Information Notice No. 91-05: Intergranular Stress Corrosion Cracking in Pressurized Water Reactor Safety Injection Accumulator Nozzles

                                UNITED STATES
                        NUCLEAR REGULATORY COMMISSION
                    OFFICE OF NUCLEAR REACTOR REGULATION
                           WASHINGTON, D.C.  20555

                              January 30, 1991


Information Notice No. 91-05:  INTERGRANULAR STRESS CORROSION CRACKING 
                                   IN PRESSURIZED WATER REACTOR SAFETY 
                                   INJECTION ACCUMULATOR NOZZLES


Addressees:

All holders of operating licenses or construction permits for pressurized 
water reactors (PWRs).

Purpose:

This information notice is intended to inform licensees of recent problems 
involving intergranular stress corrosion cracking (IGSCC) of PWR safety 
injection accumulator nozzles.  It is expected that recipients will review 
the information for applicability to their facilities and consider actions, 
as appropriate, to avoid similar problems.  However, suggestions contained 
in this information notice do not constitute NRC requirements; therefore, no 
specific action or written response is required.

Description of Circumstances:

In January 1988, personnel at the Prairie Island Nuclear Generating Plant, 
Unit 2, detected a leak in one of the safety injection accumulators.  The 
leak was determined to be in a two-inch diameter nozzle for the water level 
sensing instrumentation line.  The licensee (Northern States Power Company) 
determined that the failure mode was IGSCC in a crack that started as a 
consequence of high stresses caused by the improper fit-up of the pipe to 
the nozzle in preparation for welding. 

In October 1990, personnel detected a leak from safety injection accumulator 
"C" at the H. B. Robinson Steam Electric Plant, Unit 2, during the 10-year 
inservice inspection hydrostatic test.  This leak was also located in a 
two-inch diameter nozzle for the water level sensing instrumentation line.  
In both cases, the accumulators involved are part of the safety injection 
system and contain borated water maintained at approximately 600 psig by 
nitrogen cover gas.

Discussion:

At Prairie Island Unit 2, the leak occurred in a nozzle that was submerged 
in the borated water near the bottom of the tank.  Westinghouse Electric 
Corporation performed a failure analysis at the request of the licensee 
which revealed 



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that the cause of the failure was IGSCC.  Westinghouse attributed the 
stresses that were responsible for initiating the crack to the improper 
fit-up of the nozzle socket to the pipe in preparation for welding.  
Specifically, during the fit-up of the nozzle, the small gap which is 
required to be maintained between the end of the pipe and the bottom of the 
socket while the welding procedure is performed was not established.  The 
investigation at Prairie Island confirmed that the gap had not been 
maintained and that the pipe had been seated fully into the nozzle before 
welding.  This situation is believed to have caused the stresses that 
initiated the crack and promoted IGSCC in the nozzle.  The analysis by 
Westinghouse also clearly indicated that the nozzle material was in a 
sensitized condition, making it susceptible to IGSCC.  The licensee 
inspected other nozzles at Prairie Island and found no significant 
indications of cracking.  At that time, Westinghouse attributed the failure 
primarily to the fit-up problem and took no further actions.

Carolina Power and Light Company (CP&L, the licensee) performed a failure 
analysis on the cracked nozzle from Robinson, Unit 2.  The results of the 
analysis indicated that IGSCC caused the leak.  The nozzle appeared to be 
manufactured from 304 stainless steel based on a chemical analysis of a 
sample that was removed from the nozzle.  The crack had started on the 
inside diameter (ID) of the coupling and extended axially along the nozzle 
ID within the tank shell.  The portion of the crack that propagated to the 
outside diameter (OD) of the nozzle was approximately 3/16-inch long and did 
not extend into the nozzle attachment fillet weld reinforcement.  CP&L 
concluded that the full penetration weld (double-V groove design) connecting 
the nozzle to the shell produced the residual stresses that initiated the 
cracking.  The axial orientation of the crack appears to provide some 
justification for this conclusion.

The failed nozzle at Robinson, Unit 2, was manufactured using austenitic 
stainless steel that became sensitized.  CP&L attributed the sensitization 
of the coupling primarily to the post weld heat treatment (PWHT) of the 
accumulator performed by the manufacturer (Delta Southern Company, formerly 
located in Baton Rouge, Louisiana) in combination with the welding of the 
coupling to the accumulator.  Typically, when a manufacturer plans to 
perform PWHT on a component that contains stainless steel, a low carbon 
grade of the material, containing a maximum of 0.035 percent carbon (e.g. 
types 304L or 316L), would be preferred.  These low carbon grades of 
stainless steel are much less susceptible to sensitization and are therefore 
typically considered to be resistant to IGSCC.  During the failure analysis, 
CP&L determined that the carbon content of the failed nozzle was 0.062 
percent.  No certified material test reports could be located for the 2-, 
1-, and 3/4-inch diameter nozzles on the accumulator.  CP&L determined that 
none of these small nozzles on the three accumulators at Robinson Unit 2 
were made using low carbon content stainless steel, but that the 10-inch 
nozzles on the bottom of the tanks were made using stainless steel with low 
carbon content.  The Westinghouse specification for the nozzles called for 
304 stainless steel and did not specify a requirement for low carbon 
content.  

The exact corrosive environment that contributed to the crack's propagation 
could not be determined.  This particular nozzle was in the portion of the 
accumulator that was filled with gaseous nitrogen, and not under water as 
was the nozzle at Prairie Island.
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Later, the licensee performed liquid penetrant and ultrasonic examinations 
on all of the nozzles on the three accumulators at Robinson Unit 2 and found 
that another 2-inch diameter nozzle, in this case on accumulator "A", had a 
crack with the characteristics of IGSCC.  Further excavation of the nozzle 
from accumulator "A" revealed that the cracking was identical to that found 
in the nozzle on accumulator "C."  In both of these cases, the licensee 
found no indication of any problem with the fit-up for the nozzle.

CP&L has reported this condition to the NRC under the provisions of 10 CFR 
Part 21 and has evaluated other tanks and vessels in its plant that were 
supplied by Delta Southern Company and found no further problems.  In order 
to accurately determine the material used in and the condition of the 
nozzles on the safety injection accumulators, CP&L had to review their 
plant-specific drawings and associated records and take filing samples from 
the nozzles for analysis.  Ultrasonic examination of the nozzles in a 
circumferential direction has proven to be the most effective crack 
detection method if examinations are required.

This information notice requires no specific action or written response.  If 
you have any questions about the information in this notice, please contact 
one of the technical contacts listed below or the appropriate NRR project 
manager.




                              Charles E. Rossi, Director
                              Division of Operational Events Assessment
                              Office of Nuclear Reactor Regulation


Technical Contacts:  James L. Coley, Region II
                     (404) 331-5584

                     Robert A. Hermann, NRR
                     (301) 492-0768


Attachment:   List of Recently Issued NRC Information Notices
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