Nace Basic Corrosion Course Book
Contents. Overview of sweetening process The process selected for sweetening a sour gas depends on the general conditions:.
NACE Basic Corrosion Course [National Association of Corrosion Engineers] on Amazon.com. *FREE* shipping on qualifying offers. This course covers a basic but thorough review of causes of corrosion and the methods by which corrosion is identified, monitored, and controlled.
H 2S and mercaptan concentration in the sour gas, and sales gas H 2S and total sulfur limits. maximum design flow rate. raw gas inlet pressure. requirement for sulfur recovery. acceptable method of waste products disposal Cost considerations The selected process must be cost effective in meeting the various specifications and requirements. Throughout the world, regulations generally limit the flaring of H 2S.
Sweetening of gas streams containing very low concentrations of H 2S can be done in many ways, depending on the general conditions. If the sour gas stream contains more than 70 to 100 pounds of sulfur/day in the form of H 2S in the inlet gas to a sour plant, a regenerative chemical solvent is usually selected for the sweetening of the sour gas stream. For very low H 2S content sour gas, a scavenger chemical is usually used. In such cases, the chemical is consumed, and the method for ultimate disposal of the spent chemical is a consideration. Typical process equipment for sweetening sour gas with a regenerative solvent A schematic drawing of typical process equipment for sweetening sour gas with regenerative solvent is shown in Fig.
The first vessel is the inlet separator, which performs the important function of separating the fluid phases on the basis of density difference between the liquid and the gas. The sour gas flows from the separator into the lower part of the absorber or contactor. This vessel usually contains 20 to 24 trays, but for small units, it could be a column containing packing.
Lean solution containing the sweetening solvent in water is pumped into the absorber near the top. As the solution flows down from tray to tray, it is in intimate contact with the sour gas as the gas flows upward through the liquid on each tray. When the gas reaches the top of the vessel, virtually all the H 2S and, depending on the solvent used, all the CO 2 have been removed from the gas stream. The gas is now sweet and meets the specifications for:. H 2S.
CO 2. total sulfur content.
1—Schematic drawing of sweetening process equipment. The rich solution leaves the contactor at the bottom and is flowed through a pressure letdown valve, allowing the pressure to drop to about 60 psig. In some major gas plants, the pressure reduction is accomplished through turbines recovering power. Upon reduction of the pressure, the rich solution is flowed into a flash drum, where most dissolved hydrocarbon gas and some acid gas flash off. The solution then flows through a heat exchanger, picking up heat from the hot, regenerated lean solution stream. The rich solution then flows into the still, where the regeneration of the solvent occurs at a pressure of about 12 to 15 psig and at the solution boiling temperature. Heat is applied from an external source, such as a steam reboiler.
The liberated acid gas and any hydrocarbon gas not flashed off in the flash drum leave the still at the top, together with some solvent and a lot of water vapor. This stream of vapors is flowed through a condenser, usually an aerial cooler, to condense the solvent and water vapors. The liquid and gas mixture is flowed into a separator, normally referred to as a reflux drum, where the acid gas is separated from the condensed liquids.
The liquids are pumped back into the top of the still as reflux. The gas stream, consisting mainly of H 2S and CO 2, is generally piped to a sulfur recovery unit.
The regenerated solution is flowed from the reboiler or the bottom of the still through the rich/lean solution heat exchanger to a surge tank. From here, the solution is pumped through a cooler to adjust the temperature to the appropriate treating temperature in the absorber. The stream is then pumped with a high-pressure pump back into the top of the absorber, to continue the sweetening of the sour gas. Most solvent systems have a means of filtering the solution. This is accomplished by flowing a portion of the lean solution through a particle filter and sometimes a carbon filter as well.
The purpose is to maintain a high degree of solution cleanliness to avoid solution foaming. Some solvent systems also have a means of removing degradation products that involves maintaining an additional reboiler for this purpose in the regeneration equipment hook-up. In some designs, the rich solution is filtered after it leaves the surge drum. Sweetening solvents The desirable characteristics of a sweetening solvent are:. Required removal of H 2S and other sulfur compounds must be achieved. Pickup of hydrocarbons must be low. Solvent vapor pressure must be low to minimize solvent losses.
Reactions between solvent and acid gases must be reversible to prevent solvent degradation. Solvent must be thermally stable. Removal of degradation products must be simple. The acid gas pickup per unit of solvent circulated must be high. Heat requirement for solvent regeneration or stripping must be low.
The solvent should be noncorrosive. The solvent should not foam in the contactor or still. Selective removal of acid gases is desirable. The solvent should be cheap and readily available. Unfortunately, there is no one solvent that has all the desirable characteristics. This makes it necessary to select the solvent that is best suited for treating the particular sour gas mixture from the various solvents that are available. The sour natural gas mixtures vary in:.
H 2S and CO 2 content and ratio. content of heavy or aromatic compounds. content of COS, CS 2, and mercaptans While most of the sour gas is sweetened with regenerative solvents, for slightly sour gas, it may be more economical to use scavenger solvents or solid agents.
In such processes, the compound reacts chemically with the H 2S and is consumed in the sweetening process, requiring the sweetening agent to be periodically replaced. Regenerative chemical solvents Most of the regenerative chemical sweetening solvents are alkanolamines, which are compounds formed by replacing one, two, or three hydrogen atoms of the ammonia molecule with radicals of other compounds to form primary, secondary, or tertiary amines respectively. Amines are weak organic bases that have been used for many years in gas treating to remove CO 2 and H 2S from natural gas as well as from synthesis gas. These compounds combine chemically with the acid gases in the contactor to form unstable salts. The salts break down under the elevated temperature and low pressure in the still. Because the chemical reactions are reversible by changing the physical conditions of temperature and pressure between absorber and still, amines are highly suitable for removing the acid gases from the hydrocarbon gas stream.
However, sometimes nonreversible reactions take place to a minor degree, forming degradation compounds. Such degradation compounds must be periodically removed by distillation. This occurs in a reclaimer vessel. Primary amines are more prone to forming degradation compounds than the other solvents. Another chemical solvent, potassium carbonate (K 2CO 3), has also been used for removing H 2S and CO 2 from manufactured or natural gas.
It is not widely accepted in the sour natural gas industry, but it is periodically mentioned in the literature as finding some application under specific conditions. This chemical solvent was originally developed by the U.S.
Bureau of Mines for removing CO 2 from manufactured gas. Table 1 lists the regenerative chemical solvents generally used for sweetening sour gas and gives the acronyms, chemical formulas, and molecular weights.
Table 1 Primary amines Monoethanolamine (MEA) MEA was the earliest amine used for sweetening sour gas. It is a stronger base than diethanolamine (DEA) and also has a higher vapor pressure than DEA; therefore, vapor losses are higher than for DEA. MEA forms nonregenerative (degradation) compounds with:. CO 2. COS.
CS 2 This is a disadvantage, as the degradation compounds must be removed periodically to lessen the corrosion rate. A reclaimer is usually incorporated in an MEA sweetening train to periodically remove the degradation products from the solution by distillation. MEA has been used for more than 60 years in process applications, and the process operation and problem areas are well understood. Solution strengths of MEA are usually in the range of 15 to 22% by weight MEA in water.
