GB1589932A - Corrosion inhibiting compositions for use in gas scrubbing solutions - Google Patents

Description

(54) CORROSION INHIBITING COMPOSITIONS FOR USE IN GAS SCRUBBING SOLUTIONS (71) We, THE DOW CHEMICAL COMPANY, a corporation organised and existing under the laws of the State of Delaware, United States of America, of Midland, County of Midland, State of Michigan, United States of America, do hereby declare the invention, for which we pray that a patent may be granted to us, and the method by which it is to be performed, to be particularly described in and by the following statement: The present invention relates to corrosion inhibiting compositions and, in particular, to corrosion inhibiting compositions for ferrous metals.

The conditioning (sweetening) of gases, natural and synthetic, i.e., the removal of acidic gases such as CO2, H2S and COS, by absorption in a liquid absorbent medium, has been practiced commercially for many years. Various absorbents, such as the alkanolamines, "sulfolane" (tetra-hydrothiophene- 1,1-dioxide), "sulfinol" (tetrahydrothiophene- 1,1dioxide plus diisopropanolamine) and potassium carbonate have been used commercially.

Each of these systems is plagued by corrosion problems, some of which result from decomposition of the absorbent, some from reaction between the acidic components of the gases treated and the absorbent, and commonly, from attack by the acidic components of the gases treated upon the metals of construction of the equipment. Generally, the corrosion occurs in the regenerator, heat exchangers, or in pumps and piping associated with these elements of the gas treating units.

Numerous compounds have been suggested as additives to the absorbents to prevent the corrosion and/or the formation of corrosive elements. For example, copper sulfate was used for three years in a 15 percent monoethanolamine gas processing plant for removing 10 percent CO2 from the gas. Corrosion was observed as a decrease in reboiler and heat exchange tube life and on analysis of the amine solution, only a few parts per million copper was found thus indicating excessive copper deposition in the unit. (Gas Conditioning Fact Book, The Dow Chemical Company, Midland, Michigan, 1962, pp. 157-158, Case Number 8).

United States Patent No 1,989,004 teaches the use of ethanolamine or a mixture of ethanolamines in a concentration of 15 to 30 percent in water and not more than about 1 percent of a metal e.g. copper or nickel in the form of a soluble salt e.g. sulfate, oxide or hydroxide. It does not disclose maintaining sulfur, that is, elemental or the necessary sulfur compounds and oxidizing agents to produce sulfur atoms. H2S and organic sulfur compounds are absorbed from the gas using the complexing activity of each of the components, viz., the amine, the amine-metal complex and the metal. These complexes are nonthermally treated in two steps to release the amine for reuse and convert the sulfur to a solid for removal from the system.

In this patent the spent solution (aqueous alkanolamine containing the amine-sulfur compound complex and the amine-metal sulfur compound complex) is treated not with heat to regenerate but with air (page 1, column 2, lines 20-38) to oxidize the sulfur compounds (thiosulfates) and sulfates, then the oxidized solution is treated with lime to precipitate the sulfur as calcium sulfate and thiosulfates. It is well known that the alkanolamine also undergoes oxidation and that aeration increases the loss of alkanolamine, as is evidenced by the fact that the 15 to 30 percent amine solution used in Example II (page 2, column 1, lines 49-56) after regeneration constituted only a 10 to 13 percent amine solution, a loss of about 30 percent of the original amine.

In recent years, both natural and synthetic gases are being produced which contain high concentrations of CO2 and/or H2S. As the demand for neutral gases increases, the size of the units for treating these gases increases, thus for economic reasons, an increase in the concentration of absorbent in the system and/or an increase in the loading on the system seems desirable. Both of these increases, although most desirable, increase the corrosion in the unit, resulting in more frequent repair and replacement of major elements.

We have now therefore developed an inhibitor system for use in equipment in contact with acid-gas environments, which reduces the corrosion of the metals of construction of the equipment used under the conditions.

Accordingly, the present invention provides a corrosion inhibiting composition for ferrous metal and its alloys when in contact with acid-gas stripping absorbent solutions prepared from absorbents selected from (a) one or more alkanolamines having the formula:

wherein Rl and R2 each independently a hydrogen atom, or a -C(R3)2C(R3)2-OH group and R3 is a hydrogen atom or a C13 alkyl group, (b) tetrahydrothiophene-1 ,1-dioxide, (c) potassium carbonate and (d) diglycolamine (2-(2-aminoethoxy)ethanol, either alone or as a mixture of two or more thereof as aqueous solutions or glycol solutions, the inhibiting composition consisting essentially of: (e) a source of copper ions which is copper metal, copper oxide, copper sulfide, copper hydroxide or a copper salt, and (f) a source of sulfur atoms which is 1) sulfur, or 2) a sulfur generating compound in combination with an oxidizing agent which will produce sulfur atoms in solution, at least some of which is present as the polysulfide, under the conditions of operation in the acid-gas stripping plant which employs thermal regeneration techniques for separating the combined acid-gas from the stripping absorbent, and an absorbent for (e) and (f) which is (a), (b), (c) or (d), or a mixture of two or more thereof.

The present invention also provides a ferrous metal corrosion inhibiting composition consisting of: (a) copper as copper metal, copper oxide, copper sulfide, copper hydroxide or a copper salt; and (b) an oxidizing agent which, in the presence of sulfur or a sulfur generating compound, will convert sulfur to sulfur atoms and/or oxidize copper to copper ions, and an alkanolamine of the formula:

wherein Rl and R2 are each independently a hydrogen atom, or a -C(R3)2C(R3)2-OH group and R3 is a hydrogen atom or a C13 alkyl group.

The present invention also provides a corrosion inhibiting acid-gas absorbing composition consisting of an absorbent selected from (a) an alkanolamine having the formula:

wherein R, and R2 are each independently a hydrogen atom, or a -C(R3)2C(R3)2-OH group and R2 is a hydrogen atom or a C13 alkyl group, (b) tetrahydrothiophene-1,1dioxide, (c) potassium carbonate, or (d) diglycolamine (2-(2-aminoethoxy)ethanol), either alone or as a mixture of two or more thereof as aqueous solution containing from 1 to 500 ppm copper and 1 to 5000 ppm sulfur, bdth based on the weight of the absorbent.

