Information Notice 2011-04, In: Contaminants and Stagnant Conditions Affecting Stress Corrosion Cracking in Stainless Steel Piping in Pressurized Water Reactors

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)
	v • d • e

ML103410363 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