Hydrogen sulfide corrosion caused

Hydrogen Sulfide HjS Cause of rotten egg odor corrosion Aeration, chlorination, highly basic anion exchange... 

One way to reduce the amount of magnesium chloride is to use a caustic injection after the desalter. The injection amount is guided by the amount of salt in the overhead condensate. Spent caustic washes can be used if they do not contain contaminants that cause increased corrosion or plugging. For example, a spent alkylation plant caustic would add sulfur dioxide, which can react with hydrogen sulfide to cause sulfur plugging. The following steps are required to avoid problems with a caustic injection system ... 

In petroleum refineries, process streams containing hydrogen also frequently contain hydrogen sulfide. This causes sulfidic corrosion. You know from experience that increasing the chromium content of a steel increases its resistance to corrosion by high-sulfur crudes. However, do not jump to the conclusion that chromium alloying always improves resistance to sulfidic corrosion. It does so if the operation is dirty, as it usually is in crude streams, or if the corrodents are elemental sulfur or sulfur compounds that do not decompose to release hydrogen sulfide. This increased resistance to sulfur corrosion depends on formation of a protective scale. With such scales, the corrosion rate is parabolic — it decreases with exposure time. 

Hydrogen sulfide can cause corrosion of stainless steels such as 316 and 410 stainless in the form of sulfide stress cracking. Copper alloys corrode rapidly in H2S. Upper limit values have been developed by the National Association of Corrosion Engineers (NACE MR-0175 2009). In the gas phase, a stream is sour if the H2S partial pressure exceeds 0.05 psia (pounds per square inch absolute). If a single phase liquid is in equilibrium with a gas phase, where the gas phase H2S partial pressure exceeds 0.05 psia, then that liquid is also considered to be sour. 

Hydrogen chloride released dissolves in water during condensation in the crude oil distillation column overhead or in the condenser, which cause corrosion of materials at these locations. The action of hydrochloric acid is favored and accelerated by the presence of hydrogen sulfide which results in the decomposition of sulfur-containing hydrocarbons this forces the refiner to inject a basic material like ammonia at the point where water condenses in the atmospheric distillation column. 

Various patents (22—24) have been issued claiming the use of tetrakis(hydroxymethyl)phosphonium sulfate in, for example, water treating, pharmaceuticals (qv), and in the oil industry where this compound shows exceptional activity toward the sulfate-reducing bacteria that are a primary cause of hydrogen sulfide formation and consequent problems associated with souring and corrosion (25). 

Many of the by-products of microbial metaboHsm, including organic acids and hydrogen sulfide, are corrosive. These materials can concentrate in the biofilm, causing accelerated metal attack. Corrosion tends to be self-limiting due to the buildup of corrosion reaction products. However, microbes can absorb some of these materials in their metaboHsm, thereby removing them from the anodic or cathodic site. The removal of reaction products, termed depolari tion stimulates further corrosion. Figure 10 shows a typical result of microbial corrosion. The surface exhibits scattered areas of localized corrosion, unrelated to flow pattern. The corrosion appears to spread in a somewhat circular pattern from the site of initial colonization. 

Both iron and aluminum are particulady troublesome because of their abiUty to act as coagulants. Also, their soluble and insoluble hydroxide forms can each cause precipitation of some water treatment chemicals, such as orthophosphate. Airborne contaminants usually consist of clay and dirt particles but can include gases such as hydrogen sulfide, which forms insoluble precipitates with many metal ions. Process leaks introduce a variety of contaminants that accelerate deposition and corrosion. 

Cracking was caused by stress-corrosion cracking (see Chap. 9, Stress-Corrosion Cracking ) involving hydrogen sulfide and/or moist sulfur dioxide. The sulfur entered the cooling water stream through process leaks, which were repaired. 

Water and sulfur compounds are the principal non-hydrocarbon impurities present in light ends which frequently require removal. The sulfur compounds of concern are concerned with here are hydrogen sulfide and mercaptans, both of which have to be removed almost quantitatively from any light ends cut which is going to be marketed. There are two reasons for this First, they have an objectionable odor, even in minute concentrations. Second, they may cause corrosion either by themselves or through their combustion products. 

Oxygen dissolved in aqueous solutions, even in very low concentrations, is a leading cause of corrosion problems (i.e., pitting) in drilling. Its presence also accelerates the corrosion rate of other corrodents such as hydrogen sulfide and carbon dioxide. Oxygen plays a dual role both as a cathodic depolarizer and an anodic polarizer or passivator. Within a certain range of concentration the... 

For the corrosion process to proceed, the corrosion cell must contain an anode, a cathode, an electrolyte and an electronic conductor. When a properly prepared and conditioned mud is used, it causes preferential oil wetting on the metal. As the metal is completely enveloped and wet by an oil environment that is electrically nonconductive, corrosion does not occur. This is because the electric circuit of the corrosion cell is interrupted by the absence of an electrolyte. Excess calcium hydroxide [Ca(OH)j] is added as it reacts with hydrogen sulfide and carbon dioxide if they are present. The protective layer of oil film on the metal is not readily removed by the oil-wet solids as the fluid circulates through the hole. 

Arctic Drilling. Corrosion problems encountered in arctic area drilling are no different from problems faced in other areas of the world. It is a general misconception that during arctic drilling corrosion-related problems are either not very severe or totally absent due to low temperatures. Cool temperatures may slow down the corrosion process. However, they also increase the solubility of oxygen, carbon dioxide and hydrogen sulfide. Therefore, the net result can be an increase in the rate of corrosion. While cold temperatures may cause problems, the temperature fluctuation common in arctic environments can be a more severe source of corrosion-related problems [215]. 

Nevertheless, as pressures increase, the steam and condensate pH levels begin to drop significantly. This pH depression is accelerated with higher BW sulfite levels. At 700 psig, with a BW sodium sulfite reserve of, say, 40 ppm, the condensate can dip to as low as pH 4.2. This ultimately produces a very corrosive situation caused by the production of sulfur dioxide gas (S02) and hydrogen sulfide gas (H2S). 

Methods used to control presumptive corrosion include deaeration and dehydration. Carbon dioxide and hydrogen sulfide are the main corrosives in pipelines for natural gas, but they are only aggressive in the presence of water. Therefore sweetening and drying the gas are useful to prevent corrosion. In oil pipelines, water emulsified in crude oil can cause corrosion problems [251]. Emulsified crude oil in separated produced water is also an environmental and disposal problem. 

Sweetening of petroleum products implies the removal of dissolved free sulfur and its compounds like hydrogen sulfide, and mercaptans in order that the product has no bad odour and does not tend to cause corrosion. The removal of these is accomplished by oxidation processes, solvent processes or catalytic desulfurization processes. 

In-sewer processes, e.g., hydrogen sulfide formation and fermentation, may cause corrosion, toxicity, and odor problems. 

As long as sulfide remains in the water phase, no harmful effect will occur. The concrete corrosion problem is caused by hydrogen sulfide that from the gas phase is absorbed in the liquid film that exists on moist concrete surfaces in the... 

Copper can be present in fuel systems in the form of heating coils, cooling coils, brass fittings, or bronze parts. Copper is quite resistant to corrosion by water but can be attacked by ammonia and sulfur compounds. Finished fuels usually do not contain ammonia unless the ammonia somehow carries over from refining process operations. Sulfur compounds such as hydrogen sulfide and possibly elemental sulfur are more frequently the cause of copper corrosion problems in fuel systems. 

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