Information Notice No. 84-18: Stress Corrosion Cracking Water Reactor Systems

                                                           SSINS No.:  6835 
                                                           IN 84-18        

                               UNITED STATES 
                           WASHINGTON, D.C. 20555 

                               March 7, 1984 

                                   WATER REACTOR SYSTEMS 


All nuclear power reactor facilities holding an operating license (OL) or 
construction permit (CP). 


This information notice is being issued to remind all holders of pressurized
water reactor (PWR) licenses and construction permits that PWR systems are 
susceptible to stress corrosion cracking in the presence of various 
corrodants. Information is also presented on actions which, if properly and 
conscientiously implemented, can significantly reduce the likelihood of such


Stress corrosion cracking in boiling water reactor (BWR) primary pressure 
boundary piping is currently receiving considerable industry and NRC 
attention. This circumstance may lead to an unwarranted conclusion that 
similar problems do not occur in PWRs. The reactor coolant system (RCS) of a 
PWR has a hydrogen overpressure maintained as an oxygen getter during power 
operation. As a result, the primary pressure boundary piping of PWRs have 
generally not been found to be affected by stress corrosion cracking. 

However, there are two conditions where significant potential exists for 
inadvertent introduction of contaminants into PWR fluid systems. The first 
opportunity is unacceptable levels of contaminants in the boric acid 
purchased. The second is the free surface of the spent fuel pool which can 
be a natural collector of airborne contaminants. During refueling operations
there is direct communication between the reactor coolant system and the 
spent fuel pool, as well as increased free surface to collect any airborne 
contaminants caused by concurrent maintenance activities. At Three Mile 
Island Unit 1, during the extended shutdown caused by the Unit 2 accident, 
sodium thiosulfate in some way was introduced into the reactor coolant 
system and caused extensive stress corrosion attack on the Inconel 600* 
steam generator tubes. The thiosulfate solution was normally kept in a 
storage tank to be available as an 

*Inconel 600 is an alloy trade name of International Nickel Company. 


                                                            IN 84-18       
                                                            March 7, 1984  
                                                            Page 2 of 3    

additive to the containment spray system fluid. This design concept was 
employed only in reactors designed by Babcock and Wilcox, and is no longer 

Other systems which utilize borated water, and, therefore, are also made 
with austenitic materials, may not receive the same attention which is given 
to the RCS fluid.  These systems are extensively cross-connected, and some 
equipment serves more than one system function. Thus, contaminants 
introduced at any point may appear elsewhere. Because of inadvertent safety 
injection actuation, potentially contaminated water can enter the reactor 
coolant system. 

Stress corrosion cracking generally requires the presence of three factors: 
a high level of local stress, material that is sensitive to attack, and the 
presence of an active anion corrodant.  Examples of such corrodants are 
oxygen, chlorides, fluorides, sulfides, and other sulfur ions. In BWRs, 
oxygen appears to be the corrodant ion. The first two factors appear as an 
inherent result of the normal welding process which was used for assembling 
piping systems in reactors currently operating. The third factor can be 
controlled independent of the fabrication process used. 

In September 1980, the NRC published NUREG-0691, "Investigation and 
Evaluation of Cracking Incidents in Piping in Pressurized Water Reactors."* 
That NUREG discusses pipe cracking from a variety of causes in austenitic 
and nonaustenitic materials. Information is contained on the various 
instances of cracks through May 1980. Additional information is contained in
NUREG-0679* published in August 1980. 

Since the publication of NUREG-0691 and 0679, additional instances of stress
corrosion attack have been reported. 

On December 16, 1981, while transferring spent fuel in the storage pool for 
Prairie Island, the top nozzle for one fuel assembly separated from the body
of the assembly. The cause was not immediately apparent. On May 12, 1982, 
the licensee submitted a report which indicated that the cause had been 
identified as stress corrosion cracking. No specific corrodant was 
identified but corrosion products on the crack surfaces contained Si, Al, 
Cu, and Cl. None of the other fuel assemblies in storage were similarly 
affected. It is not known for certain whether the corrosion cracking 
occurred during operation or in the storage pool, but the presumption is 
that the cracking occurred in the storage pool. 

On January 29, 1983, Northern States Power Co. (the licensee) notified the 
NRC that Prairie Island Unit 1 had been shut down because of a leak detected
in a pipe connecting the boric acid storage tanks to the safety injection 
system. This pipe is part of the system used to mitigate the consequences of
a main 

*Available in microfiche form from National Technical Information Service, 
 Springfield, VA 22161. 

                                                            IN 84-18       
                                                            March 7, 1984  
                                                            Page 3 of 3    

steamline break, and is required by the plant technical specifications to be
operable whenever the unit is at power. Extensive stress corrosion cracking 
was identified during piping inspections. Unit 1 remained shut down until 
mid-April 1983, when it was returned to power operation following repairs. 

Metallurgical examination of sections of piping removed during the repair 
effort disclosed extensive stress corrosion attack. A deposit of iron oxide 
on the inner wall of the pipe contained 79 to 110 ppm of chlorides, 114 to 
204 ppm of sulfates, and 10 to 84 ppm of fluorides. The piping system was 
normally stagnant and heat-traced to 180F to keep the concentrated 
boric acid in solution. The source of the contaminants is believed to be 
impurities in the purchased boric acid which were concentrated under 
stagnant, heated conditions. 

PWR accident mitigation systems are normally in a standby condition and 
hence provide a fertile environment for stress corrosion cracking. In 
addition to technical specification surveillance requirements to exercise 
pumps and valves on a regular schedule, some licensees have initiated 
measures to recirculate and test system fluids for potential contaminants to 
facilitate prompt removal of any identified contaminants. In this 
connection, Northern States Power Co. at Prairie Island is utilizing ion 
exchange chromatography to detect the presence of potentially harmful 
contaminants and reports that this is a practical, effective technique. 

No specific action or response is required by this information notice. If 
you have any questions regarding this matter, please contact the Regional 
Administrator of the appropriate NRC Regional Office, or this office. 

                                   Edward L. Jordan, Director 
                                   Division of Emergency Preparedness 
                                     and Engineering Response 
                                   Office of Inspection and Enforcement 

Technical Contact:  J. B. Henderson, IE 

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