Mol loadings (moles of acid gas picked up in the contactor per mole of solvent circulated) are generally in the range of 0.25 to 0.33 moles acid gas per mol of MEA. Diglycolamine (DGA) The DGA process was developed by The Fluor Corp. In the 1950s, which called the process the Econamine Process.
The advantage of DGA over MEA appears to be the lower solution circulation rate owing to the higher solvent concentration, resulting in higher acid gas pickup per volume of solution circulated. This yields capital savings, as the regeneration equipment is smaller for DGA than for MEA. Disadvantages appear to be degradation of the chemical with CO 2 and greater solubility of heavier hydrocarbons in the solution, as compared to MEA. This is a serious drawback if the acid gas stream is fed to a Claus plant, as additional air is required for the combustion of the hydrocarbons. Also, this dilutes the sulfur compounds in the sulfur recovery train. Solution strength is on the order of 50 to 70% by weight of DGA in water, with mol loadings in the range of 0.3 to 0.4 moles of acid gas per mole of DGA circulated.
The DGA process train usually includes a reclaimer. Secondary armines Diethanolamine (DEA) DEA became a popular sour gas treating solvent in the 1960s after it was developed for such application in France. It can be used at higher concentrations than MEA. DEA has the advantage of picking up more acid gas per solution volume circulated, thus effecting some energy saving in circulation and regeneration. It does not form the nonregenerative products with COS and CS 2 as is the case with MEA, which is another advantage over MEA.
DEA is also generally less corrosive than MEA. Solution strength is usually in the 25 to 40% range, with mol loadings of 0.35 to 0.63. Diisopropanolamine (DIPA) This secondary amine is not used by itself as a sweetening solvent but is part of the Sulfinol solvent formulation. Tertiary armines Triethanolamine (TEA) TEA is not in general use for gas sweetening. Methyldiethanolamine (MDEA) MDEA reacts more slowly with CO 2 than the previously described amines.
It forms a slightly different salt with CO 2 from those of the other amines, at a lower rate of reaction. The difference in the rates of reaction with H 2S and CO 2 gives MDEA a desirable feature over other amines, namely selectivity of H 2S over CO 2. This is an attractive feature in cases where it is not necessary to remove all the CO 2 from the gas stream. By leaving some of the CO 2 in the natural gas, the circulation rate of the solution can be reduced, or the treating capacity of an existing unit can be increased with MDEA as compared with DEA.
MDEA concentrations are on the order of 30 to 50% by weight, with mol loadings of 0.40 to 0.55 moles acid gas per mol of amine. As a tertiary amine, MDEA is naturally a weaker base and is therefore less corrosive than the primary and secondary amines. The energy required for regeneration is also less than the requirement for the other amines.
Proprietary armine solvent formulations By making use of the difference in the rates of reaction between MDEA and the acid gases, several proprietary solvents have been developed that are suited for preferential extraction of H 2S, with only partial removal of CO 2. These proprietary formulations usually contain MDEA plus other amines at various concentrations in aqueous solutions to tailor them for specific applications. Several chemical companies have developed such proprietary solvents. Hot potassium carbonate (K 2CO 3) (Hot Pot) The potassium carbonate process was developed for removing CO 2 from manufactured gas. It reacts with both acid gases. Because the contacting of the sour gas occurs at very high temperatures, such as 195 to 230°F in this process, it is sometimes referred to as the “hot pot” process. It requires lower heat input for regeneration and is therefore somewhat less costly to operate than some amine processes.
Also, no heat exchanger is required in the regeneration equipment. The process has difficulty in meeting the H 2S specification of the treated gas if the H 2S/CO 2 ratio is not extremely small. This process is significant for treating gas with a large concentration of CO 2. The chemistry of the process can be enhanced by the addition of various catalysts, and this has resulted in the process being referred to by various trade names. Computer simulation of sweetening processes The design and optimization of sweetening processes can be done by computer, using programs such as HYSIM from Hyprotech of Calgary, which contains AMSIM from D.B. Robinson and Associates Ltd. Of Edmonton, Alberta; ProTreat from Optimized Gas Treating Inc.
Of Houston; TSWEET from Bryan Research and Engineering Inc. Of Bryan, Texas; and proprietary programs from the chemical supplier. Estimating solution circulation rate The circulation rate or the acid gas pickup by the solution can be estimated with the next two formulas.
The specific gravity of the amine solutions is shown in Fig. The specific gravity of potassium carbonate may be approximated by 1 + weight fraction K 2CO 3 in solution. 2—Specific gravity of aqueous armine solutions (after Engineering Data Book of Gas Processors Suppliers and Gas Processors Association).
Types of operating problems The main problems that can be encountered in the operation of sour gas treating facilities using chemical solvents are as follows:. failure to meet H 2S specification for sales gas. solution foaming in the contactor or regenerator. corrosion in pipes and vessels.
solvent losses Failure to Meet H 2S Sales-Gas Specifications. Treated gas that does not meet the H 2S specifications is not admitted into the sales-gas transmission lines. Potential causes for “going sour” are:. a change in the acid gas concentration of feed gas. a change in the feed gas temperature.
too hot lean amine solution. too low solvent concentration in solution. inadequate regeneration of solution. insufficient contact in absorber. too low amine circulation rate. too low absorber pressure. too high concentration of degradation products.
too high inlet gas rate. mechanical damage or problems in absorber. foaming Solution Foaming Solution foaming occurs when gas is mechanically entrained in liquid as bubbles.
The tendency to form bubbles increases with decreasing surface tension of the solution owing to interference of foreign substance at the surface of the solution on the tray. Foaming is thought to be caused by factors such as:. liquid hydrocarbons entering the contactor with the sour gas. acidic amine-degradation products.
treating chemicals from wells or gathering system. treating chemicals from makeup water.
compressor oil. fine solid suspensions such as iron sulfide While solids suspended in the solution by themselves might not cause foaming, it is thought that they tend to stabilize the foam. The results from foaming can be:. severe upsets in the process tower. leading to carryover and loss of chemical. possible damage to downstream process equipment or material The best way to reduce the propensity for foaming is to ensure that the sour gas entering the contactor is clean, free of condensed liquids, and that the solution is cleaned up by mechanical and carbon filtration.
The addition to the solution of antifoam agents is sometimes effective in controlling the foaming tendency of the solution. However, this does not solve the basic problem. Too much antifoam in the solution can actually add to the foaming problem.
Corrosion Corrosion is common in most amine plants. It is necessary to control the corrosion rate by the addition of corrosion inhibitor and by use of stainless steel in certain pieces of process equipment. In the case of MEA solutions, corrosion rates tend to increase with increasing solution strengths beyond about 22% MEA, as well as with high levels of amine degradation products in the solution. Most of the process piping and vessels in amine plants are built with carbon steel, meeting NACE MR0175 guidelines. It is not possible to predict with certainty where corrosive attack will take place. Experience has shown that the most likely areas for corrosive attack are those where the temperatures are high, such as in:.
the top part of the still. the reboiler tubes. the heat exchangers. some connecting piping Hydrogen blisters are sometimes evident after many years of service in the shell of the contactor or still.
