 8, 2005, a leak on a non-isolable portion of the reactor coolant boundary was discovered during the reactor vessel leakage test (performed in Mode 4). The leak was located in a section of one inch stainless steel instrumentation piping associated with the four inch steam supply to the Reactor Core Isolation Cooling (RCIC) system (EllS Code BN). The Technical Specification (TS) definition of pressure boundary leakage is "leakage through a non-isolable fault in the reactor coolant system". Due to its location, the leak met this definition. The leak was discovered when the unit was in Mode 4. A condition report was created, assigned a low severity level, and corrective action was taken. The damaged pipe was replaced and similar Class 1 small bore piping was inspected at that time for evidence of leakage or damage with no problems identified. The pipe was sent to an independent testing laboratory for failure analysis which determined the cause of the failure to be high cycle fatigue.

Documentation of a reportability evaluation based on the findings from the failure analysis report could not be found. Subsequent review of the failure analysis report provided indication that the leak most likely started at some point during the run cycle (i.e. during Modes I, 2 and/or 3) leading up to the time of discovery and as a result the determination was made on March 19,2008 that this condition should be reported under 10 CFR 50.73.

CAUSE OF EVENT

The piping was sent to an independent testing facility which determined the cause of the leak was failure of the pipe due to High Cycle fatigue.

REPORTABILITY ANALYSIS This report is submitted, per 10 CFR 50.73(a)(2)(i)(B), as a condition prohibited by the plant's TS.

The Unit 2 TS allows no pressure boundary leakage in modes 1, 2, or 3. Reportability of the condition turns on whether there is evidence that the condition existed prior to discovery, i.e. when the unit was in Mode 1,2, and/or 3.

Guidance provided in NUREG 1022 Rev. 2 states in section 3.2.2:

"... For the purpose of evaluating the reportability of a discrepancy found during surveillance testing that is required by the technical specifications:

(I) For testing that is conducted within the required time (i.e., the surveillance interval plus any allowed extension), it should be assumed that the discrepancy occurred at the time of its. discove~

unless there is firm evidence, based on a review of relevant information such as the eqUIpment history PRINTED ON RECYCLED PAPER (9,2007)

LICENSEE EVENT REPORT (LER)

CONTINUATION SHEET U.S. NUCLEAR REGULATORY COMMISSION

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6. LER NUMBER

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and the cause of failure, to indicate that the discrepancy existed previously."

The condition report that identified this leak was classified at a low severity level and there is no documentation that a reportability evaluation took place at the time of discovery or once the failure analysis report was received. At the time of discovery it was recognized that the leak must be repaired prior to entering modes I, 2 or 3 but consideration of impact during the prior operating cycle was not made. Recent review of the failure analysis report provided indication that the leak most likely started at some point during the run cycle (i.e. during Modes 1,2 and/or 3) leading up to the time of discovery.

As a result the determination was made on March 19,2008 that this condition should be reported under 10 CPR 50.73.

SAFETY ASSESSMENT

The reactor coolant system (RCS) includes systems and components that contain or transport the coolant to or from the reactor core. The pressure-retaining components of the RCS and the portions of connecting systems out to and including the isolation valves define the reactor coolant pressure boundary. During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant leakage, through either normal operational wear or mechanical deterioration. Limits on RCS operational leakage are required to ensure appropriate action is taken before the integrity of the reactor coolant pressure boundary is compromised.

The TS delineate the limits on the specific types of leakage. The TS unidentified leakage flow limit of five gallons per minute (gpm) is a small fraction of the calculated flow from a critical crack in the primary system piping. A critical crack is one large enough to propagate rapidly, ultimately leading to failure of the affected component. Crack behavior from experimental programs shows that leakage rates of hundreds of gallons per minute will precede crack instability (see Unit 2 Final Safety Analysis Report, section 5.2.7.5, "Nuclear System Leakage Detection and Leakage Rate Limits," and Unit 2 TS Bases B 3.4.4, "RCS Operational Leakage").

At the time the unit was shut down, the unidentified leakage rate was approximately one percent of the TS limit of five gpm. The size of the crack was much smaller than the "critical crack" (on which the TS limit is based) as evidenced by the low leakage rate. Therefore, at the time it was discovered and corrective action taken; the crack was not unstable and would not have resulted in catastrophic failure of the line. Additionally, in the unlikely event of the worst case instantaneous and complete severing of the one-inch line, due to the presence of a crack, the resulting loss of reactor coolant would not be of a significant amount.

A rupture of the one-inch RCIC line does not result in a significant decrease in water inventory within the vessel. In addition, the break is bounded by both the Loss of Coolant Accident analysis and the Feedwater Line break analysis. The proposed leak in the RCIC line is less than 10 percent of the rated capacity of the High Pressure Coolant Injection (EllS Code BJ) system, which is sized to provide adequate coolant make-up for pipe breaks up to four inches. Additionally, a leak of several hundred gpm would have adequately been accommodated by the feedwater system (EllS Code SJ), which has a flow rate capacity margin at rated conditions of at least 10 percent (over 2000 gpm). Therefore, either of these diverse and independent injection systems could have provided sufficient make-up flow to maintain water level well above the top of the active fuel.

PRINTED ON RECYCLED PAPER (9-2007)

LICENSEE EVENT REPORT (LER)

CONTINUATION SHEET U.S. NUCLEAR REGULATORY COMMISSION

1. FACILITY NAME

2. DOCKET

6. LER NUMBER

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Based upon the preceding analysis, it is concluded that this event had no adverse impact on nuclear safety.

CORRECTIVE ACTIONS

The failed weld was replaced.

Systems within the ASME Class 1 boundary were reviewed for lines which are small-bore, unisolable, and stainless steel. Sixteen Main Steam Flow connections on each unit, and the four flow measurement lines each for steam supply to RCIC and HPCI, were selected to be evaluated and corrective actions taken as determined appropriate. These actions will be tracked in the Corrective Action Program.

The Corrective Action Program has been revised to elevate the severity level even if the unit is in an operating mode at the time of condition discovery that does not require operability, and regardless of how the condition was discovered.

ADDITIONAL INFORMATION

Other Systems Affected: No systems were affected by this event other than those which have already been discussed in this report.

Failed Components Information

Master Parts List Number: 2E51 Manufacturer: NtA Model Number: NtA Type: NtA Manufacturer Code: NtA Ens System Code: BN Reportable to EPIX: Yes Root Cause Code: B Ens Component Code: NtA Commitment Information: This report does not create any permanent licensing commitments.

Previous Similar Events

There were no similar events reported in the two years prior to the original event.

PRINTED ON RECYCLED PAPER