The present invention also provides a method for removing acid-gases from natural and synthetic gases containing them by contacting the acid-gas containing gases with a gas absorbing solution prepared from an absorbent selected from (a) an alkanolamine having the formula:

wherein R1 and R2 are each independently a hydrogen atom, or a -C(R3)2C(R3)2-OH group and R3 is a hydrogen atom or a C13 alkyl group, (b) tetrahydrothiophene-1,1dioxide, (c) potassium carbonate or (d) diglycolamine (2-(2-aminoethoxy)ethanol) either alone or as a mixture of two or more thereof as aqueous solutions or glycol solutions, the gas absorbing solution containing therein a composition as claimed in any one of claims 1 to 11, thereby to reduce the corrosive attack of the acid-gases on the metallic components of the equipment in which the acid-gas removal and the regeneration of the gas absorbing solution is carried out.

The present invention also provides a method for inhibiting the corrosion of metals in contact with a circulating absorbent medium, which is used for the removal of acid-gases from natural or synthetic gas streams wherein the circulating, rich absorbent is heated in order to release the acid-gases, the resulting lean absorbent is contacted with the acid-gas containing gas stream, and wherein the absorbent medium contains a product derived by reacting a monoalkanolamine at a temperature of from 21"C to 100"C with sulfur or a sulfur compound and an oxidizing agent, together with copper metal or a copper salt, sulfide, hydroxide or oxide, for from 0.1 to 20 hours, until the resulting mixture is stable when diluted with water, the sulfur or sulfur compound being present, based on sulfur, in a ratio of from 3 to 30 parts by weight per part of copper; and, in an amount of from 1 to 40 percent by weight of the total composition, the product being added to the absorbent medium in an amount which maintains at least 0.00002 pound of copper and 0.00002 pound of sulfur per pound of absorbent medium per day.

The quantity of copper ions necessary to reduce corrosion will vary with each plant and may vary from day to day in a particular plant. Therefore, the practical manner for determining the proper quantity of copper ions is to place in the equipment at places where the most severe corrosion occurs, generally in the reboiler and cross-exchangers to the reboiler, a metal coupon which can be examined periodically for signs of bright copper plate and corrosion. Such a control design will be explained and described in detail in the examples. Further, when the inhibitor composition of the present invention is first put into use in a gas-treating unit, a larger quantity of copper must be supplied since much is consumed in removing the corrosive elements and corrosion products at the sites corrosion has or is likely to develop. Once a degree of passivation to corrosion has been obtained, it has been found that as little as about 15 parts of inhibitor per million parts of absorbent solution will maintain a corrosion rate of less than 1 mil/yr. (0.025 mm./yr.). It is to be understood that in most instances where initially high concentrations of inhibitor are required it is common for the inhibitor to eventually passivate the unit by removing the innocuous components and thus enable reduction of inhibitor to more conventional quantities, i.e., in some instances even as low as 1 to 10 ppm. However, even in those instances where corrosion is only slightly reduced, stoppages due to corrosion are minimized and even eliminated between normal plant shutdowns.

Copper (metal, oxide, sulfide, hydroxide or salt) is used to provide copper ions in situ under the conditions found in a gas treating or conditioning process using thermal regeneration. Sulfur or a sulfur yielding compound produces sulfur atoms and preferably polysulfide moieties under the conditions of operation (particularly thermal regeneration).

The copper ions form a copper polysulfide with the copper atoms and polysulfide moieties:

where y is an integer of from 2 to 6 and n is an integer of from 2 to about 50. The copper polysulfide is available to react from solution with the Fe++ in solution to form a chalcopyrite, i.e. CuFeS2 at the surface of the vessel or heat exchanger. The Fe++ is the primary product of the cathodic corrosion reaction. Further in some instances, the copper will be reduced to copper atoms which alloy with the ferrous metal below the chalcopyrite surface layer and form a copper-ferrous alloy. These phenomena provide an effective physical and electrical barrier to the corrosive environment (the alkanolamine, alkanolamine decomposition products, H2S, CO2, Cu+2, So, Fe+3 and O2); that is, the chalcopyrite acts as a kinetic barrier to the corrosion reactions by hindering the electron and mass transport required to support the anodic and cathodic-corrosion half reactions.

The phenomenon is, of course, based on theoretical concepts supported by the results of surface analysis of the ferrous surfaces of both passivated and corroded surfaces using depth profiling, Auger spectroscopy and the electron microprobe.

The copper ions are conveniently introduced into the absorbent medium both during and after the initial period as a solution of, or by dissolution in, said absorbent. There is employed a sufficient amount of one of the following to maintain the equivalent of 1 to 15 or more parts of copper per million parts of absorbent medium: I copper metal when accompanied by sulfur, or an oxidizing agent which will produce sulfur from the H2S dissolved in said absorbent; II copper sulfide (either cupric or cuprous); III a copper salt (cupric or cuprous) in combination with an oxidizing agent, and if little or no H2S or COS is present in the acid gas, then sulfur or a sulfur-generating compound. The copper salts may be, among others, cupric or cuprous carbonate, benzoate, stearate, acetate, acetylacetonate, chloride, oxalate, molybdate, chro mate, perchlorate, sulfate or tetrafluoroborate.

It is to be understood that the quantity of inhibitor in the circulating system may be, and frequently is, greater than that dissolved in the absorbent. Such a condition will occur during the initial stages of introduction of the inhibitor to a plant, or at any upset of the plant or on start-up after any scheduled or unscheduled shut down. During these periods, the inhibitor is reacting with the metal of the plant, passivating the sites of corrosion, and reacting with corrosion products to passivate these products; thus, the inhibitor is being consumed. Therefore, the inhibitor components must be present to replace those consumed. And where the solubility of one or more of the components is limited, an excess of that component or components must be present to enable reaction and/or dissolution in order to effectively inhibit corrosion. It has been found that initially as much as 500 to 2000 ppm inhibitor must be present to passivate a plant on start-up in order to obtain satisfactory readings on the monitoring coupons. This condition can exist for from several hours to several days, depending upon the condition of the plant. Similarly, during operation of a plant which has experienced operating difficulties it may be necessary to increase the amount of components circulating, dissolved or undissolved, until the monitoring unit indicates a non-corroding condition.

The oxidizing agents which have been found to give satisfactory results when used in combination with one or more of the above sources of copper are: sulfur, potassium permanganate, calcium permanganate, sodium permanganate, potassium persulfate, potassium iodate, calcium iodate, sodium bromate, sodium persulfate, potassium meta periodate, strontium permanganate, sodium perborate, zinc permanganate, hydrogen peroxide, sodium dichromate, potassium dichromate, sodium perborate, sodium peroxide and oxygen.

