United States Nuclear Regulatory Commission - Protecting People and the Environment

Information Notice No. 89-79: Degraded Coatings and Corrosion of Steel Containment Vessels

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

                              December 1, 1989


Information Notice No. 89-79:  DEGRADED COATINGS AND CORROSION OF 
                                   STEEL CONTAINMENT VESSELS


Addressees:

All holders of operating licenses or construction permits for light-water 
reactors.

Purpose:

This information notice is intended to alert addressees to the discovery of 
severely degraded coatings and the corrosion of steel ice condenser contain-
ment vessels that are caused by boric acid and collected condensation in the 
annular space between the steel shell and the surrounding concrete shield 
building.  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:

On August 24, 1989, Duke Power Company reported significant coating damage 
and base metal corrosion on the outer surface of the steel shell of the 
McGuire Unit 2 containment which was discovered during a pre-integrated leak 
rate test inspection (as required by Appendix J to 10 CFR Part 50).  
Subsequently, Duke Power identified similar degradation of the McGuire Unit 
1 containment, which is essentially identical to the Unit 2 structure.

Both units have ice condenser-type containments consisting of a freestanding 
steel shell surrounded by a concrete shield building.  Between the shell and 
the shield building is a 6-foot-wide annular space.  The steel shells have a 
nominal thickness near the annulus floor of 1 inch.  The degraded area on 
the shells of both units is limited to 30-foot circumferential sections no 
higher than 1+ inches above the annulus floors.  The average depth of the 
corrosion is 0.1 inch with pits of up to 0.125 inch.  Corrosion that is up 
to 0.03 inch deep was also found in areas below the level of the annulus 
floor on the Unit 2 shell, where concrete was removed to expose the shell 
surface.  This below-floor corrosion is due to a lack of sealant at the 
interface between the shell and the annulus floor.






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                                                       IN 89-79
                                                       December 1, 1989
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The probable cause of the degradation is attack by condensed boric acid 
coolant leaking from instrument line compression fittings.  Drains are 
provided in the annulus floor, but they are widely separated and the floor 
is not sufficiently graded to prevent pooling of the condensate between the 
drain locations.  The current average thickness of the corroded areas of the 
containment shells of 0.9 inch is expected to be reduced to no less than 
0.85 inch for Unit 1 and 0.88 inch for Unit 2 by the time they are repaired 
during the next planned outages for these units.  These estimates were made 
assuming the worst corrosion rates that could reasonably be expected and are 
greater than the minimum thickness allowed by the applicable ASME Code. 

On September 21, 1989, Duke Power Company discovered coating damage and base 
metal corrosion during inspections of the steel shells of its two Catawba 
containments.  These containments are also of the ice condenser type and are 
very similar to the McGuire containments; the nominal floor level shell 
thickness is 1 inch.  Here also, the degradation was located on the outer 
surfaces of the shells at the intersection of the shell and the concrete 
annulus floor.  At Catawba the damage was less extensive and was limited to 
a circumference of 15 feet, a height of 1 inch above the annulus floor, and 
an average depth of 0.03 inch.  The cause is also believed to be attack by 
boric acid coolant, which had leaked from instrument line compression 
fittings, condensed, and collected on the annulus floor.

Duke Power Company plans to repair the steel shells of all four units during 
their next respective refueling outages.  This will include weld repair and 
recoating of the corroded areas.

Discussion:

The degradation of the containment shells at the McGuire and Catawba plants 
is considered significant for several reasons.  The fact that the corrosion 
affects four different units indicates that other steel containments with 
similar configurations may be susceptible to the same problem.  Furthermore, 
the observed rate of corrosion far exceeds the allowance made for corrosion 
in the containment design.  This condition leads to the concern that such 
corrosion could result in undetected wall thinning to less than the minimum 
design thickness, accompanied by a loss of leaktightness or structural inte-
grity.  This problem can be prevented by a containment inservice inspection 
program that is adequate to ensure early detection and the maintenance of 
design margins through proper corrosion control.

The NRC regulations (Appendix J to 10 CFR Part 50) require that a general 
visual inspection of the accessible surfaces in the containment be performed 
before each integrated leak rate test.  The purpose of this inspection is to 
identify any evidence of structural deterioration or other problems that may 
affect containment integrity or leaktightness.  As a result of these and 
other inspections, several instances of containment wall thinning due to 
corrosion have been discovered during the past 3 years at operating power 
reactors.  However, the visual inspections done in connection with the 
integrated leak 
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                                                       IN 89-79
                                                       December 1, 1989
                                                       Page 3 of 3


rate tests are only required to be performed three times in each 10-year 
period.  In addition, because of the physical arrangement of plant systems, 
the steel surfaces in the annular spaces of some containments may not be 
easily accessible to the visual inspections associated with leak tests.  
Considering the frequency and severity of recent instances of containment 
degradation due to corrosion, additional efforts to inspect steel 
containment surfaces potentially susceptible to corrosion may be prudent.

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:  Chen P. Tan, NRR
                     (301) 492-0829

                     Keith R. Wichman, NRR
                     (301) 492-0908

Attachment:  List of Recently Issued NRC Information Notices
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