Information Notice 2011-04, in: Contaminants and Stagnant Conditions Affecting Stress Corrosion Cracking in Stainless Steel Piping in Pressurized Water Reactors
ML103410363 | |
Person / Time | |
---|---|
Site: | Callaway ![]() |
Issue date: | 02/23/2011 |
From: | Blount T, John Tappert Division of Construction Inspection and Operational Programs, Division of Policy and Rulemaking |
To: | |
Beaulieu, D P, NRR/DPR, 415-3243 | |
References | |
IN-11-04 | |
Download: ML103410363 (6) | |
UNITED STATES
NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
OFFICE OF NEW REACTORS
WASHINGTON, DC 20555-0001 February 23, 2011 NRC INFORMATION NOTICE 2011-04: CONTAMINANTS AND STAGNANT CONDITIONS
AFFECTING STRESS CORROSION CRACKING
IN STAINLESS STEEL PIPING IN PRESSURIZED
WATER REACTORS
ADDRESSEES
All holders of an operating license or construction permit for a nuclear power pressurized water
reactor (PWR) issued under Title 10 of the Code of Federal Regulations (10 CFR) Part 50,
Domestic Licensing of Production and Utilization Facilities, except those who have
permanently ceased operations and have certified that fuel has been permanently removed
from the reactor vessel.
All holders of or applicants for PWR standard design certification, standard design approval, manufacturing license, or combined license issued under 10 CFR Part 52, Licenses, Certifications, and Approvals for Nuclear Power Plants.
PURPOSE
The U.S. Nuclear Regulatory Commission (NRC) is issuing this information notice (IN) to inform
addressees of the effects of contaminants and stagnant conditions on the potential for stress
corrosion cracking (SCC) in stainless steel piping in PWRs. The NRC expects recipients to
review the information for applicability to their facilities and consider taking action, as
appropriate, to avoid similar problems. The suggestions that appear in this IN are not NRC
requirements; therefore, no specific action or written response is required.
DESCRIPTION OF CIRCUMSTANCES
Callaway Plant
In September 2008, Callaway Plant (Callaway) personnel detected a small leak from a
through-wall flaw in the 2-inch diameter, Schedule 160, American Society of Mechanical
Engineers (ASME) Class 2, Type 304 stainless steel pressurizer auxiliary spray pipe. The flaw
was axially oriented and was located beneath a pipe support clamp. Subsequently, the licensee
detected a second pipe support clamp with corrosion on the same piping, although no leak was
observed. The licensee replaced the degraded section of pipe. Based on a failure analysis of
the pipe specimen, the licensee attributed the flaws to transgranular stress corrosion cracking
(TGSCC) originating at the outside surface. The licensee also observed pitting corrosion on the
outside surface of the pipe under pipe support clamps. Pitting and TGSCC of austenitic
stainless steels are caused by exposure to chlorides. The licensee performed a chemical
analysis of the pipe surface before performing penetrant testing and detected chlorides on the
outside surface of the pipe.
The pressurizer auxiliary spray line is used during normal shutdown operation. During normal
plant operation, the coolant in the line is stagnant, but pressurized by the normal charging
system. A control valve in the line is normally closed and the line is insulated. The temperature
of the line is the surrounding ambient temperature during normal operation. During periods of
warm weather, the moisture content in the containment building is elevated. The licensee
believes that, under these circumstances, it is likely that condensation will form in the crevice
between the pipe clamp and pipe outside surface. According to the licensee, the line operates
between 120 - 212 ºF during lower energy operations. The location of cracking is not close to
any pipe welds.
Wolf Creek Generating Station, Unit 1
In October 2009, as a result of the Callaway findings, Wolf Creek Generating Station (Wolf
Creek) personnel conducted liquid-penetrant testing on similar piping and detected several axial
indications beneath the pipe support clamps of the pressurizer auxiliary spray line. On one of
the clamps, a small quantity of boron crystals was observed, indicating a through-wall flaw in the
pipe. The through-wall flaw was not located near any pipe welds. The licensee attributed
cracking to SCC originating at the outside diameter. Based on a review of relevant operating
experience, the licensee concluded that the outside diameter-initiated SCC (ODSCC) was most
likely TGSCC due to the presence of chlorides. As a result of the through-wall flaw, the licensee
inspected other safety piping systems potentially susceptible to TGSCC to determine the extent
of the condition. In this expanded inspection, the licensee performed visual examinations of
potentially susceptible piping (i.e., chemical and volume control, accumulator safety injection, and high pressure coolant injection piping) to identify boric acid deposits or potential leaks in the
proximity of pipe supports or elements that contact the outside surface of the pipe. The licensee
did not find any boron crystal deposits or leakage in the expanded inspection. Wolf Creek and
Callaway are sister plants. The above degradation, environment, and operating conditions in
the pressurizer auxiliary spray line at Callaway apply to Wolf Creek.
