05000254/LER-2009-004, Regarding Pinhole Leak in Core Spray Piping Results in Loss of Containment Integrity and Plant Shutdown for Repairs
| ML093170206 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 11/06/2009 |
| From: | Tulon T Exelon Generation Co, Exelon Nuclear |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| SVP-09-066 LER 09-004-00 | |
| Download: ML093170206 (7) | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown 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)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications |
| 2542009004R00 - NRC Website | |
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Exelon Generation Company, LLC Quad Cities Nuclear Power Station 22710 206th Avenue North Cordova, IL 61242-9740 www.exeloncorp.com Nuclear November 6, 2009 SVP-09-066 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Quad Cities Nuclear Power Station, Unit 1 Renewed Facility Operating License No. DPR-29 NRC Docket No. 50-254
Subject:
Licensee Event Report 254/09-004, "Pinhole Leak in Core Spray Piping Results in Loss of Containment Integrity and Plant Shutdown for Repairs" Enclosed is Licensee Event Report (LER) 254/09-004, "Pinhole Leak in Core Spray Piping Results in Loss of Containment Integrity and Plant Shutdown for Repairs," for Quad Cities Nuclear Power Station, Unit 1.
This report is submitted in accordance with the requirements of the Code of Federal Regulations, Title 10, Part 50.73(a)(2)(i)(A), which requires the reporting of the completion of any nuclear plant shutdown required by the plant's Technical Specifications.
There are no regulatory commitments contained in this letter.
Should you have any questions concerning this report, please contact Mr. W. J. Beck at (309) 227-2800.
Respectfully,
/
Timothy An Site Vice President Quad Cities Nuclear Power Station cc:
Regional Administrator - NRC Region Ill NRC Senior Resident Inspector - Quad Cities Nuclear Power Station AdA4
NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 3150-0104 EXPIRES: 08/31/2010 (9-2007)
, the NRC may digits/characters for each block) not conduct or sponsor, and a person is not required to respond to, the information collection.
- 13. PAGE Quad Cities Nuclear Power Station Unit 1 05000254 1 OF 6
- 4. TITLE Pinhole Leak in Core Spray Piping Results in Loss of Containment Integrity and Plant Shutdown for Repairs
- 5. EVENT DATE
- 6. LER NUMBER
- 7. REPORT DATE
- 8. OTHER FACILITIES INVOLVED MONTH DAY YEAR ISEQUENTIAL I REV M
I I
FACILITY NAME DOCKET NUMBER MOTURYEAR EU ER E
MONTH DAY YEAR N/A N/A FACILITY NAME DOCKET NUMBER 09 08 09 2009 -
004 -
00 11 06 2009 N/A N/A
- 9. OPERATING MODE
- 11. THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR §: (Check all that apply)
El 20.2201(b)
El 20.2203(a)(3)(i)
El 50.73(a)(2)(i)(C)
El 50.73(a)(2)(vii) 1 El 20.2201(d)
El 20.2203(a)(3)(ii)
[l 50.73(a)(2)(ii)(A)
[I 50.73(a)(2)(viii)(A)
El 20.2203(a)(1)
El 20.2203(a)(4)
El 50.73(a)(2)(ii)(B)
El 50.73(a)(2)(viii)(B)
_]
20.2203(a)(2)(i)
[I 50.36(c)(1)(i)(A)
El 50.73(a)(2)(iii)
El 50.73(a)(2)(ix)(A)
- 10. POWER LEVEL El 20.2203(a)(2)(ii)
[I 50.36(c)(1)(ii)(A)
Cl 50.73(a)(2)(iv)(A)
El 50.73(a)(2)(x)
El 20.2203(a)(2)(iii)
[I 50.36(c)(2)
Cl 50.73(a)(2)(v)(A)
[1 73.71(a)(4) 100%
El 20.2203(a)(2)(iv)
El 50.46(a)(3)(ii)
[I 50.73(a)(2)(v)(B)
El 73.71(a)(5)
El 20.2203(a)(2)(v)
E 50.73(a)(2)(i)(A)
El 50.73(a)(2)(v)(C)
[I OTHER El 20.2203(a)(2)(vi)
El50.73(a)(2)(i)(B)
El 50.73(a)(2)(v)(D)
Specify in Abstract below or in Exelon Generation Company, LLC, PowerLabs. The inspection confirmed a patch of severe internal thinning in the pipe section that was closest to the upstream PCIV. The thinned region exhibited a jagged, irregular contour that was consistent with cavitation erosion.
