Carbon dioxide corrosion caused

To prepare gas for evacuation it is necessary to separate the gas and liquid phases and extract or inhibit any components in the gas which are likely to cause pipeline corrosion or blockage. Components which can cause difficulties are water vapour (corrosion, hydrates), heavy hydrocarbons (2-phase flow or wax deposition in pipelines), and contaminants such as carbon dioxide (corrosion) and hydrogen sulphide (corrosion, toxicity). In the case of associated gas, if there is no gas market, gas may have to be flared or re-injected. If significant volumes of associated gas are available it may be worthwhile to extract natural gas liquids (NGLs) before flaring or reinjection. Gas may also have to be treated for gas lifting or for use as a fuel. 

Carbon dioxide dissolves in water to form a weak acid (carbonic acid), which reduces the pH of the solution and, consequently, increases its corrosivity. Corrosion caused by carbon dioxide is generally referred to as sweet corrosion, and results in pitting. The mechanism of carbon dioxide corrosion is as follows [197,198] ... 

Materials of construction for ammonia are dependent on the operating temperature. Whilst mild steel may be used at ambient temperature, special costly steels are required at low temperatures to avoid embrittlement. Impurities in liquid ammonia such as air or carbon dioxide can cause stress corrosion cracking of mild steel. Ammonia is highly corrosive towards copper and zinc. Rubber lined steel construction is suitable for service at ambient temperature. 

Carbon dioxide CO2 Causes corrosion in water fines, particularly steam and condensate fines Aeration, deaeration, membrane contactors, neutralisation with alkalies... 

Corrosion service Carbon dioxide (CO2) or hydrogen sulphide (H2S) in formation tluids will cause rapid corrosion of standard carbon steel and special steel may be required... 

If produced gas contains water vapour it may have to be dried (dehydrated). Water condensation in the process facilities can lead to hydrate formation and may cause corrosion (pipelines are particularly vulnerable) in the presence of carbon dioxide and hydrogen sulphide. Hydrates are formed by physical bonding between water and the lighter components in natural gas. They can plug pipes and process equipment. Charts such as the one below are available to predict when hydrate formation may become a problem. 

The most common contaminants in produced gas are carbon dioxide (COj) and hydrogen sulphide (HjS). Both can combine with free water to cause corrosion and H2S is extremely toxic even in very small amounts (less than 0.01% volume can be fatal if inhaled). Because of the equipment required, extraction is performed onshore whenever possible, and providing gas is dehydrated, most pipeline corrosion problems can be avoided. However, if third party pipelines are used it may be necessary to perform some extraction on site prior to evacuation to meet pipeline owner specifications. Extraction of CO2 and H2S is normally performed by absorption in contact towers like those used for dehydration, though other solvents are used instead of glycol. 

Final Purification. Oxygen containing compounds (CO, CO2, H2O) poison the ammonia synthesis catalyst and must be effectively removed or converted to inert species before entering the synthesis loop. Additionally, the presence of carbon dioxide in the synthesis gas can lead to the formation of ammonium carbamate, which can cause fouHng and stress-corrosion cracking in the compressor. Most plants use methanation to convert carbon oxides to methane. Cryogenic processes that are suitable for purification of synthesis gas have also been developed. 

Corrosion was caused by carbonic acid. A film of condensed moisture and dissolved carbon dioxide formed the acid. The erosion was caused by high-velocity movement of air across the tubes. Attack occurred intermittently. Deepest metal loss was 33% of the 0.040 in. (0.10 cm) wall thickness. 

The carbon dioxide produced can contribute to the corrosion of metal. The deposits of ferric hydroxide that precipitate on the metal surface may produce oxygen concentration cells, causing corrosion under the deposits. Gallionalla and Crenothrix are two examples of iron-oxidizing bacteria. 

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]. 

Carbon dioxide, from the decomposition in the boiler of temporary hardness salts present in some waters, causes corrosion of steel steam pipework and cast iron valves and traps. Corrosion inhibitors may be used, but the choice of inhibitor must take into account the other materials in the system. Neutralizing amines such as morpholine or cyclohexylamine are commonly used. 

Condensate returns lines are often copper. Copper has good corrosion resistance to oxygen and carbon dioxide individually. When both gases are present in the condensate, copper is susceptible to corrosion. Copper picked up in the condensate system and returned to the boiler causes serious corrosion problems in the boiler and any steel feedwater and steam pipework. Boiler tubes should last for 25 years but can fail within one year in a mismanaged or ill-designed boiler system suffering from these faults. 

With insufficient carbon dioxide of type 3 (and none of type 4) the water will be supersaturated with calcium carbonate and a slight increase in pH (at the local cathodes) will tend to cause its precipitation. If the deposit is continuous and adherent the metal surface may become isolated from the water and hence protected from corrosion. If type 4 carbon dioxide is present there can be no deposition of calcium carbonate and old deposits will be dissolved there cannot therefore be any protection by calcium carbonate scale. 