San Onofre Nuclear Generating Station, Units 2 and 3
From 2009 to 2010, personnel at San Onofre Nuclear Generation Station (SONGS) detected
three leaks at Unit 2 and five leaks at Unit 3 in various ASME Class 2 stainless steel pipes. The
affected systems include refueling water storage tank (RWST) gravity feed line to charging
pump, RWST line to the emergency core cooling system (ECCS) suction line, ECCS minimum
return line to the RWST, and containment emergency sump to the charging pump. The
following are details of three representative degradation incidents at SONGS.
At SONGS Unit 2, the licensee identified boric acid residue on the 6-inch diameter, Schedule 10
(0.134-inch nominal wall thickness), Type 304 stainless steel RWST gravity feed line to
charging pump suctions. The boric acid residue was found at the toe of a pipe weld joint. The
pipe was located in a tunnel, not insulated, and exposed to a marine atmosphere environment.
The coolant in the line is stagnant during normal operation and is under static head pressure of
the gravity feed pipe. The Unit 2 pipe had a circumferential flaw approximately 0.5-inches long on the inside surface and 0.1-inch on the outside surface of the pipe. The licensee performed
destructive examinations on the affected area of the Unit 2 pipe. The licensee has not
completed the failure analysis but its preliminary assessment found that the circumferential flaw
was initiated from the inside surface of the pipe and was located within the heat-affected zone of
a pipe weld. The licensee observed excessive heat tinting on the inside surface and pitting on
the outside surface of the pipe. The preliminary assessment showed that the heat-affected
zone may be sensitized.
At SONGS Unit 2 the licensee found two leaks on the 24-inch, Schedule 10, RWST to train A
ECCS suction piping. The pipe is at ambient temperature and is exposed to a marine
atmosphere environment. The coolant inside the pipe is stagnant during normal operation. The
licensees preliminary laboratory results show that the degradation on this piping has similar
aspects to the degradation observed on the 6-inch RWST gravity feed pipe. Specifically, the
boric acid residue was found at the toe of a butt weld in the 24-inch pipe, outside surface pitting
was present, and linear indications were found by penetrant testing. The cause of the leakage
has not yet been determined.
For SONGS Unit 3, the licensee found different flaw characteristics on the 24-inch, Schedule
10, RWST line to the train A ECCS suction line. The licensee detected three indications at the
north-side pipe support lug and two indications at the south-side pipe support lug (the lugs were
welded to the pipe). The most significant indication was a 100 percent through-wall flaw
1.875-inches long. The failure mechanism for the cracking in the vicinity of the lug has not yet
been determined. The licensee removed the affected section of the pipe during a refueling
outage and will analyze it in the near future.
BACKGROUND
In 10 CFR 50.55a(a)(1), the NRC requires that structures, systems, and components must be
designed, fabricated, erected, constructed, tested, and inspected to quality standards
commensurate with the importance of the safety function to be performed. The regulation in
10 CFR 50.55a(a)(2) requires that systems and components in boiling and pressurized
water-cooled nuclear power reactors must meet American Society of Mechanical Engineers
Boiler and Pressure Vessel Code (ASME Code) Sections III and XI.
ASME Code Sections III and XI contain requirements for the construction of piping and
mechanical components of nuclear power plants, and for the inspection and testing of piping
and mechanical components of nuclear power plants, respectively. Therefore, the structural
integrity of the piping discussed above is governed and monitored by ASME Code Sections III
and XI, in accordance with 10 CFR 50.55a, Codes and Standards.
Related Generic Communications
- NRC Circular 76-06, Stress Corrosion Cracks in Stagnant Low Pressure Stainless Piping
Containing Boric Acid Solution at PWRs
- Bulletin 79-17, Pipe Cracks in Stagnant Borated Water Systems at PWR Plants * IN 79-19, Pipe Cracks in Stagnant Borated Water systems at PWR Plants
- IN 85-34, Heat Tracing Contributes to Corrosion Failure of Stainless Steel Piping
- IN 91-05, Intergranular Stress Corrosion Cracking in Pressurized Water Reactor Safety
Injection Accumulator Nozzles
- IN 97-19, Safety Injection System Weld Flaw at Sequoyah Nuclear Power Plant, Unit 2
DISCUSSION
The operating experience described above shows that, as nuclear plants age, SCC can
potentially become an emergent degradation mechanism in PWRs for environments that contain
chlorides or stagnant flow conditions. Licensees should be aware of the potential for SCC to
occur in stainless steel in PWR applications.