The presence of hydrogen sulfide (H2S) is required if the inhibitor is to be effective in absorbent systems of potassium carbonate and the dialkanolamines. The inhibitor has limited effectiveness in the presence of CO2 alone in these absorbents. The preferred absorbents are monoethanolamine, diisopropanolamine-sulfolane, diethanolamine, diglycolamine(2-(2-amino-ethoxy)ethanol), 3-dimethylamino-1,2-propanediol (Methicol) all as aqueous solutions. It is to be understood that instead of water glycols may be employed.

General test procedure Various aqueous solutions of monoethanolamine, with or without inhibitors were prepared and the solutions saturated with H2S at 25"C. Mild steel coupons, which had been pickled in HCI (15 percent) for 30 minutes, rinsed with water, scrubbed with pumice soap and a toothbrush, rinsed first with water, and then with acetone and air dried, were weighed and immersed in the test solutions, with or without inhibitor. Then the solution jars were sealed and placed in a pressure vessel and maintained at 1200C. for 15 hours under a pressure which just exceeds the vapor pressure of the stripping solution (absorbent) at the 1200C. temperature used for stripping the acid gases from the absorbent. The metal coupons were removed, pickled for 10 minutes in 10 percent HCI which was inhibited with a commercial acid corrosion inhibitor, scrubbed, rinsed and dried as before. The so-prepared coupons were weighed and the difference in weight was converted to corrosion rate in mils penetration per year (mpy) (mm. x 39.37). Such a procedure determines the corrosion rate of the solutions on AISI 1010 or 1020 Steel. This test determines whether a compound or mixture of compounds has potential as an inhibitor, i.e. it is a screening test. The coupons are similar to the metal in a freshly cleaned, new plant and thus simulate start-up in such a plant. However, in an operating plant, there is an additional problem of corrosion products which act as a copper sink (absorb copper by chemical-combination), e.g., FeS will rapidly absorb copper ions from solution to form chalcopyrite, CuFeS2, a poor inhibitor.

Example 1 Solutions, prepared containing various compounds and mixtures of compounds, were tested in accordance with the above. Procedure to determine the effectiveness of the compounds as inhibitors. The results are set forth below: TABLE 1 % Monoethanol Rate, Amine % MPY Inhibitor in Water H2S (mm.) % Inhibition(1) Control None 80 Sat @ 25 C. 74 (1.9) 1 1000 ppm CuCO3 80 Sat @ 25 C. 14 81 1000 ppm KMnO4 (0.36) Control None 40 Sparged 16 14.4 hours w/H2S (0.37) 2 0.3 gm. (1000 ppm) CuCO3 40 Same 1.1 92 (0.028) 0.3 gm. (1000 ppm) KMnO4 (1)% inhibition = corrosion rate in mils penetration per year (MPY) (mm. x 39.37) without inhibitor - corrosion rate in mpy (mm. x 39.37) with inhibitor X 100 corrosion rate in mpy (mm. x 39.37) without inhibitor Example 2 In a similar manner, the following compounds were tested yielding the results set forth in Table II. The numbers under "Percent Inhibition" represent the average results of replicates. The data hereafter presented establish the utility of many of the copper salts listed as well as the effectiveness of the inhibitors of the present invention to reduce corrosion in various gas treating solutions used commercially. It is to be understood that these data do not define the lower limits of the compositions of the present invention, but only the indication that these compositions have utility as a corrosion inhibitor. The lower limits are determined by the test methods later set forth in this application. It will be readily observed, for example, that CuS and S added to maintain about 90 ppm and 45 ppm, respectively, will substantially inhibit corrosion in a badly corroded commercial plant, whereas most of the data from the laboratory hereafter set forth indicates 100 ppm of any combination usually gives less than 50 percent protection.

TABLE II 80% Monoethanolamine in water saturated with H2S at R. T.

