DE2748216A1 - Corrosion inhibitor for acid-gas stripping plant - comprises copper ions and sulphur atoms in aq. alkanolamine soln. - Google Patents

Abstract

Corrosion inhibiting compsn. for ferrous metals and alloys in contact with acid-gas stripping absorbent solns. comprises (a) a source of copper ion, which is copper, copper sulphide or a copper salt, and (b) a source of sulphur atoms, which is (1) sulphur, or (2) H2S and/or COS in combination with an oxidizing agent, which, under the conditions of acid-gas stripping and regeneration of the stripping absorbent, yield sulphur atoms. in soln. at least some of which are present as polysulphide. (a) and (b) are in soln. in the absorbent soln. The absorbent soln. in an alkanolamine of formula (I) where R1 and R2 are each H or -C(R3)2C (R3)2-OH and R3 is H or 1-3C alkyl, in aq. or glycol soln. Used partic. in removing CO2 and H2S from natural and synthetic gases. The corrosion inhibitor allows higher loading of the plant.

Description

Corrosion inhibitor for metal that comes into contact with

Acid gases is the conditioning (sweetening) of gases, natural and synthetic ones, i.e. the removal of acidic gases such as C02, H2S and COS Absorption in a liquid absorbent medium has been technical for many years carried out. Various absorbents, such as alkanolamines, sulfolane (tetrahydrothiophene-1h1-dioxide), "Sulfinol" (tetrahydrothiophene-I 1 -dioxide plus diisopropanolamine) and potassium carbonate, are used technically. Corrosion problems arise with each of these systems. Some of them cause the absorbent to decompose, some cause a reaction between the acidic components of the gases to be treated and the absorbent, and attack by the acidic components of the gases with which treat the metals used to build the device. In general finds the corrosion in the regenerator, the heat exchangers or in pumps and Pipes or tubes take place with these elements of the gas treatment units are connected. There were numerous Compounds as additives for the absorbents to prevent corrosion and / or the formation of corrosive Elements suggested. For example, copper sulfate has been in a for three years 15 some monoethanol amine gas processing plant to remove 10 C02 from the Gas used. Corrosion is observed due to a reduction in the useful life the reboiler and the heat exchange tubes, and when analyzing the amine solution only a few ppm of copper are solid, causing excessive copper deposition in the unit (Gas Conditioning Fact Book, The Dow Chemical Company, Midland, Michigan, 1962, pages 157 to 158, case no.8).

In US-PS 1 989 004 the use of an alkanolamine or a mixture of mono-, di- and trialkanolamines in a concentration of 15 up to 30% in water and less than 1% of a soluble metal salt, e.g.

Copper or nickel sulfate or oxide.

However, there is no indication of providing sulfur, i.e. more elemental Sulfur or the necessary sulfur compounds and oxidizing agents for formation of sulfur atoms.

In US Pat. No. 1,989,004, H2S and organic sulfur compounds are disclosed from the gas using the complexing activity of each of the components, i.e.

the amine, the amine-metal complex and the metal. These Complexes are nonthermally in two stages to release the amine for the Reuse and convert the sulfur to a solid for removal handled from the system.

According to this US patent, the used solution (aqueous Alkanolamine, which is the amine-sulfur compound Complex and the amine-metal-sulfur compound complex contains) not with heat for regeneration, but with air (page 1, column 2, Lines 20 to 38) treated for the oxidation of sulfur compounds (thiosulfates). The oxidized solution is then mixed with lime to precipitate the sulfur as calcium sulfate and thiosulfates treated. It is well known that the alkanolamine is oxidized and that the aeration increases the loss of alkanolamine, resulting from the It can be seen that 15 to 30% amine solution is used in Example II (p 2, column 1, lines 49 to 56) and that after regeneration only about 10 to 1396 Amine solution are present, causing a loss of about 3096 of the original amine means.

The past few years have been both natural and synthetic Formed gases that contain high concentrations of C02 and / or H2S. after the As demand for neutral gases increases, so does the size of the units for treatment of these gases too. For economic reasons, there appears to be an increase in the Con: entration of absorbent in the system and X or an increase in load of the system is desirable. Both of these increase these increases, although they are very undesirable are, the corrosion in the unit, and this causes a more frequent, unplanned Parking for the repair and replacement of the main elements.