Material
There have been cases of intergranular stress corrosion cracking (IGSCC) of austenitic
stainless steels in PWRs. NRC IN 91-05 and IN 97-19 discuss cases of IGSCC in PWRs due to
furnace sensitized materials being exposed to an oxygenated environment. IGSCC in austenitic
stainless steels is usually attributed to sensitization of the material by excessive exposure of the
material to temperatures between approximately 800 - 1,500 oF, usually during fabrication.
Particular care is needed when welding thin-walled components, which are more prone to
sensitization because the thin sections limit the ability of welding heat to dissipate into
surrounding material.
ODSCC can sometimes be attributed to intergranular cracking in the heat-affected zones of
welds if the base material becomes sensitized by improperly controlled welding, heat treatment, or other fabrication or service conditions that result in temperatures above approximately
800 oF. Pitting at the outside surface of the pipe due to the presence of chlorides may also
contribute to ODSCC because the local chemistry in a pit is conducive to cracking and the pit is
a stress concentration location.
Austenitic stainless steels are subject to TGSCC in the presence of chlorides when the
temperature exceeds approximately 140 oF, although some occurrences have been reported to
occur at lower ambient temperatures. Some of the observed cracking has been transgranular.
Environment
TGSCC of austenitic stainless steels requires the presence of water and an environmental
condition conducive to TGSCC such as a sufficient level of oxygen dissolved in the water and a
sufficient level of chlorides. The SCC is more severe with increasing temperature and chloride
concentration. For the TGSCC at Callaway, the licensees preliminary study showed that the
probable cause was chloride contamination on the pipe trapped in a crevice environment
between the pipe and the clamps. The temperature swings in the containment could permit condensation to accumulate in the interface between the pipe clamps and the outside surface of
the pipe. The condensation may dissolve residual chlorides resulting in a corrosive
environment.
Potential sources of chlorides include atmospheric chloride from sea spray or marine
environments, tapes, marking fluid, threaded joint compounds, sweat, and insulation. Industry
experience with ODSCC shows that austenitic stainless steels have high susceptibility to
chloride-induced SCC. TGSCC can occur in either sensitized or non-sensitized material at low
applied stress (when residual stress is sufficient) and even at near-ambient temperature where
local effects such as heat tracing, sunlight or other sources of heat raise the local temperature
near 140 oF. NRC IN 85-34 discusses the impact of heat tracing on a pipe and chlorides in the
water inside the pipe that led to SCC at a nuclear plant.
Electric Power Research Institute literature indicates that even very low levels of chloride can
have a detrimental influence on crack growth rates observed in the laboratory, especially at the
higher oxidizing potentials associated with the presence of oxygen in solution. The nuclear
power plants located close to oceans are susceptible to chloride-induced ODSCC because of
the salty air. In addition, inland plants such as Wolf Creek and Callaway are also susceptible to
chloride-induced degradation from other chloride sources.
Stresses
Stresses that contribute to SCC are due to operational and/or residual stresses. Higher stress
increases the susceptibility for SCC. Pipe cracking can also be initiated at surface
discontinuities (e.g., welded pipe support lugs, pits, rough ground areas, and crevices created
by mechanical or welded joints). These areas can have higher residual stresses and altered
microstructures that are susceptible to SCC (particularly in the case of the welded materials).
However, these areas can also be occluded areas where the local environment can evolve into
a corrosive environment and become different from the bulk environment. For pitting corrosion, such as under pipe support clamps, the stress component of ODSCC may come from stress
concentration points in pits in combination with the operational stresses such as pressure and
temperature.
