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Application of corrosion inhibitors confer many advantages for combatting internal pipeline corrosion in the upstream oil and gas industry. It is known that the associated costs for using corrosion inhibitors are low compared to other mitigation techniques [1]. For continuous injection procedures, water-soluble inhibitors are not expected to form long-lasting films, so they must be continuously injected to maintain their effectiveness. Batch inhibitors are usually higher molecular weight species and oil soluble. They tend to be more tenacious, providing a protective barrier between the water and the metal over a long period of time.
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Offshore metallic structures have an average life-time of 20-25 years. They consist of four different zones, the buried, the submerged, the tidal/splash and the atmospheric one. According to NACE 2013 the global corrosion cost is estimated to be US$2.5 trillion, consisting a major economic problem. Hence, protection from corrosion is essential. Each zone is protected either with cathodic methods, or with a combination of cathodic methods and coatings. More specifically, the protection of the atmospheric zone, which is the aim of this research, due to the lack of continuous electrolyte (seawater) does not allow the application of cathodic protection.
Wells in oil, gas and geothermal production experience a broad spectrum of operating conditions in terms of temperature, depth, pressure and production environments, which govern material selection. For severe environments, where high strength and toughness combined with excellent corrosion and cracking resistance are required, a new superaustenitic stainless steel has been recently developed. Aiming for a minimum yield strength of at least 120 ksi (827 MPa), strain hardening enables the desired mechanical properties, allowing users to avoid well known but HISC susceptible and less cost effective precipitation hardened (PH) nickel alloys.
Sour corrosion and iron sulphide scale deposition are two common flow assurance issues encountered in oilfields. Sour oil wells typically produce crude along with produced water and a significant amount of acidic gases such as carbon dioxide and hydrogen sulfide. The high pressure and temperature conditions under the downhole tend to cause severe corrosion damage including metal loss and pitting, along with iron sulphide scale deposition. Iron sulfide deposition in sour wells is a corrosion induced scale problem. It potentially causes production decline, restricted well intervention, well shutdown, or even severe consequences towards to the abandoned wells.
TOL corrosion is reported to occur in large diameter wet gas pipeline in stratified flow conditionsdue to low fluid velocities1. With increasing distance from the inlet, the wet gas pipeline becomescooler as it loses heat to the environment. Such cooling causes water, hydrocarbon, and otherhigh vapor pressure species to condense on the pipe wall. The upper part of the pipe willconstantly be supplied with freshly condensed water while the less corrosive water saturatedwith corrosion products will be drained along the pipe wall to the bottom of the line.
The Bureau of Reclamation (USBR) is currently investigating the feasibility of using foul-release coatings to mitigate impacts caused by macro-fouling organisms such as zebra and quagga mussels. Durability of these coatings must be considered as a factor in determining overall life cycle costs. To this end, the Bureau of Reclamation has developed testing protocols to evaluate the durability of foul-release coatings with respect to abrasion, erosion resistance and the ability to overcoat existing equipment.
Offshore oil production facilities are subject to internal corrosion, potentially leading to human and environmental risk and significant economic losses. Microbiologically influenced corrosion (MIC) and reservoir souring are important factors for corrosion-related maintenance costs in the petroleum industry.1 MIC is caused by sulfate-reducing prokaryotes (SRP), which can be Bacteria (SRB) or Archaea (SRA), with the main focus in literature being on SRB.2–5 The microorganisms most frequently reported in literature to be responsible for MIC are the SRB; Desulfovibrio, Desulfobacter, Desulfomonas, Desulfotomaculum, Desulfobacterium, Desulfobotulus, and Desulfotignum, and methanogens.2,5
The purpose of this review is to discuss environmental effects, especially hydrogen sulfide and carbon dioxide on pitting susceptibility of low alloy steels and corrosion resistant alloys.
In recent years, several novel technologies have been proposed and developed to produce energy in a clean and sustainable way. However, in the foreseen future, fossil fuel will still be the major source to meet our needs on energy.1 The combustion of fossil fuel for power and heat is always accompanied by CO2 emission, which is believed to be in large correlation to global warming.2 To control the CO2 emission and reduce the negative effects, carbon capture and storage (CCS) has been rapidly developed in fossil fuel combustion power plants.3, 4 One of the crucial parts of CCS is the longdistance transportation of CO2, during which a large amount of captured CO2 is transported to storage sites. Pipeline network is chosen as transportation system due to its high efficiency and moderate cost.5 And the transported CO2 streams are usually compressed into supercritical CO2 (s-CO2).6
To restrain the failure of plate heat exchanger in customer boiler working fluid, the effect of crevice former type on the corrosion behavior of Type 316L (UNS S31603) stainless steel plate was investigated using electrochemical methods and surface analysis in chloride-containing synthetic tap water.
Structural steel, which is a critical component of many infrastructures, can suffer from deterioration of steel by reaction with air and its pollutants known as atmospheric corrosion when exposed to theenvironment. The risks associated with corrosion of newly-built and ageing infrastructure are high and their consequences costly. The recent International Measures of Prevention, Application, andEconomics of Corrosion Technologies (IMPACT) study led by NACE International (now renamed asAMPP) has shown for Canada the estimated annual corrosion cost to be $51.9 billion, which is 2.9% of Canada’s GDP.
Environments in oil and gas industries are often characterized by high temperature and pressure, harsh chemicals, humidity, extreme stress cycles, radiation, and mechanical disturbances.1,2 These extreme conditions degrade the ability of materials to perform, thus requiring enhanced protection through application of heavy-duty anti-corrosive and chemical resistant coatings that can withstand the aggressive environment.