Hydrogen-induced cracking can also occur in welds in the vessels or piping after many years of service. Corrosion/erosion can occur in areas where fluid velocities are high, such as:.
in the return line from the reboiler. at the point of entry of the reboiler vapors into the still. downstream of pressure letdown valves As compared with CO 2 and H 2S mixtures, corrosion rates in amine systems, especially MEA systems, generally increase with:. increasing temperature. increasing amine concentration. increasing mole loadings. pure acid gas MEA is generally much more corrosive than DEA, and MDEA is only slightly corrosive.
Use of Corrosion Inhibitors. The use of corrosion inhibitors is a common practice to reduce the attack on steel by H 2S and CO 2 in aqueous environments. In most sour gas sweetening installations, a corrosion inhibitor is continuously injected into the sweetening solution. Solvent Loss In all regenerative solvent systems, it is necessary to periodically add pure solvent to the solution because of the loss of solvent during operation. Solvent losses in gas treating systems can occur because of:. vaporization. entrainment.
degradation and removal of degradation products. mechanical losses Solvents used in gas treating, like any other liquids, have a vapor pressure that increases with temperature. In a gas sweetening system, there are three vessels where gas and liquid streams separate:. contactor. flash tank. reflux drum By far the largest gas stream is the one leaving the contactor. To reduce the solvent losses from this source, a water wash process is usually applied to the treated gas downstream of the contactor.
Solvent losses from the flash tank are usually quite small, as the amount of gas leaving this vessel is usually small when compared to the total plant stream. When the solution is regenerated in the still, some solvent leaves the still overhead with the acid gas stream and the water vapor. Upon cooling the still overhead stream and condensing most of the water and amine, the liquid is returned to the top of the still as reflux, which also recovers most of the solvent.
Nevertheless, some solvent vapor leaves the top of the reflux drum with the acid gas stream. Lower reflux drum temperatures reduce solvent losses at this point. Entrainment of solvent occurs during foaming or under high gas velocity situations. By preventing foaming and by staying within design throughput, entrainment losses can be avoided. In amine systems, some degradation of the solvent occurs.
Primary amines are most susceptible to this problem, and such systems require special separation equipment to periodically remove the degradation products that contribute to corrosion. The degradation products are mainly caused by irreversible reactions between the solvent and CO 2. The most serious losses of solvent usually result from mechanical actions or problems. These include:. filter changeouts. drips from pumps or flanges.
vessel cleaning and draining Physical solvents In addition to the chemical solvents, there are also physical solvents available for extracting the acid gases from natural gas. Physical solvents do not react chemically with acid gases but have a high physical absorptive capacity. The amount of acid gas absorbed is proportional to the partial pressure of the solute, and no upper limit, owing to saturation, is evident, as is the case with chemical solvents. Hence, they are mainly suited for sour gases with high acid gas content at high contacting pressures. The physical absorption solvents have the advantage of regeneration by flashing upon reduction of pressure and, therefore, do not require much heat in the stripping column. This makes physical solvents useful as bulk-removal processes, followed by final cleanup using a chemical solvent because physical solvents have difficulty in achieving the H 2S limit specified for sales gas.
Unfortunately, they also tend to absorb heavier hydrocarbons, which is a disadvantage if the acid gas is fed to a Claus plant for sulfur recovery. There are several physical solvents mentioned in the literature. 3 is a process schematic of a typical physical solvent process. A brief description of the more prominent physical solvent processes is discussed next. 3—Schematic drawing of physical solvent process equipment. Selexol process The Selexol process was developed by Allied Chemical Corp. The solvent is dimethyl ether of polyethylene glycol and is usually used in its pure form.
It has a preference for H 2S over CO 2, and, therefore, some CO 2 remains in the gas stream, depending on the mole loading of the solvent. Several stages of flashing are provided for in the regeneration step, to allow the absorbed hydrocarbons to evolve from the solution. The flashed gases from the initial flash stages are compressed and returned to the inlet of the absorber.
Selexol is noncorrosive and also removes water vapor from the gas stream. Fluor solvent process The solvent in this process is propylene carbonate and was developed in the late 1950s by The Fluor Corp. This solvent also has a greater affinity for H 2S than for CO 2 and also dehydrates the feed gas. Absorptive capacity is highly temperature dependent, favoring the lower temperature.
Purisol The Purisol solvent process was developed in Germany by Lurgi. The solvent used is N-methylpyrrolidone, which has a high absorptive capacity for the acid gases.
Hybrid process Sulfinol The Shell Sulfinol process is a hybrid process using a combination of a physical solvent, sulfolane, and a chemical solvent, Diisopropanolamine (DIPA) or Methyl diethanolamine MDEA. The physical solvent and one of the chemical solvents each make up about 35 to 45% of the solution with the balance being water. The sulfinol process is economically attractive for treating gases with a high partial pressure of the acid gases, and it also removes:. COS. CS 2. mercaptans Other advantages are:.
good heat economy. low losses because of low vapor pressure. absence of corrosion A disadvantage of this process is that the sulfolane absorbs heavier hydrocarbons from the gas, some of which are then contained in the acid gas feed stream to the sulfur plant. Thus, the Sulfinol process is best suited for very sour, lean gas.
Reduction/oxidation (Redox) process Nonregenerative chemical solvent (Scavenger) processes When the gas is only slightly sour, that is to say, contains only a few ppm of H 2S above the specification limit, a simpler sweetening process might have economic advantages over the typical processes described in the previous sections. These processes scavenge the H 2S from the sour gas, with the chemical being consumed in the process. It is, therefore, necessary to periodically replenish the chemical, as well as dispose of the end product of reaction containing the sulfur. Table 2 gives a summary of some common chemicals used for this purpose. The process equipment consists of a tower containing a solution of the chemical, or the chemical is in suspension in water.
The sour gas is bubbled through the solution, and the chemical reacts with the H 2S. The chemicals do not react with CO 2. Table 2 The Sulfa-scrub process development. The chemical used in this process is triazine.
The end product is beneficial as a corrosion inhibitor and is water soluble. As a result, disposal of the end product is convenient, as it is simply added to a water-disposal system.
Sulfa-scrub can be injected into the flowline at the well, and it reacts with the H 2S while the gas is flowing to the plant. Thus, there might not be a requirement for a treating tower.
Dry sweetening processes While the sweetening of sour gas is predominantly done with regenerative solvents, there are also some dry processes that can be used for this purpose. Because these processes are batch processes, two or more towers are usually used, so that one tower can be taken out of service for chemical charge replacement without interruption of gas flow. Iron sponge (Iron Oxide) Iron sponge consists of wood chips that have been impregnated with a hydrated form of iron oxide. The material is placed in a pressure vessel through which the sour gas is flowed. Because this is a batch process, usually two vessels are installed—one in service and the other on standby. The H 2S reacts with the iron oxide to form iron sulfide.
In due course, the iron oxide is consumed. While it is possible to regenerate the iron sulfide with air to restore the iron oxide, in practice this is not done. Instead, the tower containing the spent iron sponge is taken out of service, and the standby tower is placed in service. The spent iron sponge is moistened with water, removed, and disposed of at an approved disposal site, and the tower is filled with a new charge of iron sponge.
Care has to be exercised in handling the spent material in the dry state, as it is pyrophoric. When dry iron sulfide is exposed to air, a spontaneous chemical reaction between the iron sulfide and oxygen takes place—oxidizing the iron sulfide to iron oxide and emitting sulfur dioxide into the air. SulfaTreat (Iron Oxide) Several years ago, a new iron-oxide-based dry product with the trade name of SulfaTreat was introduced for sweetening sour gas.