Copper Source, ppm Oxidizing Agent, ppm % Inhibition(1) Cu2S 1000 KMnO4 1000 84,28 CuS 100 K persulfate 100 corrosion(2) CuS 100 KMnO4 100 corrosion CuS 500 KMnO4 500 90 CuS 1000 KMnO4 1000 96 CuS 500 K iodate 500 91 CuS 1000 K iodate 1000 90 CuS 500 K persulfate 500 88 CuS 500 K persulfate 1000 92 CuS 500 K persulfate 100 92 CuS 1000 Na bromate 1000 93 CuS 500 Na bromate 100 93 CuS 500 Na chlorate 1000 93 CuS 500 Na chlorate 100 93 CuS 1000 H202 (30%) 1000 60 Cu (oxalate)2 1000 KMnO4 1000 85 Cu (oxalate)2 2000 KMnO4 1000 94 Cu (oxalate)2 5000 KMnO4 1000 94 Cu (oxalate)2 1000 K persulfate 2000 corrosion Cu (oxalate)2 2000 K persulfate 5000 94 Cu oxalate)2 1000 H202 30%) 5000 88 Cu (oxalate)2 2000 H2O2 30% 1000 85 Cu (oxalate)2 5000 H2 2 (30%) 1000 85 Cu (acetate)2 1000 KMnO4 1000 91 Cu (benzoate)2 2000 KMnO4 1000 80 l)As calculated in Table I 2)Corrosion means no inhibition, i.e. same or greater corrosion rate as that observed with no inhibitor CuB4O7 1000 KMnO4 1000 85 Cu(CF3C02)2 1000 KMnO4 1000 77 CuS04 1000 K persulfate 1000 87 CuS04 1000 Na bromate 1000 60 CuS04 1000 KMnO4 1000 66 Cupric chromate 1000 KMnO4 1000 77 Cu (stearate)2 1000 KMnO4 1000 62 Cu (stearate)2 2000 KMnO4 1000 81 Cu (stearate)2 2000 KMnO4 2000 85 Cuprous per- 1000 KMnO4 1000 64 chlorate Cu(BF4)2 1000 KMnO4 1000 84 Cupric per- 1000 KMnO4 1000 75 chlorate Cupric per- 2000 KMnO4 1000 83 chlorate Cupric per- 5000 KMnO4 1000 95 chlorate Cupric 1000 KMnO4 1000 51 acetylacetonate Cuprous 1000 KMnO4 1000 84 acetate Cu2O 1000 Sulfur 1000 49 Cu2O 2000 Sulfur 1000 82 Cu2O 1000 Sulfur 2000 70 Cu2O 2000 Sulfur 2000 75 CuCO3 1000 Sulfur 1000 37 CuCO3 2000 Sulfur 1000 77 CuCO3 1000 Sulfur 2000 72 CuCO3 2000 Sulfur 2000 83 Cu(NO3)2 1000 Sulfur 1000 60 Cu(NO)2 1000 Sulfur 5000 46 CuC03 1000 KMnO4 1000 90 CuC03 1000 KMnO4 2000 80 CuCO3 1000 KMnO4 5000 75 CuCO3 1000 KMnO4 500 corrosion CuCO3 1000 KMnO4 100 corrosion CuCO3 2000 KMnO4 1000 91 CuC03 2000 KMnO4 500 92 CuCO3 2000 KMnO4 100 87 CuCO3 2000 KMnO4 50 86 CuCO3 5000 KMnO4 1000 91 CuC03 5000 KMnO4 500 90 CuCO3 5000 KMnO4 100 88 CuCO3 5000 KMnO4 50 86 CuCO3 10000 KMnO4 1000 90 CuCO3 10000 KMnO4 100 89 CuCO3 1000 K persulfate 2000 80 CuC03 2000 K persulfate 1000 81 CuCO3 2000 K persulfate 2000 85 CuC03 1000 K iodate 1000 79 CuCO3 1000 Na bromate 1000 85 CuC03 500 Na persulfate 500 corrosion CuCO3 1000 Na persulfate 500 corrosion CuCO3 1000 Na persulfate 1000 corrosion CuCO3 2000 Na persulfate 1000 86 CuCO3 1000 Na persulfate 2000 84 CuCO3 2000 Na persulfate 2000 86 CuCO3 1000 Na persulfate 5000 82 CuCO3 1000 K meta- 1000 71 -periodate CuCO3 1000 Na permanga- 1000 26 nate CuCO3 1000 Na permanga- 2000 33 nate CuCO3 2000 Na permanga- 1000 75 nate CuCO3 2000 Na permanga- 2000 81 nate CuCO3 1000 Sr permanga- 1000 66 nate CuCO3 1000 Sr permanga- 2000 82 nate CuCO3 1000 Sr permanga- 5000 94 nate CuCO3 2000 Sr permanga- 2000 96 nate CuCO3 5000 Sr permanga- 2000 94 nate CuCO3 1000 Na perborate 5000 68 CuCO3 1000 Zn permanga- 1000 72 nate CuCO3 2000 Zn permanga- 1000 80 nate CuCO3 1000 Zn permanga- 2000 59 nate CuCO3 1000 Ca iodate 1000 75 CuCO3 1000 NaHSO3 1000 corrosion CuCO3 1000 Na chlorate 1000 corrosion CuCO3 1000 Na chlorate 2000 corrosion CuCO3 1000 KI 1000 77 KMnO4 1000 CuCO3 1000 H2O2 (30%) 5000 63 Cu2O 1000 K persulfate 1000 corrosion Cu2O 1000 K persulfate 2000 90 Cu2O 1000 K persulfate 5000 93 Cu2O 2000 K persulfate 2000 89 Cu2O 2000 K persulfate 5000 93 Cu2O 1000 KMnO4 1000 corrosion Cu2O 2000 KMnO4 1000 44 Cu2O 2000 KMnO4 100 38 Cu2O 1000 Ca iodate 1000 87 CuO 1000 KMnO4 1000 90 CuO 1000 Ca iodate 1000 91 CuO 1000 K iodate 1000 95 CuO 1000 Na permanga- 1000 59 nate Cu(NO3)2 1000 Zn permanga- 1000 63 nate CuO 1000 K persulfate 1000 94 CuO 1000 Na bromate 1000 92 Cu(NO3)2 1000 Na dichromate 1000 40 Cu(NO3)2 1000 Na dichromate 5000 49 Cu(NO3)2 1000 Br2 1000 corrosion Cu(NO3)2 1000 I2 1000 corrosion Cu(NO3)2 1000 I2 2000 6 Cu(NO3)2 1000 I2 5000 corrosion Cu(NO3)2 1000 K persulfate 5000 corrosion Cu(NO3)2 1000 K persulfate 1000 corrosion Cu(NO3)2 1000 Na persulfate 1000 42 Cu(NO3)2 1000 Na persulfate 5000 50 Cu(NO3)2 1000 Na chlorate 500 corrosion Cu(NO3)2 1000 Na chlorate 100 corrosion Cu(NO3)2 1000 Na chlorate 1000 corrosion Cu(NO3)2 1000 Na chlorate 5000 corrosion Cu(NO3)2 5000 Na chlorate 5000 88 Cu(NO)2 1000 La perchlorate 1000 corrosion Cu(NO3)2 1000 Na perborate 1000 30 Cu(NO3)2 1000 Na perborate 500 35 Cu(NO3)2 1000 Sr permanganate 1000 63 Cu(NO3)2 2000 Sr permanganate 2000 91 Cu(NO3)2 5000 Sr permanganate 2000 95 Cu(NO3)2 1000 Sr permanganate 2000 67 Cu(NO3)2 1000 Sr permangate 5000 79 Cu(NO3)2 1000 Na peroxide 1000 corrosion Cu(NO3)2 1000 Periodic acid 1000 20 Cu(NO3)2 1000 NH4 persulfate 1000 16 Cu(NO3)2 1000 NH4 persulfate 2000 corrosion Cu(NO3)2 1000 NH4 persulfate 5000 28 Cu(NO3)2 1000 KMnO4 1000 72 Cu(NO3)2 1000 Ca permanganate 1000 80 Cu(NO3)2 1000 Ca iodate 1000 13 Cu(NO3)2 1000 K-meta 1000 78 periodate Cu(NO3)2 1000 H202 (80%) 5000 45 Cu(NO3)2 1000 H202 (30%) 1000 37 Cu(NO3)2 1000 H202 (30%) 5000 68 Cu(NO3)2 1000 Cu selenate 1000 corrosion Cu(NO3)2 1000 Na chlorate 1000 93 Cupric 1000 KMnO4 1000 77 chromate Cupric 2000 KMnO4 1000 70 molybdate Cupric 5000 KMnO4 1000 41 tungstate Cupric 5000 KMnO4 1000 28 phosphide CuCl2 1000 KMnO4 500 92 CuCl2 1000 KMnO4 1000 84 CuCl2 1000 K persulfate 500 92 CuCl2 1000 K iodate 500 92 CuI2 1000 KMnO4 1000 71 CuBr2 1000 KMnO4 1000 77 To demonstrate the effectiveness of the corrosion inhibitor compositions of the present invention in other commercial absorbents used in gas-treating plants a series of tests were run where various absorbents containing CuCO3 or CuS, an oxidizing agent and one or more acid gases were evaluated.