Following the identification of the pinhole leak on the 1B CS piping, an immediate assessment of other similar piping was performed. The piping that was considered included the min flow lines on residual heat removal (RHR) [BO],
high pressure coolant injection (HPCI) [BJ], and reactor core isolation cooling (RCIC) [BN] as well as the test return lines that the min flow lines are aligned to discharge to. UT exams were then targeted for locations immediately upstream and downstream of valves, restricting orifices [OR], and piping tees [PSF].
As inspection results were obtained, the extent of condition locations were re-assessed.
The UT results showed most locations had wall thicknesses that were within the manufacturing tolerances established for the size and schedule of pipe installed. The only locations that exhibited obvious wall loss were the recently identified locations upstream and downstream of the 1-1402-38B valve, and areas around the 1-1406-8 inch (1A and 1B CS common return header) where previous damage was recorded prior to removing a restricting orifice from the header in 1992 (but still of acceptable minimum wall thickness).
Recent inspections in March 2009 (1B CS piping loop Class 2 leak test), and Q1R20, May 2009, (1A and 1B CS piping pressurized during the integrated leak test), provided similar opportunities to identify leaks, but did not identify any leakage from this leak location. The 1B CS piping section had been previously formally successfully leak tested (per VT-2) for the presence of through wall leaks in September 2002.
The 1B CS piping downstream of 1-1402-38B was replaced on September 10, 2009. A section of the 1B CS piping upstream of 1-1402-38B was replaced on September 10, 2009. The 1-1402-38B valve was also inspected during the piping replacements, and although cavitation damage was observed, it was evaluated as acceptable.
Unit 1 was restarted on September 12, 2009.
C.
CAUSE OF EVENT
A Root Cause evaluation was completed on October 21, 2009. The root cause of the 1 B min flow piping pinhole leak at Quad Cities Station was due to a piping design that produced high water flow velocity (approximately 26 fps) in the 1B CS Min Flow Piping.
The high flow velocity exceeded typical piping design recommendations (to maintain less than 20 fps), and when combined with the globe valve (MO 1-1402-38B), resulted in a high pressure drop and cavitation downstream of the valve. The cavitation led to the erosion of the downstream pipe wall during operation of the min flow line. It is likely in this case, considering the low usage expected from the min flow line, that it was not anticipated by the designers that the high flow velocities would eventually cause damage.
Contributing to the event was the lack of any formal controls (administrative barriers) to monitor for velocity induced cavitation erosion susceptibility and to monitor for potential damage in critical piping systems. Cavitation erosion is a known degradation mechanism associated with piping systems but is not specifically monitored at Quad Cities unless it is within the scope of the Risk Informed Inservice Inspection (RI-ISI) program or the Flow Accelerated Corrosion (FAC) program. The 1B CS min flow line was exempt from both the RI-ISI and FAC programs due to either size or service conditions and was appropriately exempted from inspections under the Inservice Inspection (ISI) program, and from Local Leak Rate Testing (LLRT) under the 10CFR50, Appendix J program. This section of piping is required to be tested/inspected during the periodic Integrated Leak Rate Test (ILRT) and associated walkdowns. In reviewing the governing codes and program requirements, the exemptions that were applied were found to be valid and did not contribute to this event.
D.
