Hydrogen sulfide, corrosion inhibitors

It had been demonstrated [39] early on that in hydrogen sulfide corrosion the inhibitor has to be in contact with a sulfided (precorroded) surface in order to show inhibition. This observation rendered useless all those test procedures in which the inhibitor is applied to a clean metal surface in so-called film persistency tests. While it is well established that certain chemicals, such as high molecular weight fatty acids, have an affinity for metal surfaces and can form a water repellent film, they are readily replaced by other compounds that have a stronger affinity, for instance H2S. Fatty amines, on the other hand, adsorb strongly on iron sulfide, and their desorption from sulfided surfaces takes much longer them the desorption of fatty acids from bare metal surfaces in the presence of H2S. 

Hausler, R. H., Goeller, L. A., and Rosenwald, R. H., Contribution to the Mechanism of Hydrogen Sulfide Corrosion Inhibition," Proceedings of the 3rd European Symposium on Corrosion Inhibitors, Ferrara, Italy, 14-17 September 1970, p. 399. 

Uses Removing carbon dioxide and hydrogen sulfide from natural gas in emulsifiers, hair waving solutions, polishes softening agent for hides agricultural sprays pharmaceuticals, chemical intermediates corrosion inhibitor rubber accelerator nonionic detergents wool treatment. 

Corrosion inhibitor Two inhibitors could be used a. Copper corrosion inhibitor to help prevent sulfur, hydrogen sulfide, and mercaptan attack on copper b. Ferrous metal corrosion inhibitor to prevent water/oxygen initiated corrosion of iron and steel system components... 

It is rare in actual applications that only one corrosion inhibitor is used. Synergistic blends of two or more inhibitors can take advantage of the strengths of each. Table 10-1 compares the performances of several of these blends to that of a chromate-zinc blend under different operating conditions. Note that while the chromate-zinc blend offers the best corrosion inhibition with no contaminants present and at high temperatures, other blends are close, and do not present the environmental problems that chromates do. With petroleum ether, hydrogen sulfide, or hexane contaminants present in the cooling water, the Polyphosphate-HEDP-Carboxylate blend performs the best, followed by Zinc-HEDP. 

Inhibitor Blend Concentration (ppm) Corrosion Rate (mpy) Corrosion Rate (mpy) with Petroleum Ether Contaminant (40 ppm) present Corrosion Rate (mpy) with Hydrogen Sulfide (10 ppm) present Corrosion Rate (mpy) with Hexane (30 ppm) present Corrosion Rate (mpy) at High Temperature (170-180° F)... 

The produced water is a combination of water from a free-water knockout and from heater treaters. An aeration tower is used to oxidize the iron and hydrogen sulfide, and chlorine is also added to the tower. The chemical treatment utilizes 45 to 60 ppm alum, 75 ppm chlorine, and a corrosion inhibitor. The finished water quality is as follows ... 

Production of sulfides. This may involve the production of FeS, Fe (OH)2 etc. and an aggressive chemical agent such as hydrogen sulfide (H2S) or acidity. Micro-organisms may also consume chemical species that are important in corrosion reactions (e.g., oxygen or nitrite inhibitors). Alternatively, their physical presence may form a slime or poultice, which leads to differential aeration cell attack or crevice corrosion. They may also break down the desirable physical properties of lubricating oils or protective coatings. (Stott)5... 

Carbon steel is the predominant construction material for carbonate and amine solution containers. Corrosion in the overhead lines (hydrogen sulfide or carbon dioxide plus water from the regenerator) is prevented by adding corrosion inhibitors. Although amine carry-over can act as a corrosion inhibitor in the overhead line, SCC of carbon steel has occurred when amine added as a corrosion inhibitor became concentrated. Copper and copper base alloys should be avoided in amine service and are questionable in carbonate seivice. Nickel or cobalt base alloys (e.g., Monel00 400 and Inconel 600) except for Stellite01 should be avoided in carbonate service. Monel 400 should be avoided in amine service if UCC Amine Guard02 corrosion inhibitor is used. 

For cross country lines containing oil or gas, the corrosive constituents such as water, carbon dioxide, and hydrogen sulfide are usually reduced to a very low level before the fluid enters the line. The lost efficiency required to pump the unwanted constituents and the extra wall thickness required for corrosion allowance usually cannot be economically justified. Even with cleanup systems, some water will get into pipelines. In oil lines, oil soluble corrosion inhibitors usually prevent attack by water settling in low spots, etc. Gas lines are usually dehydrated to 60% of saturation to avoid corrosion from condensing water containing dissolved carbon dioxide. Molecular sieves that reduce water to 5 ppm have proved necessary in lines containing 100% carbon dioxide. 

