Per NACE-SP0775,4 the monitoring time is changeable depending on the intended fluid to which the coupon is exposed and the expected specific pipeline corrosion rate. Moreover, corrosion topography and surface morphology, depth of formed pits, electrolyte chemical composition, and the chemistry of sediments and corrosion products are also helpful for identifying and interpreting the system corrosivity.5-6
The NACE SP0775 standard covers preparation, installation, analysis, and interpretation of corrosion coupons in oilfield operations. Section 3.4 discusses the locations of coupons and other monitoring tools, and consideration of the most proper ones for coupons: dead fluid regions, high-velocity streams and impingement areas, downstream from points prone to possible oxygen entry, and locations where water is likely to collect in a sour system.
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This article is the result of several years of experience in the field of corrosion monitoring using corrosion coupons and corrosion probes, and discusses the most proper positioning of access fittings, and consequently, more intelligent monitoring of the corrosion control system. Certainly, the selection of suitable positions for access fitting installation will be enabled to gather more vital information regarding the governing process conditions and possible process upsets. Employing the presented items and utilizing the obtained data could enable one to improve interpretations, maintenance, and monitoring of the system. Hopefully, the discussions presented here will be considered by the NACE SP0775 editorial committee in the future.
One of the methods used for the secondary exploitation of oil deposits is the water injection. The injected water is obtained after the separation of the well extracted fluid that contains a mixture of crude oil, water, gases and solid particles. Prior to injection, water must meet the following requirements: a high degree of purity obtained thought the lowest possible mechanical and oil content; lower degree of aggressiveness (corrosion); the highest stability; compatibility with the fluids and minerals in the reservoir formation; low oxygen content and bacteria. The fulfilment of these requirements must be ensured by the water treatment plant whose equipment is subjected to corrosion wear. The equipment degradation are occurring mainly at pipelines and connecting elements of the flotation skid, in the form of advanced corrosion wear because the water injection contains an inconsistent composition mixture of dissolved gases, hydrocarbons, solid particles. The paper presents the regression analyses that emphasize the influence of chemical water composition and fluid speed on the corrosion rate of the different equipment parts. The corrosion rates were obtained using metallic samples according with the NACE SP0775-2013 standard that were placed in different points of the plant. The paper results can be used both at the water plant exploitation and also to next studies concerning the effectiveness of the corrosion inhibition on the corrosion rate.
The trend analysis is categorized corrosion rates as per NACE standard RP-0775/99. Based on the data recorded by our site team, our team of experts advise Oil and Gas companies on preventive maintenance and chemical/inhibitor dosing in pipelines.
The main problem in cooling water systems in geothermal power plant units is supported by corrosion, deposits, and slime. Corrosion can shorten the life of cooling water system equipment due to a decrease in operating efficiency, leakage, and pollution. These problems, occur very complex and many causes. On the other hand, most cooling water systems in the industry contain carbon steel components that are easily corroded. To determine the value of the corrosion rate of carbon steel in a geothermal power plant, a simulation test using an open recirculating system was carried out. The simulation process is done by an interval test method and based on NACE RP0775 standard. The corrosion rate of those steel was determined by weight loss method. The Morphology of surface and composition of corrosion products are characterized using scanning electron microscopy (SEM), X-ray diffractometer (XRD) and energy dispersive spectroscopy (EDS). The corrosion rate values of carbon steel from the simulation results for 1, 3 and 4 weeks were 2.29 mmpy; 1.23 mmpy; and 0.93 mmpy, respectively. There is a decrease in the corrosion rate of the simulation time is extended, because of passive film layers on the steel surface. Meanwhile, the most dominant water parameters in this simulation are dissolved oxygen (DO). The change of DO greatly affect the corrosion rate of carbon steel. Based on the product morphology of corrosion, corrosion attacks occur locally. Corrosion products form oxide compounds in the form of Fe3O4, FeOOH, and Fe2O3.
Carbon steel was exposed to isolated bacteria for 7 days to characterise their corrosive behaviour under anaerobic conditions. Surface profilometry analysis (Fig. 3) showed that in the presence of bacterial isolates except for CCC-IOB3 (P. balearica), the metal surface exhibited greater deterioration compared to the abiotic control. The weight loss in each coupon after exposure to abiotic and biotic conditions is shown in Table S3. The corrosion rate and pitting rate calculated from the weight loss and maximum pitting depth, respectively, measured for each isolate are shown in Fig. 4. Most of the isolates significantly increased the corrosion rates and pitting rates of carbon steel coupons as compared to abiotic control (Table S4). The corrosion rates triggered by the isolated bacteria showed distinct trends among species. Isolates such as CCC-APB3 (C. sakazakii), CCC-APB5 (S. chilikensis), and CCC-SPP14 (E. roggenkampii) induced higher general corrosion rates than pitting rates. In contrast, the isolates CCC-APB1 (E. cloacae), CCC-SPP15 (P. mobilis), CCC-IOB1 (P. aeruginosa), CCC-IOB9 (C. youngae), CCC-IOB10 (P. stutzeri) induced higher pitting rates than general corrosion rates. Different to all other isolates, carbon steel exposure to CCC-IOB3 (P. balearica) resulted in corrosion inhibition. Optical microscopy revealed that after 7 days of carbon steel exposure to P. balearica, the metal surface was completely covered by a biofilm layer. Instead, for the other isolates, carbon steel was covered by patchy biofilms (Fig. S1). The corrosion rates influenced by the isolated bacteria were classified from low to severe (Table S5), according to NACE SP0775 standard44. be457b7860
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