The product is placed in towers, as illustrated in Fig. 5, through which the sour gas is flowed. The gas stream should have a superficial gas velocity of no more than 10 ft/minute, and the temperature of the gas should be between 70 and 110°F. The gas must be water saturated at the tower conditions of temperature and pressure. SulfaTreat has a different molecular structure from that of iron sponge and, upon reaction with H 2S, forms iron pyrite instead of iron sulfide. The charge of SulfaTreat is replaced when consumed. 5—Schematic drawing of typical SulfaTreat process equipment.
This process is usually installed in a two-tower configuration, as shown in Fig. The slightly sour gas is flowed through both towers in series.
The H 2S content is monitored in the gas between the two towers. When the concentration of H 2S starts to increase in this gas, it is an indication that the SulfaTreat chemical in the first tower is consumed. This tower is then temporarily bypassed, and a fresh charge of chemical is installed. The tower containing the new chemical charge becomes the second tower in the continuation of the operation. Molecular sieves Molecular sieves are crystalline compounds created from alumina silicates, with controlled and precise structures, which contain pores of uniform size. These compounds have an affinity for various molecules, especially for polar compounds such as water, H 2S, and CO 2. The pore size can be controlled during the manufacturing process and can be tailor-made for specific molecules, such as H 2S.
Molecular sieves can therefore be used for removing water from sour gas, or they can also be used for sweetening sour gas that exceeds the H 2S specification by a few ppm. The process requires two or three towers filled with molecular sieves, one of which is used for adsorption, while the others are being regenerated by the application of a hot gas stream.
Sweetening with molecular sieves is suitable for large volume, very low H 2S concentration gas. Screening program for optimum process selection The Gas Research Institute (GRI) of Chicago, now called the Gas Technology Institute (GTI), has performed large scale investigations of redox and scavenger sweetening processes. The results have been compiled in reports and papers, which are available from GTI.
Furthermore, computer screening programs have been prepared, and these are also available for a nominal fee. The two programs dealing with scavenger process selection are CalcBase™ and SeleXpert™. Information on these programs can be accessed on the GTI website, by searching for the term “H 2S scavenger.” Nomenclature AG = percent acid gas,% ML = mole loading, moles/mole MW = molecular weight, lbm/mole Q = gas flow rate, MMscf/d SG = specific gravity of solution (water = 1) W = weight percent of solvent in solution,% References. Smith, R.S. Improve Economics of Acid-Gas Treatment. Oil & Gas J 73(March): 78-79.
Tennyson, R.N. And Schaaf, R.P. Guidelines Can Help Choose Proper Process for Gas-Treating Plants. Oil & Gas J 75 (2): 78. ↑ King, J.C.
Rigorous Screening Selects Sour-Gas Plant Process. Oil & Gas J 84 (36): 101-110. Butwell, K.F., Kubek, D.J., and Sigmund, P.W. Alkanolamine Treating. Hydrocarbon Processing (March): 108. Fitzgerald, K.J.
And Richardson, J.A. New Correlations Enhance Value of Monoethanolamine Process. Oil & Gas J 64 (43): 110-118. Freireich, E. And Tennyson, R.N. Process Improves Acid Gas Removal, Trims Costs, and Reduces Effluents.
Oil & Gas J 74 (34): 130-132. Quick Design Charts For Diethanolamine Plants. Oil & Gas J 70 (January): 88. Selective Gas Treating Produces Better Claus Feeds. Oil & Gas J 78 (18): 239-242. Maddox, R.N. Hot Carbonate—Another Possibility.
Oil & Gas J (October): 167-173. ↑ Dehydration. In GPSA Engineering Data Book, 11th edition, Sec. 19, 20, and 21. Tulsa, Oklahoma: Gas Processors Suppliers Association. Abry, R.G.F.
And DuPart, M.S. Amine Plant Troubleshooting and Optimization. Hydrocarbon Processing (April): 41-50. Pauley, C.R., Hashemi, R., and Caothien, S.
Ways to Control Amine Unit Foaming Offered. Oil & Gas J 87 (50): 67-75.
DuPart, M.S., Bacon, T.R., and Edwards, D.J. Understanding Corrosion in Alkanolamine Gas Treating Plants, Part 1. Hydrocarbon Processing (April): 80. Kutsher, G.S., Smith, G.A., and Greene, P.A.
NOW—Sour-Gas Scrubbing by the Solvent Process. Oil & Gas J (March): 116. Buckingham, P.A.
Fluor Solvent Process Plants: How They Are Working. Hydrocarbon Processing (April): 113. Hydrocarbon Processing (April) 84. Sulfinol Process Has Several Key Advantages. Oil & Gas J (30 June): 117. Schaack, J.P.
H2S Scavenging, 4-part series. Oil & Gas J (23 January): 51; (30 January): 81; (20 February): 45; (27 February): 90. Dillon, E.T. Triazines Sweeten Gas Easier. Hydrocarbon Processing (December): 65.
Anerousis, J.P. And Whitman, S.K. Iron Sponge: Still a Top Option for Sour Gas Sweetening. Oil & Gas J (18 February): 71.
Samuels, A. H2S Removal System Shows Promise Over Iron Sponge. Oil & Gas J (5 February): 44. Maddox, R.N. And Burns, M.D. Solids Processes for Gas Sweetening. Oil & Gas J (17 June): 90.
Noteworthy papers in OnePetro Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read External links See also Sour gas sweetening Category.
NACE Basic Corrosion Course Basic Corrosion Course, Houston, Texas, 1970. This Basic Corrosion Course has been prepared under the direction of the National Association of Corrosion Engineers to help provide a broader program for corrosion education for its membership and the industries which have corrosion problems. The preparation of this course has been assigned to a special committee composed of former Presidents-C. Munger, Amercoat Corporation; W. Burton, Allied Chemical Corporation; E. Greco, Consultant; and Aaron Wachter, Consultant. This committee has served for two years under the Chairmanship of Professor Anton deS.
Brasunas of the University of Missouri-Rolla. They secured the services of numerous members who contributed time and effort in preparing this seventeen-chapter text on corrosion which is intended to be used by individuals throughout the world as a correspondence course. For that reason, the writing and preparation was so patterned as to maximize the clarity of the discussion and minimize the need for any additional instruction. This text is liberally illustrated to help clarify various situations and the language which was used throughout the text has been made as nonmathematical and nontechnical as possible to discuss this very technical subject in a relatively easy-to-understand manner. As corrosion technology develops and as the need for additional, new, and more detailed information becomes necessary, will then consider the preparation of a more advanced text, as well as preparing up-to-date and supplementary data for this basic course. NACE gratefully acknowledges the assistance of the various authors and editorial committee who helped make this course possible and we trust that their arduous efforts will be amply rewarded by the realization that this course will be of considerable benefit to the nation, to numerous industries, and to individuals all over the world who will take advantage of the opportunity afforded them by this educational effort. Anton deS.