Water which is used for cooling purposes in refineries and chemical plant can cause severe problems of corrosion and erosion. Ordinary cast irons usually fail in this type of environment due to graphitic corrosion or corrosion/ erosion. Ni-Resist irons however show better corrosion resistance, due to the nobility of the austenitic matrix, and are preferred for use in the more aggressive environments such as those containing appreciable amounts of carbon dioxide or polluted with chemical wastes or sea-water. 

Sulphates, silicates, carbonates, colloids and certain organic compounds act as inhibitors if evenly distributed, and sodium silicate has been used as such in certain media. Nitrates tend to promote corrosion, especially in acid soil waters, due to cathodic de-polarisation and to the formation of soluble nitrates. Alkaline soils can cause serious corrosion with the formation of alkali plumbites which decompose to give (red) lead monoxide. Organic acids and carbon dioxide from rotting vegetable matter or manure also have a strong corrosive action. This is probably the explanation of phenol corrosion , which is not caused by phenol, but thought to be caused by decomposition of jute or hessian in applied protective layers. ... 

Calcium hydroxide leached from incompletely cured concrete causes serious corrosion of lead (see Section 9.3). This is because carbon dioxide reacts with the lime solution to form calcium carbonate, which is practically insoluble. Carbonate ions are therefore not available to form a passive film on the surface of the lead . Typically, thick layers of PbO are formed, which may show seasonal rings of litharge (tetragonal PbO) and massicot (orthorhombic PbO) . 

Higher acidity caused greater corrosion but contamination by sulphur dioxide or carbon dioxide inhibited attack. By contrast, chloride ions were found to have a mild aggressive effect. 

The effect of pH on the corrosion of zinc has already been mentioned (p. 4.170). In the range of pH values from 5 -5 to 12, zinc is quite stable, and since most natural waters come within this range little difficulty is encountered in respect of pH. The pH does, however, affect the scale-forming properties of hard water (see Section 2.3 for a discussion of the Langelier index). If the pH is below the value at which the water is in equilibrium with calcium carbonate, the calcium carbonate will tend to dissolve rather than form a scale. The same effect is produced in the presence of considerable amounts of carbon dioxide, which also favours the dissolution of calcium carbonate. In addition, it is important to note that small amounts of metallic impurities (particularly copper) in the water can cause quite severe corrosion, and as little as 0-05 p.p.m. of copper in a domestic water system can be a source of considerable trouble with galvanised tanks and pipes. 

Both iron- and copper-based alloys are corroded more easily on either side of the neutral pH band. In low pH conditions e.g. due to carbon dioxide, the acidic environments attack the alloys readily, causing damage both at the points of initial corrosion and perhaps, consequentially, further along the system, by screening the surface with corrosion products and permitting the development of differential aeration cells. 

To remove oxygen, carbon dioxide, and other noncondensable gases from the condensate to maintain the necessary vacuum and to minimize the potential corrosion problems that these gases can cause in the condensate return system. 

The formation of a passive film of iron oxide (magnetite, Fe304), under sulfite or hydrazine reducing conditions, is optimized at pH of 11 to 12. The downside is that the decomposition of carbonates and bicarbonates produces carbon dioxide, the primary cause of condensate system corrosion. 

In practice, the potential causes of boiler section corrosion are many and often commonplace. Initiators include oxygen, carbon dioxide, acid, caustic, copper plating, chelant, and even the water itself. In addition, mechanical problems may be an initiator of corrosion, which in turn may lead to boiler mechanical failure. 

Corrosion of condensate lines is a serious problem. It is compounded where both oxygen and carbon dioxide are present because it causes considerable quantities of hematite (Fe203) to develop. Corrosion of other boiler plant components, such as FW heaters, adds more metals to the mix, and corrosion debris typically includes iron, copper, nickel, zinc, and chromium oxides. 

With carbon dioxide in the solid state the mixture detonates on impact. Therefore, with graphite, carbon dioxide cannot be used as an extinguishing agent for potassium fires. The slow reaction of potassium with gaseous carbon dioxide at ambient temperature gave rise to an accident. Potassium was stored in an aluminium container in a laboratory in contact with carbon dioxide the formation of potassium carbonate caused the corrosion of the container, which caused potassium to combust on contact with air. 

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. 

Having removed the suspended solids and dissolved salts, the water then needs to have the dissolved gases removed, principally, oxygen and carbon dioxide, which would otherwise cause corrosion in the steam boiler. The usual method to achieve this is deaeration, which removes dissolved gases by raising the water temperature1,2. 

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