Procedure: The conditions for testing the various absorbents, including gas ratios, as volume ratios, are described in the following tables. The saturated solutions, at the concentration used, were poured into 4 oz. bottles (118 ml.) which had the inhibitors and the 1020 mild steel coupons (prepared as in the general procedure) already weighed and placed in them. The bottles were capped with loose fitting caps and placed in a pressure vessel which was then held at 125"C with a total pressure of 40 psig (2.8 kg./cm.2) of either H2S, or CO2 or both, for 16 hrs. All inhibitor components are reported in parts inhibitor component per million parts of absorbent medium.

Example 3 Absorbent used: N-Methyldiethanolamine 45% + water 55% Gas Loading ratio: 0.2 vol. CO2/vol. H2S MPY CuCO3 KMnO4 (mm./yr.) % Inhibition - - 38.5 0.0 (0.98) 1000 1000 11.2 71.0 (0.29) 1000 - 12 68.8 (0.30) - 1000 61 -58.5 (0.16) Example 4 Absorbent used: Diisopropanolamine 45%, Sulfolane 35%, Water 20% Gas Loading ratio: Saturated with H2S only MPY CuC03 KMnO4 (mm./yr.) % Inhibition - - 18.4 0.0 (0.47) 25 25 11.1 39.7 (0.28) 50 500 3.1 83.1 (0.08) 500 500 5.56 70 (0.14) 2500 50 8 56.5 (0.20) 2500 2500 5.74 68.8 (0.15) 5000 5000 7.46 59.4 (0.19) Example 5 Absorbent used: Diglycolamine (2-(2-aminoethoxy)ethanol) 60% + water 40% Gas loading ratio: Saturated with H2S only MPY CuC03 KMnO4 (mm./yr.) % Inhibition - - 20.4 0.0 (0.52) 50 50 37.5 -84 (1.0) 50 2500 6.21 69.5 (0.16) 500 500 3.22 83.7 (0.08) 2500 50 3.19 84.3 (0.08) 2500 2500 3.1 84.8 (0.08) 5000 5000 4 80.4 (O. 10) Example 6 Absorbent used: 3-dimethylamino-1,2-propanediol 50% + water 50% Gas loading ratio: CO2 sparged 30 min., H2S sparged 20 min. External H2S gas pressure was applied to to establish the pressure at 40 psig. (2.8 kg./cm.2) MPY CuC03 KMnO4 (mm./yr.) % Inhibition - - 25.55 0.0 1000 1000 11.11 56.5 (0.28) Example 7 Absorbent used: Potassium carbonate Gas loading ratio: 50/50 CO2/H2S saturated MPY CuC03 KMnO4 (mm./yr.) % Inhibition - - 27.63 0.0 (0.70) 1000 100 20.0 27.6 (0.50) 1000 1000 18.6 32.6 (0.47) 1000 2000 15.1 45.0 (0.38) The following three tables illustrate that a high CO2 content, i.e., CO2 alone or ratios greater than 1 to 1 CO2 to H2S, in potassium carbonate or diethanolamine systems are not effectively inhibited. However, when'the CO2 to H2S ratio is 1 to 1 or less than 1 to 1, e.g., 1/4.5 or H2S alone, inhibition is effected.

Comparative Example I Absorbent used: Potassium Carbonate Gas ratio: C02 only MPY CuS S" (mm./yr.) % Inhibition - - 42 0 (1.07) 500 - 56 -30 (1.42) - 500 80.2 -86.6 (2.04) 100 100 60.2 -40 (1.53) 500 1000 69 -58 (1.75) 1000 1000 87 -104 (2.21) 1000 3000 54 -28 (1.37) 3000 1000 105 -144 (2.67) Comparative Example 2 Absorbent used: Diethanolamine: (DEA) 30% + 70% water Gas ratio: 9/1 CO2/H2S MPY CuC03 S" (mm./yr.) % Inhibition 9.3 0 (0.24) 100 5000 22.76 -148 (0.58) 500 5000 27.8 -205 (0.71) 1000 5000 26.2 -185 (0.67) 5000 5000 33.02 -260 (0.84) Example 8 Absorbent used: Diethanolamine: (DEA) 40% + 60% water Gas loading ratio: CO2/H2S 1/4.5 MPY CuC03 KMnO4 (mm./yr.) % Inhibition - - 14.35 0.0 (0.37) 25 50 16.8 -17.07 (0.43) 25 5000 11.6 19.2 (0.29) 500 25 8.05 44.0 (0.20) 500 1000 7.91 45.0 (0.20) 500 5000 8.84 38.4 (0.22) 1000 50 9.27 35.4 (0.24) 1000 2000 11.0 23.3 (0.28) 5000 50 10.1 29.6 (0.26) Example 9 Absorbent used: Diethanolamine: (DEA) 80% + 20% water Gas ratio: Saturated with H2S only MPY CuC03 KMnO4 (mm./yr.) % Inhibition - - 17.25 0.0 (0.44) 1000 1000 5.66 67.2 (0.14) 1000 2000 6.5 62.3 (0.16) 1000 5000 -6.00 65.2 (0.15) 2000 1000 6.85 60.0 (0.17) 2000 2000 4.8 72.2 (0.12) 5000 1000 7.06 59.07 (0.18) 5000 5000 6.7 61.2 (0.17) It is apparent from the above data that the copper inhibitor composition of the present invention is not a satisfactory inhibitor for diethanolamine solutions of less than 50 percent diethanolamine when used for sweetening acid-gases high in carbon dioxide content.

Similarly the inhibitor composition has limited utility in potassium carbonate solutions of greater than 50 percent CO2. However, as H2S content increases, the inhibitory effect is apparent.

Example 10 An off-gas stripper in a medium size refinery operating at 250"F. (121"C.) on the reboiler and with 17 to 19% aqueous monoethanolamine asborbent, 6000 U.S. gallons (22.7 kiloliters) was seriously corroded and recording 37.4 mpy (0.95 mm./yr.) corrosion rate on an electrical resistance corrosion monitoring probe at the reboiler outlet, and 74.6 mpy and 95.5 mpy (1.89 and 243 mm./yr.) corrosion rate on coupons at the reboiler outlet and the reboiler cross-exchange, respectively. This rate of corrosion was experienced during a five-day period following a periodic shutdown. On the sixth day, copper sulfide and sulfur were added to the aqueous amine solution continuously at a rate of approximately 50 pounds (22.7 kg.) CuS every 6-8 days and approximately 24 pounds (10.9 kg.) sulfur every day.

