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The Hanford site contains approximately 55 million gallons (2.08 x 108 liters) of radioactive and chemically hazardous wastes arising from weapons production, beginning with World War II and continuing through he Cold War era. The wastes are stored in 177 carbon steel underground storage tanks, of which 149 are single-shell tanks (SSTs) and the remaining are double-shell tanks (DSTs). Historically, tank failures have been associated with the SSTs
Radioactive and chemically hazardous wastes are stored at the Hanford site in underground double-shell tanks (DSTs) constructed of carbon steel. The corrosion management of these tanks has largely focused on the complex waste chemistries that reside within the interiors of the primary tanks. More recently, attention has been given to the corrosion that has been found on the exterior of the secondary liners of the DSTs. The cause of the external corrosion seems to be related to the intrusion and accumulation of groundwater in the tertiary leak detection systems, which exist under the concrete foundations of the DSTs. The external corrosion has led to significant wall-loss (up to 70% in one of the tanks), which has occurred in a localized manner (broad pitting). In addition, site measurements have indicated that the most significant areas of wall-loss are aligned with the slots (drain channels) of the concrete foundation.
The power plant is a natural gas-fired, combined cycle plant with three combustion turbines and a single steam turbine. A large stainless steel surface condenser is used to condense steam off of the turbine, and provide high purity steam condensate return to the boiler system. The steam condenser was put into service approximately 15 years ago. This plant takes makeup water for its open recirculating cooling tower water system from a river location that is inland from an ocean coastal area.
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The formation of common inorganic scales (such as BaSO4, SrSO4, CaSO4 and CaCO3) in production tubing presents a significant problem in the oil and gas industry. The mixing of incompatible waters or changes in temperature, pressure, pH or hydrodynamics of a fluid may result in scale deposition, with the potential to cause constrictions in production tubing when allowed to build up. This can lead to costly interventions that result in delayed production and loss of revenue. Therefore, an effective scale mitigation strategy is a crucial part of field development and management.
Naphthenic acids and sulfur species in crude oil cause severe corrosion of the steel equipment of crude distillation units in oil refineries.1–3 Because of rapidly changing oil economics, the refineries have inclined towards cheaper “opportunity crudes”, but the high levels of corrosive species, mainly naphthenic acids and organosulfur compounds, in these crudes would reduce the life of the equipment, and also increase the risk of catastrophic failure.3 So the opportunity crudes are often blended with the crudes containing lower levels of corrosive species; this decreases overall concentration of corrosive species and the corrosion rates.4,5 However, corrosion rates are not simply proportional to the concentrations of naphthenic acids and sulfur species that are present in the crude oil.4,5 Without accurate estimation of corrosion rates by crude oils or their “blends”, carbon steel equipment needs to be constructed with higher wall thickness for safety; if still insufficient, high alloy steels are required.