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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.
The deposition of inorganic scale from waters supersaturated with minerals is a significant flow assurance issue in oil and gas production. Several laboratory techniques are routinely used to assess scale deposition and qualify chemical inhibitors but these all have limitations with regard to matching field conditions such as the hydrodynamic regime and residence time that the fluids are likely to experience. In some cases, these tests do not give sufficient confidence to develop scale management strategies and a more field-representative method is required to bridge the gap between laboratory tests and full field trials.
The design and use of a large pilot-scale test system to evaluate scale deposition and inhibition is described in this paper. The system involves flowing large quantities of brine through a test piece at high flow rates for several hours. Different test piece configurations can be used and these are constructed from shorter lengths of pipe allowing scale deposit location and quantity to be readily analysed. An example is given in which sections of pipe made from different materials are used to investigate the effect that this has on scale adhesion. Chemical inhibition has been investigated by the injection of scale inhibitor into the flow stream and evaluating the reduction in surface deposits. Design considerations for these tests are also discussed with results from smaller scale preliminary tests used to ensure that sufficient deposits will be formed in the full-scale tests.
The successful implementation of the pilot-scale test system described provides an important industry tool enabling the evaluation of inorganic scale deposits under field-realistic flow conditions and methods to mitigate the flow assurance issues resulting from them. The results obtained from the tests also advance the understanding of the effect that the use of different materials in oilfield flow systems have on scale deposition.
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 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
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.