Beginning the sixth day of the test, the day the corrosion inhibitor was added, throughout the twelfth day the corrosion rates were 9.75 mpy, 4.77 mpy and 16.08 mpy (0.25, 0.12 and 0.41 mm./yr.) at the probe at the reboiler outlet and the coupons at the reboiler outlet and reboiler cross-exchanger, respectively. From the twelfth day to the end of the test the corrosion rates were as follows: Probe Coupons Reboiler Reboiler Cross Outlet, Outlet, Exchanger Day MPY (mm./yr.) MPY (mm./yr.) MPY (mm./yr.) 12-14 1.85 1.26 9.44 (0.05) (0.03) (0.24) 19-26 1.85 1.25 14.6 (0.05) (0.03) (0.37) 27-39 1 10.5 13.7 (0.03) X (0.27) (0.35) 39-45 1 4.7 18.1 (0.03) (0.12) (0.46) On several instances the corrosion rate on the probe was allowed to increase to about 24 mpy (0.61 mm./yr.) by discontinuing the addition of inhibitor, then inhibitor addition resumed. Within one hour after the addition was resumed, the probe registered 1 mpy (0.03 mm./yr.) or less corrosion rate.

Methods for determining the corrosion rates and inhibitor effectiveness There are two methods which can be used to measure the corrosion rate and also the effectiveness of the copper based inhibitors of the present invention at various points throughout plants which are using solvents such as monoethanolamine to remove mixtures of acid gases, such as H2S and CO2, from liquid or gas process streams. The first is by using metal corrosion test coupons. The second is by using a metal resistance probe and an electrical resistance measuring bridge such as that manufactured by Corrosion Monitoring Systems, Inc., 33 Lincoln Road., Springfield, New Jersey 07081. A very good probe, the F.

Jefferies probe, is especially useful because of its all metal construction and essential freedom from temperature fluctuation sensitivity. This probe is also sold by the above named corporation. Another probe which is also useful is one made by Magna Corporation, who also manufactures a resistance bridge which will measure the corrosion experienced by their probe.

It is not unusual to have different sections of any gas treatment plant made from different metals. Thus, if the corrosion rate of a particular plant section is sought, it is necessary to measure the corrosion on a probe or coupon made of that same alloy which has been placed in the plant at that section.

A convenient coupon test method for mild steel is the one described below. Similar tests are available for other alloys.

First, a coupon of the metal of interest is machined. A convenient size is 1/2 in. x 2 in. x 1/16 in. (1.27 cm. x 1.27 cm. x 0.16 cm.). A 3/8 in. (0.95 cm.) hole is drilled near one end so that the coupon can be mounted on a coupon holder. This holder is used to place and hold the coupon, in electrical isolation from the plant's base metal, in the plant at the point of interest.

Second, the machined coupon is cleaned as described under General Test Procedure, weighed accurately on a balance to a tenth of a milligram and mounted on the coupon holder and placed into the plant's solution.

Entry to the corrosive environment is achieved by one of several techniques widely known in the art. One such method is to insert the coupon and its holder through a packing gland and then through an open valve.

Third, after the coupon has been in the corrosive environment for several days, it is removed. The exact number of days is not important except that, in order to be able to place more significance in the measured corrosion rates, times of 20-30 days are desirable; but times as short as one day can be used. Very short test periods generally result in higher apparent corrosion rates than would be expected from longer time period tests. The coupon is then recleaned according to the following procedure.

Place the corroded metal coupon in 15% HCI solution containing a good acid corrosion inhibitor. Then, follow the same instructions as listed above for the first cleaning of the coupon.

When the coupon is reweighed, subtract to determine the difference in weight from the weight of the untested coupon. The original weight, minus the final weight, will give the weight loss in grams.

By using the following method, a corrosion rate for the solution-alloy system can be calculated.

CR (mpy) = 0.183 x Wt. Loss (mg) (mm. x 39.37) Strip factor x Coupon Weight Before (gm) x Time (days) Where: 0.183 is the conversion factor from milligrams/square decimeter/day (mdd) to mils penetration per year (mpy) for mild steel (1020).

Strip Factor = Area in Decimeters of Reference Coupon Weight of Reference Coupon In Grams (For coupons used 0.0176 was strip factor) Fourth, inhibitor in the way and amount described in accordance with the present invention is added to the plant and a new corrosion rate determined by the method outlined just above.

Fifth, a percent inhibition is calculated for the particular inhibitor concentration used as follows: Uninhibited Corrosion Rate % Inhibition = Inhibited Corrosion Rate Uninhibited Corrosion Rate Sixth, the amount of inhibitor is increased or decreased to achieve the desired corrosion protection as measured by the coupon method just outlined. Usually, 5 mpy (0.13 mm./yr.) is achievable; but corrosion has been reduced in the hot, corrosive environments from 20 mpy (0.51 mm./yr.) to values less than 1 mpy (0.03 mm./yr.) as measured by this technique which is found to correlate well with plant inspection and measurements made on specific elements by a state licensed boiler inspector.

The corrosion rate of a plant's solution can also be measured by using metal probes such as those described earlier. In this case, the probe is designed to replace the coupon as described above. The probe can be used directly as received from the manufacturer where it was sand-blasted before shipment or it can be cleaned with uninhibited HCI as described in the above by the coupon cleaning method.

After the corrosion probe is cleaned, it is inserted into the plant's solution at the location in question and the temperature allowed to equilibrate. A resistance reading is taken with a resistance bridge. The bridge sold by the probe manufacturer is very convenient. By drawing a graph of the resistance probe vs. time, the corrosion rate can be calculated from the slope of the line using the formula supplied by the probe manufacturer.

When the uninhibited corrosion rate has been determined, inhibitor is added according to the present invention and the corrosion rate is measured and calculations made as above outlined.

It frequently happens that much less inhibitor is required than laboratory tests appeared to indicate. In fact it was discovered that laboratory experiments indicated the ability of the inhibitors to passivate new or severely corroded metals, and that once passivation was achieved much less inhibitor was necessary in order to minimize corrosion. In addition, pilot plant and field testing illustrated that techniques for on-line measuring of the corrosion were needed which would indicate the potential for corrosion prior to actual corrosion.

Such an on line system would thus signal the need for greater concentration of inhibitors.

Therefore, it is desirable to provide in a gas treating plant a commercial inhibitor composition capable of use at start-up of the plant and for passivating the metal surfaces of the plant during normal operation, and a method for determining the appropriate times to add inhibitor during the operation of the plant.