Hoar Ci J found that in the corrosion inhibition of iron in hydrochloric acid by g-naphthoquinoline, the corrosion potential increases monotonically with increasing inhibitor concentration, while in the case of o-tolylthiourea one observes first a decrease of the corrosion potential followed by an increase at higher inhibitor concentrations. A similar predominant inhibition of the cathodic partial reaction at small inhibitor concentrations is exhibited also by phenylthiourea according to Kaesche. Furthermore, in the series of the thiourea derivatives one often finds corrosion acceleration at small concentrations, as for instance in the case of phenylthiourea at concentrations of 10- moles per liter. This appears to be due to a small cathodic decomposition of thiourea and its derivatives in the course of which hydrogen sulfide is formed. As is well known, hydrogen sulfide tends to accelerate corrosion, in particular the anodic partial reaction of dissolution of iron, which has been demonstrated independently by other authors (17). 

It is generally assumed that ions which can accelerate either or both partial reactions in a corrosion process are capable of being adsorbed on the iron surface. Thus it is known that hydrogen sulfide ions which accelerate both partial reactions of acid corrosion (although predominantly the anodic one), and formic acid molecules which catalyze the cathodic partial reaction but inhibit the anodic one, as well as commercial inhibitors which reduce both partial reactions, are in fact adsorbed on the iron surface. As a consequence the mere fact that adsorption takes place cannot be used to predict an expected change in corrosion rate as it is also known that halide ions cat-alize the anodic dissolution of indium, while hydroxyl adsorption catalyzes the anodic dissolution of iron. Furthermore, it is also known that certain ions can act either as a catalyst or an inhibitor when adsorbed on the metal surface depending on the type of metal considered. Kolotyrkin (18) observed that the adsorp-... 

In order to understand the iron sulfide-inhibitor interaction,it will be necessary to review briefly the corrosion mechanism of iron in the presence of hydrogen sulfide in a two-phase medium. 

As can be seen, pipelines suffer from both internal and external corrosion. Internal corrosion is due to presence of sulfur-bearing gases such as hydrogen sulfide, carbon dioxide, and moisture, which is entrapped as brine from the sea. The usual rule of thumb is that the internal coatings are applied only if the crude/gas is sour in nature (its hydrogen sulfide concentration is more than 500 ppm). Otherwise, the internal corrosion is usually tackled by addition of inhibitors, either continuously or in a batch process. 

As outlined above, surfactants are added to acids to perform one or more of several needed functions. However, other chemicals are also added to the acid. These additives inclnde corrosion inhibitors [IS], iron control agents [J9, 20], hydrogen sulfide scavengers [21], scale inhibitor [22] and clay stabilizers [23], It is very important to perform compatibility tests of the selected surfactant with the acid formnla, especially in this complex environment. Also, some of the snrfactants are nsed in high temperature and high salinity applications. Therefore, it is necessary to ensure thermal stability of these surfactants nnder these harsh conditions. 

Recommendations for Selecting Inhibitors for Use as Sucker Rod Thread Lubricants Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment Metallic Materials for Sucker Rod Pumps for Hydrogen Sulfide Environments Control of Internal Corrosion in Steel Pipelines and Piping Systems... 

The rate of corrosion of cast iron is directly linked to oxygen content. Carbon dioxide accelerates the formation of scales in fresh water. Cast iron and carbon steels are sensitive to attack by hydrogen sulfide even in the absence of oxygen. Corrosion rates of low carbon steels and cast iron accelerate with velocity, if the water is not treated with inhibitors. 

The Catacarb process, which was disclosed by Eickmeyer (1962), is licensed by Eickmey-er and Associates of Prairie Village, Kansas. For most applications the Catacarb process utilizes a catalyzed hot potassium carbonate solution however, potassium borate solutions are used for the removal of hydrogen sulfide in the absence of carbon dioxide (Gangriwala and Chao, 1985). The solutions contain undisclosed additives that catalyze absorption and desorption of acid gases, particularly carbon dioxide. The additives, which include a corrosion inhibitor, are claimed to have no effect on reformer or methanation catalysts that the purified gas may pass through downstream of the Catacarb absorber (Morse, 1968). 

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