CONCLUSION
SCC can be managed effectively to minimize the potential for catastrophic pipe failure through
stainless steel piping cleanliness control and limiting the contact with fluids (including sweat
from personnel) or condensation that may contain halogens (chlorides and fluorides). Water
chemistry can be used to minimize the adverse effect of oxygen and chloride on SCC. When
welding piping joints or attachments, appropriate procedures can be followed to minimize
stainless steel sensitization. Periodic inspections of the susceptible piping systems as part of
the existing boric acid corrosion control program per the April 2008 Nuclear Energy Institute
report NEI 03-08, Revision 1, Guideline for the Management of Materials Issues, or as part of
routine walkdowns have been instrumental in detecting SCC in stainless steel piping. By letter
dated October 14, 2010, the PWR Owners Group issued PA-MSC-0474, Outside Diameter
Initiated Stress Corrosion Cracking Revised Final White Paper, which provides additional
information on SCC. Austenitic stainless steel piping is susceptible to TGSCC when tensile stresses are applied in a
chloride environment where local temperatures exceed approximately 140 oF. Austenitic
stainless steel piping is susceptible to IGSCC when the material is sensitized. IGSCC can
occur in austenitic stainless steels exposed for a sufficient time to temperatures between about
800 and 1,500 oF and subsequently exposed to tensile stress and water containing sufficient
levels of oxygen (typically at least 100 parts per billion) at elevated temperatures. SCC can be
initiated from the outside and inside surfaces of the pipe and can occur at the (1) location of
stress concentration regions (such as at welds for pipe restraint lugs) or susceptible regions for
corrosion at the interface between the pipe and support clamp and (2) sensitized heat-affected
zone of a weld. Sensitization can be minimized or prevented by using the guidance in NRC
Regulatory Guide 1.44, Control of the Use of Sensitized Stainless Steel.
CONTACT
This IN requires no specific action or written response. Please direct any questions about this
matter to the technical contact listed below or the appropriate Office of Nuclear Reactor
Regulation (NRR) project manager.
/RA/ /RA by MShuaibi for/
Thomas B. Blount, Acting Director John R. Tappert, Acting Director
Division of Policy and Rulemaking Division of Construction Inspection and
Office of Nuclear Reactor Regulation Operational Programs
Office of New Reactors
Technical Contact:
John C. Tsao, NRR
301-415-2702 E-mail: John.Tsao@nrc.gov
Note: NRC generic communications may be found on the NRC public Web site, http://www.nrc.gov, under Electronic Reading Room/Document Collections. Initiated Stress Corrosion Cracking Revised Final White Paper, which provides additional
information on SCC.
Austenitic stainless steel piping is susceptible to TGSCC when tensile stresses are applied in a
chloride environment where local temperatures exceed approximately 140 oF. Austenitic
stainless steel piping is susceptible to IGSCC when the material is sensitized. IGSCC can
occur in austenitic stainless steels exposed for a sufficient time to temperatures between about
800 and 1,500 oF and subsequently exposed to tensile stress and water containing sufficient
levels of oxygen (typically at least 100 parts per billion) at elevated temperatures. SCC can be
initiated from the outside and inside surfaces of the pipe and can occur at the (1) location of
stress concentration regions (such as at welds for pipe restraint lugs) or susceptible regions for
corrosion at the interface between the pipe and support clamp and (2) sensitized heat-affected
zone of a weld. Sensitization can be minimized or prevented by using the guidance in NRC
Regulatory Guide 1.44, Control of the Use of Sensitized Stainless Steel.
CONTACT
This IN requires no specific action or written response. Please direct any questions about this
matter to the technical contact listed below or the appropriate Office of Nuclear Reactor
Regulation (NRR) project manager.
/RA/ /RA by MShuaibi for/
Thomas B. Blount, Acting Director John R. Tappert, Acting Director
Division of Policy and Rulemaking Division of Construction Inspection and
Office of Nuclear Reactor Regulation Operational Programs
Office of New Reactors
Technical Contact:
John C. Tsao, NRR
301-415-2702 E-mail: John.Tsao@nrc.gov
Note: NRC generic communications may be found on the NRC public Web site, http://www.nrc.gov, under Electronic Reading Room/Document Collections.
ADAMS Accession Number: ML103410363 TAC ME 4917 OFFICE DCI:CPNB Tech Editor BC:DCI:CPNB D:NRR:DCI BC:NRR:DLR:RARB BC:NRO:DE:CIB2 NAME JTsao K Azariah-Kribbs TLupold (JTsao for) MEvans (JLubinski ADias MNorato
for)
DATE 1/27/11 e-mail 12/17/10 e-mail 2/3/11 2/8/11 2/9/11 2/10/11 OFFICE PM:NRR:PGCB LA:NRR:PGCB BC:NRR:PGCB D:NRO:DCIP D:NRR:DPR
NAME ARussell CHawes SRosenberg JTappert (Acting) TBlount (Acting)
(MShuaibi for)
OFFICE 2/14/11 2/14/11 2/18/11 2/22/11 2/23/11 OFFICIAL RECORD COPY