The metal surfaces of the gas-treating plant are effectively passivated and proper times for adding correct amounts of inhibitor composition are determined by introducing into the absorbent medium or product derived by reacting monoethanolamine at from 21"C. to 100"C. with sulfur and an inorganic sulfide and an oxidizing agent, together with copper metal or a copper salt, sulfide, hydroxide or oxide, for from 0.1 to 20 hours, until the resulting mixture is stable when diluted with water. The sulfur or sulfur compounds are present in a ratio of 3 to 30 parts by weight of copper per part of sulfur, and in an amount of 1 to 40 percent by weight of the total composition. This composition is added to the absorbent medium in the gas treating unit in a sufficient amount to maintain at least 0.00002 pound (0.0091 g.) of copper and at least 0.0001 pound (0.045 g.) of sulfur per pound (454 g.) of absorbent medium per day.

The reaction to prepare the composition is conveniently and preferably carried out in monoethanolamine, although it can be carried out in other of the amine absorbents employed in the gas treating industry, e.g. diethanolamine, at from ambient temperature to about 100"C for a sufficient time to produce a stable, non-precipitating composition.

Conveniently, periods of from 0.1 to 20 hours are employed. The product so produced can be added to an absorbent stream of a gas treating plant, as for example an aqueous alkanolamine employed as described in U.S. Patent No. 3,349,544. The addition can be continuous or batchwise sufficient in quantities to maintain the circulating absorbent medium substantially noncorrosive to the metal surfaces of the plant. In particular, the product is added to provide corrosion protection to those portions of the plant which are contacted by elevated temperatures, i.e., 200"F (93"C.) and above, principally the regenerator, wherein the acid-gases are released. The inhibitor's viscosity may be adjusted by addition of small quantities of water to facilitate handling and additions.

The amount of inhibitor composition employed may vary considerably from 0.00002 pounds (0.0091 g.) per pound (454 g.) of absorbent (20 parts per million) of copper equivalent per day to 0.02 pounds (9.1 g.) per pound (454 g.) of absorbent (20000 ppm) copper equivalent per day, and 0.0001 pounds 00.045 g.) per pound (454 g.) of absorbent (100 parts per million) of sulfur equivalent per day to 0.2 pounds (91 g.) per pound (454 g.) of absorbent (200,000 ppm) sulfur equivalent per day. The lower concentrations ranging from about 20-100 ppm copper equivalents per day and about 100 to about 1000 ppm sulfur equivalents per day are useful in a commercial operation at a plant which has been on stream with the inhibitor for several weeks. The higher concentrations ranging from about 500 to about 2000 ppm copper equivalents per day and about 5000 to about 20000 ppm sulfur equivalents per day are the amounts which may be necessary to maintain a non-corrosive condition, as detected by a metal resistence corrosion probe. This is true regardless of whether the inhibitor has just been installed in the plant, or whether the inhibitor has been in use for some time and the plant is being started up after a shutdown.

The advantage of the present inhibitor composition is ability to add inhibitor to a plant quickly and in measured amounts. Thus the operator can follow the effect of the addition and add the proper amount of inhibitor to passivate the metal surfaces of the plant that are contacted by the absorbent.

Example 11 Preparation of the inhibitor To a stirred and heated kettle containing 67.5 Ibs. (30.6 kg.) of monoethanolamine was added 31.5 Ibs. (14.3 kg.) of sulfur. The mixture was heated for one hour at 90" to 100"C with stirring. Then 3 Ibs. (1.36 kg.) of copper metal in the form of chopped copper wire was added with stirring, followed by heating at 900 to 1000C with stirring for another hour. The solution resulting from this procedure was filterdd and allowed to cool to room temperature without stirring. It remained free of precipitate or solids. The mixture was stable to repeated heating and freezing cycles between 100"C and -50 C. Addition of 15% water did not precipitate free sulfur, nor was sulfur extractable with carbon disulfide. This inhibitor solution was used as a stock solution for periodic addition to the absorbent in the plant, as described below.

The inhibitor was introduced into the rich monoethanolamine stream of a sour gas conditioning pilot plant which processes sour gas (natural gas containing high concentrations of H2S and CO2). The operating conditions for the plant, inhibitor introducing rate and corrosion rates are set forth below: Operating conditions H2S/CO2 (ratio) 9:1 Loading .6-.8 moles acid gas/mole MEA(1) MEA(') concentration 30% wt. in H2O Flow rate 0.25-0.3 U.S. gallons (0.95-1.13 liters)/min.

MEA inventory 10 U.S. gal (38.8 liters) Absorber 80-150"F (gradient) (27-66"C.) Stripper reboiler 232-240"F (111-116"C.) Inhibitor injection Continuous (I) MEA - monoethanolamine Over a period of 168.5 hours the corrosion rate was maintained at about zero mils penetration per year (MPY) (mm. x 39.37) as determined by a,corrosometer with the amounts of inhibitor solution indicated in Table I.

TABLE I Time Period Amount of Liquid Equivalent Corrosion (hours) Formulation Injected (ml.) (ml/day) Rate (MPY)' 27 143 127 0.0 24 88 88 0.0 23 184 192 0.0 25 155 148 0.0 21.5 48 53 0.0 24 43 43 0.0 24 216 216 0.0 'mils penetration per year as measured by an electrical resistance probe.

In a similar manner as above set forth 4.5 Ibs. of CuS (2.04 kg.) was substituted for Cu metal. Results were similar to those above set forth.

Example 12 In the following test, the same pilot plant was operated under lower daily inhibitor injection rates to determine if corrosion would occur, and if so, whether larger additions of inhibitor could bring the plant to a more passive (less corrosive) state again. Table II illustrates the results. The first seven entries repeat the entries in Table I and the remaining entries show the results of two lesser daily rates followed by two larger rates. The lower rates of 0.000011 copper and 0.000132 sulfur permitted corrosion whereas the return to 0.000056 copper and 0.000674 sulfur established the non-corrosive or passive state.