Brasunas, Editor, Basic Corrosion Course October, 1970 Chapter 1 - The and Language of Corrosion By Anton deS. Brasunas and Norman E. Hamner When a study of corrosion is undertaken, it may be natural to think that corrosion is a simple single reaction and that when understood, it can be turned off like a spigot. If cost and availability were not factors, we could select the very best materials and come close to doing just that. But let us dismiss consideration of materials like gold or platinum and think in terms of practical substances that we can afford to use in our homes, industries, automobiles, etc. Practical materials like iron and steel, aluminum and copper alloys, plastics, ceramics, wood, refractory metals, stainless steels and many other modern alloys and superalloys, all have certain advantages as well as disadvantages.
A selection of one of these alloys or classes of alloy can be a 'best choice' for a certain application. Learning when to choose which, comes with experience and knowledge. This is a part of what we hope you can learn from this course. Chapter 2 - By Ordinarily, people become engaged in controlling or preventing corrosion by appointment rather than as the final step in a process of formal education having this as its original goal.
This course is designed to be helpful to that segment of such a group entering this field without the benefit of any extensive training in the basic sciences related to corrosion, but who may be called upon from time to time to take at least the first steps in anticipating, diagnosing and otherwise dealing with corrosion problems, either on their own or in collaboration with others. Economic Importance While corrosion processes form an interesting basis for scientific studies which are frequently undertaken as exercises in chemistry, and particularly electrochemistry, by far the greatest interest in, and concern for corrosion stems from its practical effects and how they may be avoided. Various estimates have been made of the annual economic loss resulting from corrosion. There is no general agreement as to just what should be included in calculating this loss, for example, should we include the coating on tin cans which would not be needed if the contents were not corrosive to steel. It is, therefore, fruitless to argue about the figure that should be used. However, there is ample evidence that annual losses attributable to corrosion in North America amount to several billions of dollars and, depending on what is included in the estimate, could well surpass the $10 billion figure that has been suggested.
Chapter 3 - Corrosion-Related and Electrochemistry By N. Greene Corrosion as a Chemical Reaction Although at first sight the corrosion of metals may appear to be a rather complex process, the general reaction can be readily understood by considering elementary chemical principles. Almost all of these have been discussed in your high school chemistry courses and therefore their application to the phenomenon of corrosion should be relatively simple. In this chapter, the principles of chemistry and chemical reactions important to the understanding of corrosion are discussed.
Since space limitations prevent a complete review of basic chemistry, it is suggested that if necessary, a high school chemistry text or review book be utilized for additional study purposes. Chapter 4 - Corrosion By Kenneth G. Compton Corrosion in the atmosphere usually occupies a minor position in the writings of scientists and corrosion engineers dealing with the basic subject. The corrosion phenomena in chemical plants, underground structures and, to a lesser degree, in sea water or at elevated temperatures seem to offer more glamour and to be more spectacular. Actually, most of the destructive damage to equipment and structures caused by corrosion occurs in the atmosphere. The large segment of the vast paint industry concerned with the manufacture and application of its products for the protection of metals and the large scale operations of the galvanizing industry attest to the -importance of controlling atmospheric corrosion.
Most of the broad forms of corrosion occur in the atmosphere and some appear to be largely restricted to it. Since the corroding metal is not bathed in large quantities of electrolyte, most atmospheric corrosion operates in highly localized corrosion cells.
Calculation of the electrode potentials on the basis of ion concentration, the determination of polarization characteristics and other electrochemical operations are not possible as contrasted to the situation in liquid immersion types of corrosion. Yet, all of the electrochemical factors significant in corrosion processes operate in the atmosphere, so their comprehension is vital to an understanding of its operation. Chapter 5 - Principles of Protection by A. Peabody The purpose of this chapter is to introduce the student to cathodic protection, one of the widely used 'tools' for the control of electrochemical corrosion throughout industry. After a brief description of the meaning of cathodic protection and how it works, the balance of the chapter will consist of a discussion of the practical aspects of cathodic protection systems as well as various factors that may influence cathodic protection designs. As a first step, it is necessary to agree on a definition for 'cathodic protection' so that a basis will be established on which can be built a better knowledge of the manner in which it functions and of its practical use. Cathodic protection is defined as: Reduction or elimination of corrosion by making the metal a cathode by means of an impressed direct current or attachment to a sacrificial anode (usually magnesium, aluminum, or zinc).
A cathode is the electrode where reduction (and practically no corrosion) occurs. Prior to applying cathodic protection, most corroding structures will have both cathodic areas and anodic areas (those areas where corrosion is occurring, see glossary). It follows, then, that if all anodic areas can be converted to cathodic areas, the entire structure will become a cathode and corrosion will be eliminated. The second step is to show how application of direct current electricity to a corroding metallic structure can cause it to become a cathode throughout its area. To begin with, direct current electricity is associated with the corrosion process on a buried or submerged metallic structure. Chapter 6 - Corrosion by By Marshall E.
As was mentioned in previous chapters, various metals have varying tendencies to corrode as illustrated by their relative positions on the Galvanic or Emf Series. Since this chapter will center largely around iron, it is well to note that iron is intermediate in these lists. Furthermore, it has been shown that pure iron, wrought iron, or mild steel behave just about the same in underground situations. It has been observed that iron pipe buried in bone dry soil suffers little or no corrosion.
However, because of rain, natural springs, rivers, etc. Soils are rarely dry, especially beneath the surface, so we must consider real cases. Even if we considered the simple case of moisture from natural rain, we would soon be dealing with the complex solutions similar to well water, river water, etc.
All soils contain a variety of mineral matter, some of which is soluble to a greater or lesser degree and we must deal with these 'solutions'. Had there been no minerals to dissolve in rainwater, corrosion by soils would be almost nil. Iron in pure water does not corrode, but when there is oxygen dissolved in it the situation is very different.
Furthermore, when other substances dissolve in it the situation becomes even more complex. An explanation of corrosion behavior under a variety of conditions is not easy to give, but one important factor is the electrical conductivity of the medium which surrounds the metal being corroded.
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Pure water is a very poor electrical conductor but as substances dissolve in it, particularly those which ionize, conductivity rises sharply. As it will be seen later, the relationship between conductivity and corrosion is a very logical one. Chapter 7 - Corrosion by and Steam By Warren E. Berry A major use of water in industry is the transfer of heat and the production of steam. There is extensive use of cooling water in almost every manufacturing process, in commercial air conditioning, and even a fair percentage of domestic air conditioning. Fossil and nuclear-fueled steam plants and attendant steam generation dominate the power generating field.
Water is corrosive to most metals. Pure water without dissolved gases (as O 2, CO 2, SO 2) in it does not cause undue corrosion attack of most metals and alloys at temperatures up to the boiling point of water.
Even at temperatures of about 850 F (450 C) almost all the common structural metals, except the light metals aluminum and magnesium, possess adequate corrosion resistance to highpurity water and steam. Naturally-occurring or man-made contaminants make water corrosive. The most significant of these contaminants is oxygen from the air that is dissolved in the water. As described in Chapter 3, oxygen is a cathodic depolarizer that reacts with and removes reaction products from the cathode during electrochemical corrosion, thereby permitting the attack to continue. Other contaminants that are often found in water and which contribute to corrosion include chloride salts (usually sodium chloride-common table salt) from the sea, wells, or industrial sources; sulfides from wells, mining wastes, or sewage; and carbon dioxide from combustion-products in the air or certain water treatment practices. Of course, many other man-made contaminants can be found in local areas where industries discharge their wastes into streams.