It would therefore be desirable if an inhibitor system was available that could be used with devices in contact with acid gas environments, whereby corrosion of the metals used to build the device can be avoided used in these conditions.

The invention relates to a corrosion inhibitor composition or preparation for a ferrous metal and its alloys or for ferrous metals and their alloys when they are in contact with acid gas stripping absorbent solutions which are prepared from solvents selected from the group which contains (a) Alkanolamines of the formula in which each of the substituents R, and R2 is hydrogen or -C (R3) 2C (R3) 2-OH and R3 is hydrogen or a Cl 3 -alkyl group, (b) tetrahydrothiophene-1,1-dioxide, (c) potassium carbonate or (d) diglycolamines, each alone or in admixture with one or more of the other aqueous solutions or glycol solutions, the inhibitor composition essentially comprising (e) a source of copper ions selected from the group consisting of copper metal, copper sulfide and copper salts, and (f) a source of sulfur atoms selected from the group (1) sulfur or (2) hydrogen sulfide and / or COS together with an oxidizing agent which forms the solution of the sulfur atoms, at least a part of which is the polysulfide, under the operating conditions in an acid gas stripping system , in which thermal regeneration processes are used, for the separation of the bound acid gas from the strip absorbent and a solvent for (e) and (f) selected from (a), (b), (c) or (d) The amount of copper ions required to reduce corrosion will vary with each installation and will vary from day to day for a particular installation.

Therefore, it becomes the most practical way to determine the appropriate amount of copper ions that can be put into the devices in places where the strongest Corrosion occurs, generally in the reboiler and in the cross exchangers Reboiler, a metal coupon that is periodically replaced with a shiny Copper plate and corrosion is checked. Such type of control is used in the Examples explained and explained in detail. When the inhibitor composition of the invention first used in a gas treatment unit must have a large amount of copper as much in the removal of the corrosive elements and the corrosion products is consumed at the points where corrosion has already taken place or will develop. Having obtained a degree of passivation against corrosion has been found to be as little as about 15 parts inhibitor / million parts absorbent solution give and maintain a corrosion rate below 0.025 mm / year (1 mil / yr.). In most cases where high levels of inhibitor are required initially it is common for the inhibitor to eventually passivate the entity by the harmless components are removed, and thereby there is a reduction of the inhibitor to the more usual amounts, i.e. in some cases even as little such as 1 to 10 ppm, possible. Even in those cases where the corrosion is only moderate is reduced, the necessary shutdowns or shutdowns are conditional by corrosion, kept to a minimum and even eliminated between normal shutdowns the plant.

Copper (metal, oxide, hydroxide or salt) is used for in-situ generation of copper ions under the conditions used in the gas treatment or the conditioning process occur using thermal regeneration, used, and sulfur or sulfur-yielding compounds that under the operating conditions (in particular at the thermal Regeneration) sulfur atoms and preferred Polysulphide moieties form, are used or are present.

The copper ions form a copper polysulphide with the copper atoms and polysulphide molecule parts: where y is an integer from 2 to 6 and n is an integer from 2 to about 50. The copper polysulphide is available to form a chalcopyrite, ie CuFeS2, from solution with the Fe ++ in solution with formation on the surface of the reactor, the heat exchanger etc. The Fe ++ is the main product in the cathodic corrosion reaction. In some cases the copper will be further reduced to copper atoms which will alloy the ferrous metal under the chalcopyrite surface layer to form a copper-iron alloy. This phenomenon results in an effective physical and electrical insulation against the corrosive environment (the alkanolamine, the alkanolamine decomposition products, H2S, CO2, Cu + 2, ° Fe + 3 and 02), ie the chalcopyrite acts as a kinetic insulation against the corrosion reactions by it hinders the electron and wet transport required to support the anodic and cathodic corrosion half-reactions.

This phenomenon is of course based on theoretical considerations and is determined by results of surface analysis of the ferrous surface both passivated as well as corroded surfaces using depth profiles, Auger spectroscopy and electron microprobes supported.