SAFETY ANALYSIS
System Operation Two independent core spray divisions are provided for use under loss of coolant accident (LOCA) conditions associated with large pipe breaks and reactor vessel depressurization. Each of the two core spray divisions consists of a 4500 gpm capacity pump [P], valves, piping and an independent circular sparger ring inside the inner shroud just over the core. Each core spray system is designed to operate in conjunction with low pressure coolant injection (LPCI) [BO] and either the automatic depressurization system (ADS) or HPCI subsystems to provide adequate core cooling over the entire spectrum of liquid or steam pipe break sizes. [UFSAR 6.3.2.1]
The injection valves in both injection divisions will remain closed until the reactor pressure decays to approximately design discharge pressure of the pumps, at which time the valves will open to admit flow into the reactor vessel. The pumps are operated on the minimum flow bypasses which discharge back to the suppression pool [NH] during the period they are running with the injection valves closed. [UFSAR 6.3.2.1.3]
The MO 1-1402-38B (1B CS minimum flow valve) valve has safety functions to open and to close.
This valve provides the CS min flow function (open function) for the "B" loop of CS, and is also a Primary Containment Isolation Valve (PCIV) (closed function).
The safety function of MO 1-1402-38B to open is to provide a minimum flow path for the core spray pump.
The safety function of MO 1-1402-38B to close is to isolate primary containment and to prevent diversion of core spray flow to the suppression pool during an accident. The plant is normally operated with the MO 1-1402-38B valve in the closed position.
System Impact Based on a review of recent RHR in-service test results, the pinhole leak would not have had an adverse impact on suppression pool cooling. The suppression pool inventory loss (less than 1/2 gpm) is well within station makeup capabilities and would have had minimal impact on Emergency Core Cooling System (ECCS) performance under accident conditions. Procedures allow torus makeup from a variety of water sources including the floor drain surge tank, main condenser, and contaminated condensate storage tank (CCST). Furthermore, the pinhole leak did not represent a significant flooding concern.
Other redundant safety systems, such as 1A CS and LPCI, were available during the time the 1B Loop of CS was inoperable due the pinhole leak event, and the MO 1-1402-38B valve could have been operated to the open position if required.
The time the 1B Loop of CS was inoperable due the pinhole leak, although potentially impacting the ability to achieve CS minimum flow, did not create any actual plant or safety consequences, since Unit 1 was not in an accident condition requiring CS injection during this event.
A finite element analysis of the as-found condition determined that substantial structural integrity had existed in the CS min flow piping. This analysis supports the conclusion that the pinhole leak would not have caused the pipe to rupture under accident conditions. Since cavitation erosion damage is time dependent, it is estimated that the wall loss that occurred was the result of erosion that occurred over the intermittent operation of the CS min flow line.
Assuming the worst case operation of 1B CS where the CS pump may be operating on min flow while waiting for the reactor to depressurize, it is expected that the resultant min flow run time would conservatively be a few hours. In this
worst case condition, 1B CS operation on min flow with cavitation erosion occurring would not impact the structural integrity of the 1 B CS piping.
Radiological Impact The pinhole leak would have contributed to post-accident Engineered Safety Feature (ESF) leakage, however, given the leakage was small (leakage was estimated to be less than 1/2 gpm), accident dose would not have exceeded regulatory limits. Considering available margins (with the control room operator dose being limiting), a leak of up to 60 gpm would have met the regulatory requirement for post-LOCA exposure. Therefore, the predicted control room operator dose following a LOCA would not have exceeded any regulatory requirements (Alternate Source Term).
Risk Insights Although the 1 B Loop of CS was declared inoperable due the pinhole leak, the 1 B Loop of CS was not unavailable for CS injection, hence there was no impact on CDF since the pinhole leak did not affect CS availability. In addition, the guidance provided in NRC IMC 0609, Appendix H (Containment Integrity Significance Determination Process) indicates that since this event did not affect CS availability, there is no impact on CDF, and hence there is no Large Early Release Frequency (LERF) contribution since "small lines (less than 2 inches diameter) and lines connecting to closed systems would not generally contribute to LERF." The CS min flow line is a 1-1/2 inch diameter line, and is considered a closed system. Therefore, there is no impact on the Station PRA.