This chapter will discuss the corrosion problems associated with natural and treated waters at temperatures ranging from room temperature up to 1000 to 1100 F (540 to 600 C); the means of preventing or slowing down corrosion; and the best choice of materials for each environment. Chapter 8 - Corrosion By Hugh P. Godard Localized corrosion can be defined as selective removal of metal by corrosion at small special areas or zones on a metal surface in contact with a liquid environment. Note that this discussion is limited to corrosion in liquids, whereas pitting and other forms of localized corrosion can also occur in other environments. It usually occurs under conditions where the largest part of the original surface either is not attacked or is attacked to a much smaller degree than at the local sites. The most common type of localized corrosion is pitting, in which small volumes of metal are removed by corrosion from certain areas on the surface to produce craters or pits. Pitting corrosion may occur on a metal surface in a stagnant or slow moving liquid.
It also may be caused by crevice corrosion, poultice corrosion, deposition corrosion, cavitation, impingement and fretting corrosion. Another common type is intergranular corrosion (sometimes called 'intercrystalline corrosion'). In this form, a small volume of metal is preferentially removed along paths that follow the grain boundaries to produce what might appear to be fissures or cracks. The same kind of subsurface fissures can be produced by transgranular corrosion (sometimes called 'transcrystalline corrosion'). In this, a small volume of metal is removed in preferential paths that proceed across or through the grains. This occurs only under certain conditions and with certain alloys. Intergranular and transgranular corrosion sometimes are accelerated by tensile stress.
In extreme cases, the cracks proceed entirely through the metal, causing rupture or perforation. This condition is known as 'stress corrosion cracking', a subject that will be dealt with in Chapter 10.
Intergranular and transgranular subsurface cracks also can be produced by hydrogen. Caustic embrittlement and corrosion fatigue are two other mechanisms of metal deterioration which form fissures at or beneath the surface.
In a completely different type of corrosion which may become localized one of the metals in an alloy may be selectively leached out without producing visible pits or cracks, and without changing the dimensions of the metal. At a casual glance the metal may appear to be intact. Under a microscope it can be seen to be porous.
The mechanical properties of the alloy are greatly reduced by the selective attack. The most common example of this type is dezincification of brass in which the zinc is selectively dissolved out of the alloy. Another case is 'graphitic corrosion' of cast iron, in which the iron is selectively dissolved or leached away leaving a porous mass apparently intact but in reality consisting largely of graphite. Chapter 9 - Fundamentals of By Norman Hackerman and E.
Snavely Definition of Corrosion Inhibitor An inhibitor is a substance which retards or slows down a chemical reaction. Thus, a corrosion inhibitor is a substance which, when added to an environment, decreases the rate of attack by the environment on a metal. Corrosion inhibitors are commonly added in small amounts to acids, cooling waters, steam and other environments, either continuously or intermittently to prevent serious corrosion. It would be awkward to include mechanisms of inhibition in the definition of a corrosion inhibitor because inhibition is accomplished by one or more of several mechanisms. Some inhibitors retard corrosion by adsorption to form an invisibly thin film only a few molecules thick; others form visible bulky precipitates which coat the metal and protect it from attack.
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Another common mechanism consists of causing the metal to corrode in such a way that a combination of adsorption and corrosion product forms a passive layer. We also include in the definition those substances which, when added to an environment, retard corrosion but do not interact directly with the metal surface. This type of inhibitor causes conditions in the environment to be more favorable for the formation of protective precipitates or it removes an aggressive constituent from the environment. Presentation The use of corrosion inhibitors has grown to be one of the foremost methods of combating corrosion. To use them effectively, the corrosion engineer must, first of all, be able to identify those problems which can be solved by the use of corrosion inhibitors.
Second, he must consider the economics involved, viz., whether or not the loss due to corrosion exceeds the cost of inhibitor and maintenance and operation of the attendant injection system. Third, he must consider the compatibility of inhibitors with his process to avoid adverse effects such as foaming, decreases in catalytic activity, degradation of another material, loss of heat transfer, etc. Finally, he must apply the inhibitor under conditions which produce maximum effect. This chapter on inhibitor fundamentals was written with the above tasks in mind. Corrosion inhibitors are discussed from four points of view:.
Their effects on the corrosion process,. Their interactions with various aggressive environments,. Properties of the inhibitors themselves, and. Possible effects of inhibitors on unit operations. Chapter 10 - Corrosion By Hugh L. Logan Mechanical forces, that is, tensile or compressive forces, will have little if any effect on the overall corrosion of metals as measured for example in mils per year corrosion penetration. However, a combination of tensile stresses and a corrosive environment is one of the most important causes of failures of metal structures.
This type of attack is properly known as 'stress corrosion cracking.' It is defined as the spontaneous failure of metals as the result of the combined action of a corrosive environment and tensile stresses, either applied or residual. In brass it has been called 'season cracking' and in low-carbon steels, 'caustic embrittlement.'
It is a fairly common cause of failure in most common alloys and has even been reported as a cause of the cracking of a gold ring found buried in the soil. Stress corrosion cracking was first extensively studied in small arms brass cartridge cases. Explosions in riveted steam boilers were believed to be triggered by stress corrosion cracking called caustic embrittlement because of caustic deposits found adjacent to the cracks. Construction of steel boilers by welding rather than riveting has reduced but by no means eliminated this type of failure. The development of numerous stress corrosion cracks in welded steel structures used in producing gas (by coal distillation) was reported in England. Recently in the United States, the failure of a large interstate natural gas pipeline was attributed to stress corrosion cracking.
Leaks that develop in stainless steel heat exchangers and other stainless steel equipment used in the petrochemical industries are believed to be due generally to stress corrosion cracking. Even titanium alloys, considered to be highly inert to general corrosion, will fail by stress corrosion cracking when stressed and in contact with sea salt above 550 F (290 C) and under some conditions in contact with dilute chlorides, wood alcohol or some other materials at room temperature. The foregoing paragraphs may suggest, and it is fortunately true, that only a limited number of corrodents will produce stress corrosion cracking in a given material. Table 10-1 gives a brief list of corrodents that are known to have produced stress corrosion cracking in the more common alloys.
Chapter 11 - Factors Affecting Corrosion By R. Hochman Since metals are the principal material suffering corrosive deterioration, it is important to develop a background in the principles of metallurgy to fully understand corrosion. General Characteristics of Metals Nearly all metals and alloys exhibit a crystalline structure. The atoms which make up a crystal exist in an orderly three dimensional array. There are solid materials, principally glass, that exist in an amorphous state.
However, only crystals have the unique condition in which atoms are geometrically and uniformly arranged in all three dimensions. The unit cell is the smallest portion of the crystal structure which contains all talc, geometric characteristics of the crystal. It can be considered the smallest building block of the crystal. The crystals, or grains, of a metal are made up of these unit cells repeated in a three dimensional array. The crystalline nature of metals is not readily obvious because the metal surface usually conforms to the shape in which it has been cast or formed. Therefore the crystalline nature of metals is difficult to understand since the usual concept of a crystal is a geometrically shaped object. In some rare instances, this crystallinity can be observed naturally, i.e., brass door knobs are normally bright and shiny, however, after a time, the corrosive perspiration from hands etches the crystalline features of the alloy on the surface.
