External Corrosion in an API 650 Tank Shell-to-Annular Plate Junction

By Vince Carucci

Previous issues of The Carmagen Engineering Report discussed the problem of assessing corrosion of the annular plate in an API 650 tank. In this issue, the problem of assessing external shell corrosion in the region just above the shell-to-annular plate junction will be covered. Corrosion of this type is quite common if grading around the tank mounds up due to shell settlement and rainwater collects around the tanks base. It also occurs on insulated tanks if the weather covering becomes damaged and water accumulates between the insulation and shell. General or pitting type corrosion in the tank shell can be assessed using API 653 criteria. However, the lower portion of the shell and annular plate are subjected to high secondary stresses in addition to membrane stresses in the shell-to-annular plate junction. Also, high peak stresses occur at the toe of the fillet welds attaching the annular plate to the shell which can cause fatigue cracking and failure.

In the standard API 653 evaluation procedure, a minimum average thickness for a shell course, t1, is determined based on averaging the minimum thickness over a considerably large region (maximum 40 inches). This minimum average thickness, minus the expected future corrosion allowance, must be greater than the minimum thickness required by either the API One-Foot Method or Variable-Design-Point Method, tmin. The actual minimum thickness of the shell, t2, less any future corrosion allowance must also be greater than 60% of tmin. While the API 653 criteria allows for a considerable amount of corrosion, the procedure is still somewhat conservative when applied to the region of the annular plate-to-shell junction. This is due to the stiffening effect of the annular plate and the restraint provided by the tank foundation ring wall. Since API 653 allows use of the ASME Code Section VIII, Division 2 “design by analysis method,” tanks which exceed the basic API 653 evaluation criteria can still be evaluated by making a detailed analysis, and a determination can be made based on a more comprehensive understanding of the stresses in the junction.

To illustrate this analysis approach, a 183 ft. diameter tank, in which half of the bottom course thickness was corroded away, was analyzed using the ALGOR finite element program. The stresses in most of the shell can be classified as primary membrane stresses and must be limited to a quality called Sm per the Division 2 method.

Sm is equal to the lower of the allowable stress that was used in the original tank design, 2/3 of the specified minimum yield strength, or 1/3 of the minimum tensile strength. However, in the region of the shell to annular plate junction, the stresses can be classified as a combination of primary (local membrane and bending) and secondary stresses. In accordance with the Division 2 procedure, these stresses can be permitted to go as high as 1.5 to 3 times Sm, depending on the stress category. Peak stresses are also calculated at the toes of the fillet welds in the junction and can also be evaluated using the Division 2 rules.

The stress analysis assumed that the outside fillet weld has been restored to approximately its original size and a 1/8 inch corrosion allowance is required until the next inspection. Figure 1 shown the finite element model used in the study, and Figure 2 shows a plot of the membrane, bending and the maximum combined stress intensity along the tank shell in the junction region. All of the stresses are below the appropriate Division 2 allowable stresses. In addition, a peak stress intensity of approximately 80 ksi occurs at the toe of the fillet welds in the annular plate. However, this peak stress is still acceptable as it would yield a fatigue life of over 1000 cycles.

In summary, over one half the original thickness of the tank shell is gone in this case. However a detailed stress calculation made in accordance with Division 2 rules demonstrated that the tank is still suitable for continued operation without downrating or undertaking an extensive repair. Therefore, use of detailed stress analysis should be considered in situations where localized tank shell corrosion exceeds the basic API 653 considered acceptance criteria.