In conclusion, there was no impact on plant risk, and the overall safety significance of this event was minimal.
E.
CORRECTIVE ACTIONS
Immediate:
Replaced 1B CS piping downstream of 1-1402-38B.
Other immediate actions included performing additional UTs on the 1B CS piping upstream of 1-1402-38B as well as other similar ECCS min flow lines on Unit 1 and a similar CS min flow line on Unit 2. The additional examinations identified only one other location where the wall thickness was below manufacturing tolerances.
As a result, a section of the 1B CS piping upstream of 1-1402-38B was also replaced.
The 1-1402-38B valve was also inspected during the piping replacements and although cavitation damage was observed, it was evaluated as acceptable.
Follow-up:
Corrective actions to prevent reoccurrence will focus on periodic monitoring activities rather than redesigning the 1B CS min flow line. A PM will be created to evaluate periodic UT exams performed on the 1-1402-38B piping sections that were replaced.
To address other susceptible ECCS piping systems, a velocity induced cavitation erosion monitoring program will be developed and implemented at the site.
Guidance to address velocity induced cavitation will be developed and will include methods for identifying susceptible piping segments, the timing for performing volumetric inspections on susceptible piping segments, and the manner in which the required actions will be sustainable.
F.
PREVIOUS OCCURRENCES
The station events database, EPIX, NPRDS, and LERs were reviewed for similar events. This event was caused by high fluid flow velocity which led to cavitation erosion, wall thinning, and ultimately a through wall piping leak in a standby system.
Station Event Database - Quad Cities CR Q2000-00599, RHRSW Vault Room Cooler Leak, and follow-up CR 93444, RHRSW Vault Room Cooler Leak Quad Cities (2/3/00) - A cooling water supply line for the 2A RHRSW pump cubicle cooler developed a pinhole leak due to cavitation erosion.
The erosion occurred downstream of a restricting orifice and where flow velocity was over 50 fps. The initial Condition Report (CR) did not result in an investigation so a follow-up Apparent Cause Evaluation (ACE) was performed under CR 93444. The ACE resulted in actions to perform additional UTs on similar cooling water lines to other cubicle coolers and modifications to install an additional restricting orifice in the susceptible lines to reduce flow rates.
This event represents a missed opportunity to have assessed other piping systems where high velocity flows may drive cavitation, however at that time station guidance provided limited extent of condition reviews, whereas current requirements concerning extent of condition as well as extent of cause would have expanded the reviews to include other piping systems. This station event is relevant to this LER because it supports the fact that high fluid flow velocity, low use piping systems are susceptible to cavitation erosion.
EPIX/ NPRDS - No similar events identified for Quad Cities LER 254-012 05/29/1998, Quad Cities Station, The Unit One Reactor Bottom Head Drain Line Developed a Leak Due to Outside Diameter Initiated Stress Cracking When Surface Contaminants Were Inadvertently Introduced as a Result of an Isolated Inadequate Work Practice During Original Installation or Welding Near Affected Crack Site. The failure mechanism for this event was outside diameter initiated stress corrosion cracking and therefore, this event is not related to the core spray piping pinhole leak event of this LER.
Other than the Station Event Database issue above, no other previous events have occurred at Quad Cities where high fluid flow velocity led to cavitation erosion in standby or low usage systems.
G.
COMPONENT FAILURE DATA
This event has been reported to EPIX as Failure Report No. 979.
The component that failed is 1-1/2 inch, schedule 80 piping manufactured from ASME SA-106 GR. B, Carbon Steel.
The pipe has an internal diameter of 1-1/2 inches and a minimum wall thickness of 0.175 inches.PRINTED ON RECYCLED PAPERPRINTED ON RECYCLED PAPER