Metal crystals may be precipitated in the cold zones of liquid metal systems due to mass transfer phenomena. Controlled etching with selected electrolytes will normally show the granular characteristics of metals and alloys. Chapter 12 - Corrosion at Temperatures By John J. Moran The behavior of materials at elevated temperatures is becoming of increasing technological importance, yet, it is a problem man has had to face and solve from the very beginnings of his existence. Understanding the behavior of metals at elevated temperatures and especially their corrosion behavior has only comparatively recently become an object of scientific investigation. Techniques for studying reactions at high temperatures had to be developed. It is obviously difficult to observe the actual reaction between gases and metals at high temperatures and watch the reaction products build up.
It is easier to measure the change in weight after some interval or even to measure the weight change continuously during the test. But these techniques are fairly recent developments.
Formerly, one could only observe the appearance of the scale after the test was concluded and examine it carefully after it had cooled. How it had changed, how it actually had appeared at any given temperature was the subject of much speculation but little accurate evidence was available.
And, as has subsequently become clear, the appearance of a scale after cooling to room temperature may be different from the same scale at a high temperature. Many scales which are continuous and thus protective at a given temperature will flake off or spall upon cooling and hence create a misleading impression of their effectiveness during continuous service.
It is not surprising, therefore, that the first quantitative approach to oxidation behavior was made in the early nineteen twenties with the postulation of the parabolic rate theory of oxidation by Tammann and, independently, by Pilling and Bedworth,2 nor that a more formal treatment of the problem would be delayed another decade, until the middle nineteen thirties, when Wagner' presented his theory of oxidation. Modifications and alternative theories continue to appear and presumably will continue to appear for a considerable time, because there are still many gaps in the theory; particularly in its application to practical problems and service experience involving complex systems.
In the following discussion we shall consider first the behavior of pure metals when exposed to oxidizing conditions at elevated temperatures and secondly the modifying effect of alloying additions upon the performance of the base metals. At least qualitatively the correlation with theory will be shown. In this fashion it is hoped that an appreciation of the important factors controlling oxidation behavior will be gained so that later when more complex alloys exposed to more complicated corrosive environments than air or oxygen are considered, it will be evident what characteristics of the alloy and the environment are likely to affect behavior. Finally the principles developed from the study of high temperature corrosion by air or oxygen will be applied to the behavior of alloys exposed to other high temperature corrosive gaseous media. Some effort will be devoted also to the effect of nongaseous contamination on high temperature corrosion behavior and to the problems of fused salt and liquid metal corrosion. Chapter 13 - Alloy at High Temperatures Anton deS.
Brasunas Factors that affect corrosion under a variety of conditions and the possible means commonly employed for its control have been discussed at length in earlier chapters. Considerable attention has been given to the corrosion of various alloys in water, chemical solutions and in underground or concrete structures. Relatively little attention is ordinarily given to corrosion by gases, especially very hot gases. In Chapter Four, the subject of corrosion by the atmosphere was discussed and in Chapter Twelve, some of the principles of high temperature corrosion were presented.
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In this chapter, we will take a more detailed look at the behavior of engineering alloys at elevated temperatures in several different commonly-encountered environments, namely, air and flue gas atmospheres as well as in low pressure gases, vacuum and molten metals and salts. Brief attention will be given also to mechanical properties at high temperatures. Although the temperatures above approximately two or three hundred degrees F are sometimes considered 'high temperature', this chapter will be concerned primarily with temperatures in the 'red hot range' primarily from 1200 degrees Fahrenheit and up (above 650 C).
A major portion of this chapter will be devoted to high temperature corrosion of heat resistant alloys and the effects of alloying elements, but some attention also will be given to the effects of high temperatures on mechanical properties and structural instability. Chapter 14 - for Corrosion Protection By N.E. Hamner The concept of placing a protective barrier between materials and their environment is so ancient that its origin is lost in the mist of history. As can be expected with a concept so old, its materials, methods and qualifications are numerous and diverse. Furthermore, some. Uses of a barrier, while originally satisfactory, are now obsolete or obsolescent in the light of new discoveries about the properties of matter and because the merits of individual components of barrier systems are better understood now.
There are three main kinds or compositions of barriers: Inert or essentially inert, inhibitive and sacrificial. Various combinations of these types are found in coatings systems designed to use some or all of the several protective advantages provided. It must be remembered, however, there is no such thing as a 'perfect' coating in a practical sense so none of these types or any combination can be expected to give perfect protection. The properties of materials being what they are, none are so inherently stable that they will permanently resist attacks by the environment. Thus, practical coatings are a compromise between the maximum protection that can be extracted from a system and how much is available to pay for them. With respect to economics it probably would be as expensive to achieve a 'perfect' coating as it is to make anything else perfect.
As the effective life of a coating system increases, its cost usually increases also. From another aspect, coatings protect by one or more of the following mechanisms:. Prevent contact between the environment and the substrate. Restrict contact between the environment and the substrate. Release substances which are inhibitive of attack by the environment on the substrate. Produce an electrical current which is protective of the substrate.
The effectiveness of a coating system is directly related to the degree to which it effectively interposes itself between the environment and the substrate or reduces attack by the environment. This concept applies equally well to both cathodic and anodic (electrical) protection, both of which in an absolute sense are coatings in that they interpose barriers between the environment and the substrate.'
In a similar way, such methods as peening2 to produce compressively stressed surface material resistant to attack also are coatings in an electrochemical sense. Chapter 15 - Corrosion By Frank L. McGeary and Bernard W. Lifka The Value of Corrosion Testing The corrosion of metals is governed by fundamental laws.
As we understand these laws better, we become better able to predict the performance of a particular metal, how it reacts under a given set of conditions and how its performance can be improved. At present, however, it is necessary to develop experimentally most of the information we need about corrosion of metals.
Metals are used under countless and changing conditions so that the unexpected is not uncommon. It is because of this limited predictability of metal performance that corrosion tests are so important. Properly conducted, corrosion tests can mean the savings of millions of dollars. They are the means by which we can avoid using a metal under unsuitable conditions or of using a more expensive material than is required. Corrosion tests also help in the development of new alloys that perform more inexpensively, efficiently, longer, or more safely than the alloys now in use. Also, quality control corrosion tests are a means of ensuring that the alloys we make and purchase have the capabilities expected of them. Scope of this Chapter Because of the large number of metals, alloys and applications, it is impossible to cover all phases of corrosion testing in this chapter.
The intent, therefore, is to cover the fundamentals of testing commonly used for metals and to develop guidelines for proper test methods. Because this is an elementary corrosion course, emphasis is given to those responsibilities frequently assigned to a laboratory technician. Corrosion testing programs can be simple ones which are completed in a few minutes or hours, or they can be complex and require the combined work of a number of investigators over a period of years. This discussion on corrosion testing is intended for high school graduate technicians as well as engineers who may be new to the field.
The trained technician is vital to a corrosion testing program. Engineers and scientists who devise and supervise the programs are liable to promotion and transfer. Consequently, the well trained technician becomes a means for maintaining the 'continuum of quality' through a long testing program. Most industrial laboratories offer a variety of employment and growth opportunities for technicians whose specialized training and skills make them indispensable. Types of Corrosion Tests Corrosion tests are in two broad categories:.
