This paper investigates the corrosion failure of aluminum tubes on a heat exchanger user to remove heat from the windings of an electric motor. Only the tubes on the perimeter (bottom, top, and sides) at the air inlet location were affected, which is associated with the heat distribution. This investigation concludes that the observed corrosion on the tube is caused by increased chloride concentration from dry out or alternate wetting and drying of the protective aluminum oxide which breaks down, forming a saturated solution of aluminum chloride. The initial aqueous chloride solution is formed by condensation and the high salt content of the inlet air from a marine environment which is then gradually concentrated as it dried out due to heat from the hot nitrogen side of the tube, hence the observed white powder at the tube inlet and vicinity. The concentrated aluminum chloride with an acidic pH of approximately 3.5 becomes very corrosive to the aluminum tubes resulting in the observed pitting and intergranular corrosion. The failure may be seasonal, based on ambient air conditions and the operating temperature of the tube inlet end. Recommendations for prevention are fourfold: change of process/design e.g., dehumidification of the inlet air in order to prevent condensation on the outer tubes; change of material (e.g., use of Incoloy 625 tubes); application of internal coating to prevent condensation (e.g., blast cleaning and coating with a solvent-free epoxy); and replacement of corroded tubes with annual cleaning to remove salts. Selection of the preferred option should involve evaluation of the relative advantages/ disadvantages.

Insulated hot oil lines on high-temperature/ intermittent duty are typically vulnerable to increased risk from corrosion under insulation (CUI) failure. This paper presents the results of an investigation into a CUI failure at an onshore natural gas-processing plant and also discusses the key issues affecting intermittent duty. The inadequate coating was degraded during high-temperature duty (up to 240°C) followed by water ingress through degraded insulation mastic and sealant and resulting in (up to 3 mm) chain (coalesced) pitting during ambient temperature downtime, at damaged coating locations from the 2 to 10 o'clock locations. Several recommendations are proposed for addressing the underlying technical and systemic causes of the failure.

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Thirteen extended H 2 S excursions (19.64 mg/l maximum) above the Standard Operating Limit (SOL, 6.7 mg/l), recorded for the export and onshore pipeline systems in January 2010, contravened the Pipelines Safety Regulations (PSR) 1996 and triggered an assessment to determine the safety of continued operation in a sour service condition. Sampling and monitoring results were assessed and the pH and H 2 S partial pressures were found not to align with any of the ISO 15156 SCC regions of environmental severity (0, 1, 2 and 3). Both pipelines were, therefore, considered safe for continued operation as long as pH remained near-neutral above 6.5. Since pH was found to be the main driver for SSCC risk, pH analysis has been recommended for every pig receipt with H 2 S and CO 2 excursions being the main triggers. Also the high risk of HIC should be mitigated by maintaining pH at near-neutral levels. Very low H 2 S levels have been achieved by pigging, biociding and scavenging and low corrosivities by adequate corrosion inhibition. Weld root hardness of the export pipeline (295 HV 10 ) is out of compliance with ISO 15156 hardness requirements for operating in the SCC region 0 (275 HV 10 ). Risk-based inspection (RBI) reviews are recommended to determine inspection techniques and frequencies appropriate for all susceptible weldments.

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