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As oilfield technologies have advanced, they have made high temperature (HT) reservoirs more accessible. HTs make the application of chemical more difficult because chemical instability at HT restricts what intermediates will work in these environments and the safety and complexity of HT testing further adds to the challenge.
The application temperature for oilfield chemicals often exceeds 120°C (248°F). This temperature is important because it is the threshold for the thermal breakdown of many oilfield chemicals. The breakdown of oilfield chemicals used to treat problems such as corrosion, scale, oil-water separation, bacterial corrosion, etc. can create additional problems if they are applied at temperatures greater than their breakdown temperatures. The breakdown products can cause gunking and in some cases the breakdown products can be corrosive to mild steel. This paper explores the high temperature thermal stability of several common families of molecules including amines, quaternary amines, phosphate esters, alkylthiols, imidazolines, and polymers at temperatures above and below this key temperature and provides data which describes why this temperature is a hard limit for many oilfield chemicals. Guidance is provided for personnel incorporating chemical treatment in their oilfield systems. This guidance will help identify system components or locations where thermal breakdown should be studied before implementing a chemical program.
Canadian Oil Sands mining operations have been producing oil from sand ore from the early 1960s. Oil Sands mainly consists of high hardness quartz, silica, bitumen and water. Bitumen production processes include mining the sand, washing it with hot water, slurry transportation, tailing disposal and bitumen production. Abrasion, gouging wear, impact wear, erosion and erosion-corrosion are predominant degradation mechanisms in Oil Sand mining operations.
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Carbon and low alloy steels (CS and LAS, respectively) used for exploration and production in the oil and gas (O&G) industry are normally exposed to environments that may contain H2S in a wide range of concentrations. In aqueous solutions, H2S acts as a cathodic poison.1,2 A cathodic poison inhibits the recombination of atomic hydrogen to H2, and as a result, favors its absorption by the metal.1,2 In the presence of a susceptible microstructure and the simultaneous effect of applied or residual tensile stress, a crack can nucleate and propagate, when a critical concentration of hydrogen is reached in the metal.3 This environmentally assisted cracking (EAC) phenomenon is known as Sulfide Stress Cracking (SSC).2 SSC is commonly addressed as a case of hydrogen embrittlement (HE) damage.2
Robust integrity management plans are critical for ensuring the lifespan and preventing failures of manmade infrastructure, including the metal (carbon steel) infrastructure that dominates the oil and gas industry. In this sector and others, many types of corrosion can occur on metal infrastructure, including corrosion that involves the participation of microorganisms, commonly referred to as microbiologically influenced corrosion, or MIC. MIC can be difficult to diagnose as the cause of a given infrastructure failure because it is not a stand-alone mechanism – the physical and chemical properties of a system can influence the types of microorganisms that are present and active, while the metabolisms of these microorganisms can influence the surrounding chemistry and physical properties of a system.