Tests made in the laboratory under controlled conditions; and. Tests made in the 'field' under natural or service conditions. Chapter 16 - for Corrosive Environments By and J.H. Peacock A large variety of materials, ranging from platinum to concrete, is used by the engineer to construct bridges, automobiles, process plant equipment, pipelines, power plants, etc. The corrosion engineer is primarily interested in the chemical properties (corrosion resistance) of materials, but he must have knowledge of mechanical, physical, and other properties to assure desired performance.
The properties of engineering materials depend upon their physical structure and basic chemical composition. Mechanical Properties These properties are related to behavior under load or stress in tension, compression, or shear. Properties are determined by engineering tests under appropriate conditions. Commonly determined mechanical properties are tensile strength, yield point, elastic limit, creep strength, stress rupture, fatigue, elongation (ductility), impact strength (toughness and brittleness), hardness and modulus of elasticity (ratio of stress to elastic strainrigidity). Strain may be elastic (present only during stressing) or plastic (permanent) deformation. These properties are helpful in determining whether or not a part can be produced in the desired shape and also resist the mechanical forces anticipated.
Other Properties The corrosion engineer is often required to consider one or more properties in addition to corrosion resistance and strength when selecting a material. These include density or specific gravity (needed to calculate corrosion rates); fluidity or castability; formability; thermal, electrical, optical, acoustical, magnetic properties; and resistance to atomic radiation. For example, a particular part must be castable into an intricate shape, possess good heat-transfer characteristics, and not be degraded by atomic radiation. In another case, the equipment must be a good insulator, reflect heat and have low unit weight. Incidentally, radiation sometimes enhances properties of a material, e.g.
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The strength of polyethylene can be increased by controlled radiation. Cost is not a property of a material, but it may be the overriding factor in selection of a material for engineering use, based on economic considerations and therefore should always be kept in mind.
Chapter 17 - Analysis and Correction of Corrosion By Ellis D. This final chapter of the NACE Basic Corrosion Course integrates information presented in earlier chapters and shows how these data can be used to analyze and improve conditions that will minimize corrosion failures and improve the useful life of many materials that must be exposed to a 'hostile environment.' What Constitutes Failure? The dictionary defines failure as 'a falling short, a deficiency or lack, an inability to perform, '.
For the corrosion engineer, the term 'failure' is defined in terms of how well a material fulfills all aspects of the functional requirements of the application for which it was selected. It is not enough, however, merely to provide functional capability.
The best choice is the material which fulfills the required function most economically, taking into account initial cost, maintenance costs, reliability, return on invested capital, product quality, need for inhibitors, product degradation, product loss, unscheduled shutdowns, etc. A few examples will illustrate the consequences of failures in materials selection. Product Degradation The, Naval Stores industry, located mainly in the southeastern and south-central parts of the United States, has an interesting materials selection problem. The raw material for this industry is pine gum collected from long-leaf yellow or slash pine trees, or extracted from pine stumps. Typical products of this industry include rosin, turpentine, dipentene, etc. These products are not especially corrosive to mild steel although the cleansing action ofturpentine and some of the processing solvents can make steel more vulnerable to atmospheric attack.
The real problem is catalytic degradation of the product from contact with metals. Rosin is priced on the basis of its paleness in color. The paler it is, the higher the price it commands. If small metal cups of copper, steel, aluminum and stainless steel were placed on a table and each was filled with molten rosin, in a matter of minutes. The rosin in the copper and the mild steel cups would turn black whereas the rosin in the aluminum and the stainless steel cups would remain pale amber in color.
As a consequence, the materials used for construction of. Process equipment, storage and shipment of Naval Stores are usually either aluminum or stainless steel alloys despite their.initial, cost premium over steel.
The textile and paper industries also are concerned with color of their finished products. Since the corrosion, products of many metals are highly colored, care must be, exercised in selection of materials to be used in contact with the finished products. Mills of this type generally are highly automated so accidental product contamination may, go, unnoticed until the finished product reaches a customer's plant. For example, undesirable rust spots were discovered on paper stock being processed at a paper specialities plant. Careful investigation revealed that a steel electrical conduit passed above the paper machine in the paper mill. Corrosion of the steel in the humid paper mill environment permitted iron corrosion products to fall and contaminate the paper.
Edible products also must be protected from degradation. Vegetable oils tend to become rancid in contact with some materials. Copper base alloys have significantly undesirable effects on edible oils.
Accordingly, such products normally are handled in nickel, stainless steels, plastics, or aluminum vessels. Corrosion of certain metals introduces toxic reaction products into process streams. So, for this reason, in the concentration of sap in the maple sugar making process, use of lead equipment or lead-base solder for fabrication of steel equipment is forbidden. Similarly, lead alloys are forbidden in the processing of edible gelatin. Excessive Maintenance Cost The cost of maintaining plant and equipment is an operating expense which directly reduces profit.
Therefore, any reduction in maintenance expense would appear desirable from a profit standpoint. When taxes are taken into consideration, however, an economic decision must be made as to whether it is better from an overall profitability standpoint to maintain and protect a lower price material (as an expense) or invest in higher cost capital equipment. Because company managements will appraise recommendations of corrosion engineers in the light of overall profitability, a working knowledge of engineering economy by corrosion engineers is strongly urged. Such knowledge will help define just what is 'excessive maintenance cost.' A typical example of a decision based on maintenance costs is given.
In soda-ash plants, exposure to sodium chloride, calcium chloride, high humidity, etc., produces an environment spectacularly corrosive to unprotected steel. It is almost useless to try to maintain protective coatings on steel grating-type stair treads because pedestrian traffic damages the coatings, permitting corrosion to undermine them and expose additional metal to attack. As a consequence because of their higher degree of corrosion resistance, aluminum stair treads are commonly employed in soda-ash plants.
Care must be exercised, however, to avoid galvanic action between the aluminum tread and steel structural members. Unscheduled Shutdowns It is good practice to plan periodic shutdowns of process equipment for inspection and maintenance purposes. This permits orderly repair and reconditioning without disruption of operations or inconvenience to customers. Unfortunately, emergencies sometimes arise requiring unscheduled shutdowns.
Consider the example of a large central station steam-power plant which was forced to shut down a unit because of excessive leakage of condenser tubes. Power plants are committed to supply power on a continuous basis at a fixed price to a large cross-section of domestic and industrial customers.
Loss of the use of a major power unit forces the power company to purchase power from other power companies in order to supply their customers. They usually must pay a premium price of the order of $10-15,000 per day or even more for this 'back-up' power. In addition, replacing condenser tubes in a large unit on an emergency basis can become alarmingly expensive. A modern surface condenser may require upwards of 150 miles of tubing. Rarely will such a large quantity be in inventory for immediate shipment.
Therefore, additional delays may be involved for manufacture of tubes. After tubing has been received, another 2 to 3 weeks will be required for installation and testing. The unscheduled shutdown of a chemical plant or refinery may involve disruption of activities not only at the plant where failure occurs, but also may interrupt operations of several other plants which depend on the first plant for their supply of raw materials. As a consequence, it sometimes is considered necessary to provide large storage capacity for certain products as a hedge against disruption of operations during an unscheduled shut down.
It is clear that unscheduled shutdowns and fear of them (which results in investment in duplicate facilities for stand by) represent an immense expense to industry, and there is justification for considerable effort to avoid them.