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The incidence and proliferation of microbial population in oil and gas production facilities can have undesirable consequences on upstream, midstream and downstream production systems. Microbes thrive in the anaerobic conditions encountered in these systems and are supported by nutrients and metabolites found in produced water. Although the majority of process and water injection systems are susceptible to microbial fouling, the development of microbial activity is exacerbated by specific conditions such as stagnant fluids or the presence of deposits.1 Threats of microbiologically influenced corrosion (MIC) and other challenges associated with microorganisms have become valid as more cases are reported. While MIC, biofouling (BF), and reservoir souring are three of the most common problems associated with microbes, many other production issues can be attributable to microbial activity including: employee infections, filter plugging, loss of injectivity, and metal sulfide deposits.2
Microbiological risk evaluation of topside systems of four floating production storage and offloading in West Africa was carried out over a period of four years. Field samples were taken, and DNA analyzed using next-generation sequencing technology to identify and classify the microbial population present on the facilities. Several classes of bacteria and archaea were sequenced and identified from the samples, including those that have been shown to play key roles in biofouling, microbiologically influenced corrosion and biogenic hydrogen sulphide generation in oil and gas production systems. The classic microbial population according to metabolic classes associated with oil and gas production systems were identified. The study found that of the 137 microbial genera identified, 45.3% were associated with biofouling, 29.9% with microbiologically influenced corrosion, 29.1% with a H2S/MIC risk and a 2.9% population did not have a clear link to any of these risks. There was at least 98% relative abundance of bacteria population in the samples from all FPSOs, implying a significant exposure to the risks posed by microbial growth and proliferation.
This paper will provide recent corrosion data for stored chemicals. Duplex stainless steel corrosion curves obtained in nitric, sulfuric, phosphoric acids as well as several kinds of waters will be provided. In addition, atmospheric corrosion data obtained after 15+ years of sample exposures in several geographic areas will be shown. These results will be compared to those obtained with other materials commonly used for the construction of storage tanks.
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Copper alloys such as copper nickel (CuNi) and Admiralty Brass (CuZn) are often successful material selections for seawater coolers. The copper alloys successes in these highly corrosive environments can be attributes to the ability of copper to form a protective scale, thus stopping corrosion of the material. On copper alloys in seawater, the protective scale formed comprises a mix of cuprous oxide (Cu2O), copper oxide (CuO) and copper hydroxy chlorides.
Many industrial processes contain H2, CO, CO2, and H2O gas mixtures, such as syngas production and processing in hydrogen, ammonia, and methanol plants. These process environments have high carbon activity, i.e. ac > 1, and low oxygen partial pressure at their elevated operating temperatures, such as in the temperature range of 400-800 °C (752-1472 °F). The high carbon activity could result in a catastrophic material degradation, i.e. metal dusting. The resulting corrosion products consist of carbon or graphite and metal particles, along with possible carbides and oxides, and cause material disintegration.