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The design packages are being optimized for the construction of gas transmission lines associated with nine (9) Gas Compression Plants (GCPs) and six (6) Liquid Separation Stations (LSSs). The objective of this study was to assess the service corrosivity of all gas transmission lines associated with these GCPs and LSSs. The results of the study will assist in selecting a cost-effective and efficient corrosion management program in terms of both materials and corrosion control options. To address this objective, the study involved conducting laboratory tests simulating the conditions in these lines. Three types of corrosion attacks were investigated, namely, general corrosion, pitting corrosion, and gas phase corrosion.
The purpose of this laboratory study was to assess the corrosivity of fluids transported through a huge network of gas transmission lines associated with nine (9) Gas Compression Plants (GCPs) and six (6) Liquid Separation Stations (LSSs). The CO2 content ranges from 0.94 mol% to 3.9 mol%, while the H 2 S content varies from 0 to 1.9 mol%. The lines range in diameter from 20 to 36 inches. The highest gas flow rate in these lines is 757 MMscfd, and the highest estimated temperature and pressure are 140°F (60°C) and 1050 psig (72 bar), respectively. The study consisted of three parts: 1) uniform corrosion in liquid and gas phases; 2) pitting corrosion in liquid and gas phases; and 3) gas phase corrosion. The absence of dissolved solids and bacteria eliminated the need to study for scaling and microbiolog icallyinfluencedcorrosion (MIC). The study was conducted using a rotating cage assembly with low alloy carbon steel test coupons and distilled water with 0, 150, and 1000 mg/L chloride.
Corrosion under thermal insulations namely CUI (Corrosion under insulation) is among the key damage mechanisms which poses integrity risk to the hydrocarbon facilities. CUI is reportedly known as the reason behind 40-60% of failures in the facility piping whereas small bore piping (i.e., NPS < 4”) are even more sensitive to CUI failures, where up to 81% of reported failures in small-sized piping are known to be from CUI. Monetary spending to inspect and fix CUI-related failures cost 10% of overall maintenance budget in a typical medium-sized oil refinery. CUI risk is influenced by numerous operational and environmental factors which impedes its management in a typical AIM (Asset integrity management) program.
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The high temperature and chemical composition of the geothermal fluid results in corrosion damage of drilling equipment, well casing and other components made of steel and iron alloys used in geothermal power production. This corrosive nature of the geothermal environment decreases the service life and increases the need for maintenance of geothermal power plants and geothermal wells. The main reasons for the corrosion of components are hydrogen sulfide (H2S) and carbon dioxide (CO2) present in geothermal system.
External corrosion in uninsulated pipelines is normally able to be prevented by cathodic protection (CP). Generally, external corrosion on buried pipelines cannot occur if CP current is getting onto the pipe. CP is an electrochemical means of corrosion control in which the oxidation reaction in a galvanic cell is concentrated at the anode and suppresses corrosion of the cathode (pipe) in the same cell. For instance, to make a pipeline a cathode, an anode is attached to it.