TABLE II Formulation Equivalent Daily Rate Time Injected Daily Rate (lbs./day(g./day) Plant (Hrs) (ml.) (ml./day) Cu S Condition 27 143 127 0.00007(0.032) 0.00084(0.38) No Corrosion 24 88 88 0.000048(0.0022) 0.00058(0.26) No Corrosion 23 184 192 0.00010(0.045) 0.00126(0.57) No Corrosion 25 155 148 0.00008(0.036) 0.00098(0.44) No Corrosion 21.5 48 53 0.00003(0.014) 0.00035(0.16) No Corrosion 24 43 43 0.000025(0.011) 0.00030(0.14) No Corrosion 24 216 216 0.00012(0.054) 0.00142(0.64) No Corrosion 12 10 20 0.000011(0.005) 0.000132(0.06) Corrosion 12 10 20 0.000011(0.005) 0.000132(0.6) Corrosion 27 115 102 0.000056(0.025) 0.000674(0.31) No Corrosion 9 50 133 0.000073(0.033) 0.00088(0.40) No Corrosion

Claims (18)

WHAT WE CLAIM IS:

1. A corrosion inhibiting composition for ferrous metal and its alloys when in contact with acid-gas stripping absorbent solutions prepared from absorbents selected from (a) one or more alkanolamines having the formula:

wherein R1 and R2 are each independently a hydrogen atom, or a --C(R3)2C(R3)2-OH group and R3 is a hydrogen atom, or a C13 alkyl group, (b) tetrahydrothiophene-1 ,1-dioxide, (c) potassium carbonate and (d) diglycolamine (2-(2-aminoethoxy)ethanol, alone or as a mixture of two or more thereof as aqueous solutions or glycol solutions, the inhibiting composition consisting essentially of: (e) a source of copper ions which is copper metal, copper oxide, copper sulfide, copper hydroxide or a copper salt, and (f) a source of sulfur atoms which is 1) sulfur, or 2) a sulfur generating compound in combination with an oxidizing agent which will produce sulfur atoms in solution, at least some of which is present as the polysulfide, under the conditions of operation in an acid-gas stripping plant which employs thermal regeneration techniques for separating the combined acid-gas from the stripping absorbent, and an absorbent for (e) and (f) which is (a), (b), (c) or (d), or a mixture of two or more thereof.

2. A corrosion inhibiting composition as claimed in claim 1 which consists of copper metal and a sulfur generating compound in combination with an oxidizing agent.

3. A corrosion inhibiting composition as claimed in claim 1 which consists of copper sulfide.

4. A corrosion inhibiting composition as claimed in claim 1 which consists of copper sulfide and an oxidizing agent.

5. A corrosion inhibiting composition as claimed in claim 4 wherein the oxidizing agent is sulfur.

6. A corrosion inhibiting composition as claimed in claim 1 wherein component (e) is a copper salt.

7. A corrosion inhibiting composition as claimed in claim 6 wherein the copper salt is cupric or cuprous carbonate, benzoate, stearate, acetate, acetylacetonate, chloride, oxalate, molybdate, chromate, perchlorate, sulfate or tetrafluoroborate.

8. A corrosion inhibiting composition as claimed in claim 1 wherein the oxidizing agent is potassium permanganate, calcium permanganate, sodium permanganate, potassium persulfate, potassium iodate, calcium iodate, sodium bromate, sodium persulfate, potassium meta periodate, strontium permanganate, sodium perborate, zinc permanganate, hydrogen peroxide, sodium dichromate, potassium dichromate, sodium perborate, sodium peroxide or oxygen.

9. A corrosion inhibiting composition as claimed in any one of the preceding claims wherein the absorbent is an aqueous solution of monoethanolamine, diisopropanolaminetetrahydrothiophene-1,1-dioxide, diethanolamine, diglycolamine (2-(2aminoethoxy)ethanol), or 3-dimethylamine-1,2-propanediol.

10. A ferrous metal corrosion inhibiting composition consisting of: (a) copper as copper metal, copper oxide, copper sulfide, copper hydroxide or a copper salt; and (b) an oxidizing agent which, in the presence of sulfur or a sulfur generating compound, will convert sulfur to sulfur atoms and/or oxidize copper to copper ions, and an alkanolamine of the formula:

wherein R1 and R2 are each independently a hydrogen atom, or a -C(R3)2C(R3)2-OH group and R3 is a hydrogen atom or a C13 alkyl group.

11. A corrosion inhibiting acid-gas absorbing composition consisting of an absorbent selected from (a) an alkanolamine having the formula:

wherein R1 and R2 are each independently a hydrogen atom, or a -C(R3)2C(R3)2-OH group and R2 is a hydrogen atom or a C13 alkyl group, (b) tetrahydrothiophene-1,1dioxide, (c) potassium carbonate, or (d) diglycolamine (2-(2-aminoethoxy) ethanol, either alone or as a mixture of two or more thereof as aqueous solution containing from 1 to 500 ppm copper and 1 to 5000 ppm sulfur, both based on the weight of the absorbent.

12. A corrosion inhibited composition as claimed in claim 11 wherein the absorbent is an alkanolamine.

13. A corrosion inhibiting composition as claimed in claim 1 and substantially as hereinbefore described.

14. A method for removing acid-gases from natural and synthetic gases containing them by contacting the acid-gas containing gases with a gas absorbing solution prepared from an absorbent selected from (a) an alkanolamine having the formula:

wherein R1 and R2 are each independently a hydrogen atom, or a -C(R3)2C(R3)2-OH group and R3 is a hydrogen atom or a C13 alkyl group, (b) tetrahydrothiophene-1,1dioxide, (c) potassium carbonate or (d) diglycolamine (2-(2-aminoethoxy)ethanol), either alone or as a mixture of two or more thereof as aqueous solutions or glycol solutions, the gas absorbing solution containing therein a composition as claimed in any one of claims 1 to 11, thereby to reduce the corrosive attack of the acid-gases on the metallic components of the equipment in which the acid-gas removal and the regeneration of the gas absorbing solution is carried out.

15. A method for inhibiting the corrosion of metals in contact with a circulating absorbent medium, which is used for the removal of acid-gases from natural or synthetic gas streams wherein the circulating, rich absorbent is heated in order to release the acid-gases, the resulting lean absorbent is contacted with the acid-gas containing gas stream, and wherein the absorbent medium contains a product derived by reacting a monoalkanolamine at a temperature of from 21"C to 100"C. with sulfur or a sulfur compound and an oxidizing agent, together with copper metal or a copper salt, sulfide, hydroxide or oxide, for from 0.1 to 20 hours, until the resulting mixture is stable when diluted with water, the sulfur or sulfur compound being present, based on sulfur, in a ratio of from 3 to 30 parts by weight per part of copper; and, in an amount of from 1 to 40 percent by weight of the total composition, the product being added to the absorbent medium in an amount which maintains at least 0.00002 pound of copper and 0.00002 pound of sulfur per pound of absorbent medium per day.

16. A method as claimed in claim 15 wherein the product is the result of reacting sulfur, monoethanolamine and copper or copper sulfide at a temperature of from 90" to 1000C.

17. A method as claimed in claim 14 substantially as hereinbefore described.

18. A method as claimed in claim 15 substantially as hereinbefore described with reference to Example 11 or Example 12.