Acid corrosion

One important feature of Fig. 8.6 is the condensate drum balance line. Note, that this line is connected below the channel head pass partition baffle. This ensures that the pressure in the channel head, below the pass partition baffle, and the pressure in the condensate drum, are the same. If these two pressures are not identical, then the level in the condensate drum cannot represent the level in the channel head. For this reason, never connect the condensate drum vapor space to either the steam supply line or the top vent of the reboiler s channel head. 

Steam produced from demineralized water is free of carbonates. Steam produced from lime-softened water will be contaminated with carbonates that decompose in the boiler to carbon dioxide. As the steam condenses in a reboiler, the C02 accumulates as a noncondensable gas. This gas will be trapped mainly below the channel head pass partition baffle shown in Fig. 8.6. As the concentration of C02 increases, the C02 will be forced to dissolve in the water  

That is, carbonic acid, will be formed. Carbonic acid is quite corrosive to carbon steel. Reboiler tube leaks, associated with steam-side corrosion, are almost certainly due to carbonic acid attack. 

Venting the channel head through the balance line shown in Fig. 8.6 will prevent an excessive accumulation of C02. This is done by continuous venting from the top of the condensate drum. For every 10,000 lb/h of steam flow, vent off 50 lb/h of vapor through a restriction orifice, placed in the condensate drum vent. This is usually cheaper than controlling reboiler steam-side corrosion, with neutralizing chemicals. 

Varying the steam-to-condensate interface level to control the reboiler duty will promote steam leaks in the channel head-to-shell flanged closure. This is caused by the thermal cycling and stresses that result from constantly varying the level of condensate in the channel head. However, when low-pressure steam ( 60 psig) is used, this becomes a minor problem, which may be safely ignored. 

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A first operation on the crude, desalting (washing by water and caustic), extracts salts (NaCl, KCl and the MgCb that is cdn eft4rdJt6 NaCl by the caustic), reduces acid corrosion as well as it minimizes fouling and deposits. /... 

AH corrosion inhibitors in use as of this writing are oil-soluble surfactants (qv) which consist of a hydrophobic hydrocarbon backbone and a hydrophilic functional group. Oil-soluble surfactant-type additives were first used in 1946 by the Sinclair Oil Co. (38). Most corrosion inhibitors are carboxyhc acids (qv), amines, or amine salts (39), depending on the types of water bottoms encountered in the whole distribution system. The wrong choice of inhibitors can lead to unwanted reactions. Eor instance, use of an acidic corrosion inhibitor when the water bottoms are caustic can result in the formation of insoluble salts that can plug filters in the distribution system or in customers vehicles. Because these additives form a strongly adsorbed impervious film at the metal Hquid interface, low Hquid concentrations are usually adequate. Concentrations typically range up to 5 ppm. In many situations, pipeline companies add their own corrosion inhibitors on top of that added by refiners. 

Naphthenic acid corrosion has been a problem ia petroleum-refining operations siace the early 1900s. Naphthenic acid corrosion data have been reported for various materials of constmction (16), and correlations have been found relating corrosion rates to temperature and total acid number (17). Refineries processing highly naphthenic cmdes must use steel alloys 316 stainless steel [11107-04-3] is the material of choice. Conversely, naphthenic acid derivatives find use as corrosion inhibitors ia oil-weU and petroleum refinery appHcations. 

Acid corrosion presents a problem in isopropyl alcohol factories. Steel (qv) is a satisfactory material of constmction for tanks, lines, and columns where concentrated (>65 wt%) acid and moderate (<60° C) temperatures are employed. For dilute acid and higher temperatures, however, stainless steel, tantalum, HasteUoy, and the like are required for corrosion resistance and to ensure product purity (65). 

Whereas sulfamic acid is a relatively strong acid, corrosion rates are low in comparison to other acids (Table 3). The low corrosion rate can be further reduced by addition of corrosion inhibitors (see Corrosion and corrosion control). 

Materials of Construction. Resistance of alloys to concentrated sulfuric acid corrosion iacreases with increasing chromium, molybdenum, copper, and siUcon content. The corrosiveness of sulfuric acid solutions is highly dependent on concentration, temperature, acid velocity, and acid impurities. An excellent summary is available (114). Good general discussions of materials of constmction used ia modem sulfuric acid plants may be found ia References 115 and 116. More detailed discussions are also available (117—121). For nickel-containing alloys Reference 122 is appropriate. An excellent compilation of the relatively scarce Hterature data on corrosion of alloys ia Hquid sulfur trioxide and oleum may be found ia Reference 122. 

The connection box cooler receives regenerator flue gas after it has been reduced to essentially atmospheric pressure. This arrangement is not limited to the production of saturated steam. Any number of coils can be installed in the box, and normally both steam-generating and superheater coils are present. The tube temperatures within the box must be maintained above the SO dew point of 150—175°C to prevent sulfuric acid corrosion (63). 

A more obvious energy loss is the heat to the stack flue gases. The sensible heat losses can be minimized by reduced total air flow, ie, low excess air operation. Flue gas losses are also minimized by lowering the discharge temperature via increased heat recovery in economizers, air preheaters, etc. When fuels containing sulfur are burned, the final exit flue gas temperature is usually not permitted to go below about 100°C because of severe problems relating to sulfuric acid corrosion. Special economizers having Teflon-coated tubes permit lower temperatures but are not commonly used. 

See Chap. 3, Tuberculation Chap. 7, Acid Corrosion and Chap. 16, Galvanic Corrosion. ... 

Surfaces beneath affected tubercles often have a striated contour due to increased acidity (see Fig. 3.24). Striated surfaces are caused by preferential attack along microstructural and microcompositional irregularities that have been elongated during steel rolling (see Chap. 7, Acid Corrosion ). 

However, the peculiar attack morphology of a deep, localized area of corrosion surrounded by lightly etched areas was not characteristic of acid corrosion. 

Many factors influence acid corrosion. Metallurgy, temperature, water turbulence, surface geometry, dissolved oxygen concentration, metal-ion concentration, surface fouling, corrosion-product formation, chemical treatment, and, of course, the kind of acid (oxidizing or nonoxidizing, strong or weak) may markedly alter corrosion. 

Acidic attack on stainless steels differs from corrosion on nonsteunless steels in two important respects. First, nonoxidizing acid corrosion is usually more severe in deaerated solutions second, oxidizing acids attack stainless steel far less strongly than carbon steel. Hence, nitric acid solutions at low temperatures cause only superficial damage, but hydrochloric acid causes truly catastrophic damage. 

TABLE 7.1 Effect of Dissolved Oxygen on Corrosion of Mild Steel in Acids Corrosion Rate (inyy)... 

Dissolved oxygen, water, acid, and metal-ion concentrations can have a pronounced effect on acid corrosion. For example, copper is vigorously attacked by acetic acid at low temperatures at temperatures above boiling, no attack occurs because no dissolved oxygen is present. 

Acid corrosion is often caused by an upset, or it occurs intermittently. Consequently, periods of attack may be separated by intervals of virtually no acid corrosion. 

Stopping acid corrosion requires the following prevention and emergency action steps ... 

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