The copper ions are expediently in an absorbent medium, both during and after the initial meal, as a solution or by dissolving in the Absorbent introduced. It will be sufficiently close to any of the following used, by the equivalent of 1 to 15 or more parts copper / million parts absorbent medium to yield: (I) copper metal, if accompanied by sulfur or an oxidizing agent, the sulfur forms from the H2S dissolved in the absorbent; (11) copper sulfide [either copper (II) or copper (I)]; (III) a copper salt [copper (II) or copper (I)] along with an oxidizer, and if little or no H2S or COS in that Acid gas is present, then sulfur or a sulfur-forming compound. the Copper salts can include copper (II) or copper (I) carbonate, benzoate, stearate, -acetate, -acetylacetonate, -chloride, -oxalate, -oxide, -molybdate, -chromate, -perchlorate, sulfate or tetrafluoroborate.

The amount of inhibitor in the circulatory system can and is frequent greater than the amount dissolved in the absorbent. Such a condition becomes during the initial stages when introducing the inhibitor into the plant or when starting or switching on the system or when restarting after a planned or unscheduled shutdown or shutdown took place. During these times if the inhibitor reacts with the metal of the system, it passivates the corrosion spots and reacts with the corrosion products and passivates these products, so that the Inhibitor is consumed. There must therefore be inhibitor components present, to replace the used ones. If the solubility of one or more of the Components is limited, there must be an excess of the component or components be present so that a reaction and / or dissolution takes place and the corrosion is effectively inhibited. It was found to be as much as 500 to 2000 in the beginning ppm inhibitor must be present to passivate a system when it is switched on, so that satisfactory readings are obtained on the control coupons. This State can take several hours to continue for several days, depending on the condition of the system. It can be similar during the operation of a system who have encountered difficulties in operation, the amount required of circulating components, dissolved or undissolved, increase until the control unit indicates a non-corrosive condition.

The oxidizers found to be when they are used in conjunction with one or more of the above sources of copper, provide good results are: sulfur, potassium permanganate, calcium permanganate, Sodium permanganate, potassium persulfate, potassium iodate, calcium iodate, sodium bromate, sodium persulfate, Potassium m-periodate, strontium permanganate, sodium perborate, zinc permanganate, hydrogen peroxide, Sodium dichromate, potassium dichromate, sodium perborate, sodium peroxide and oxygen.

The acid gas stripping absorbents which are satisfactory for use in the present invention are the alkanolamines of the formula in which each of the substituents R1 and R2 is independently hydrogen or -C (R3) 2C (R3) 2-OH and the substituents R3 are independently hydrogen or a C13-alkyl group. This absorbent can be used alone or in conjunction with any other or any of the following also useful gas wipe absorbents: sulfolanes (tetrahydrothiophene-1,1-dioxide), potassium carbonate, or diglycolamines.

The presence of hydrogen sulfide (H2S) is required when the inhibitor effective in absorbent systems of potassium carbonate and dialkanolamines should be. The inhibitor has limited effectiveness in presence of CO2 alone in these absorbents. The preferred absorbents are monoethanolamine, Diisopropanolamine sulfolane, diethanolamine, diglycolamine [2- (2-aminoethoxy) ethanol], 3-Dimethylamino-1,2-propanediol (Methicol), all as aqueous solutions. Instead of Glycols can be used in water.

General test procedure Various, aqueous solutions of monoalkanolamine, with or without an inhibitor, are prepared, and the solutions are treated with H2S 250C saturated. Fluorescent iron coupons that have been etched in HCl (155) for 30 minutes were rinsed with water, scrubbed with pumice stone soap and a toothbrush, rinsed first with water and then with acetone and allowed to air dry are weighed and immersed in the test solutions, with or without inhibitor. The vessels with the solutions are then sealed and placed in a pressure vessel and held at 120 ° C for 15 hours at a pressure just the vapor pressure of the stripping solution (Absorbent) at 120 ° C temperature, which is used to strip the acid gases from the absorbent is used. The metal coupons are removed, 10 min in the above HCl inhibited with a commercially available acid corrosion inhibitor, etched, scrubbed, rinsed and dried as before. The coupons produced in this way are weighed, and the difference in weight is expressed in the corrosion rate in mm Penetration per year (mpy) (mils penetration per year = mm x 39.37). By One such method is the corrosion rate of solutions at AISI 1010 or 1020 Steel definitely. This test determines whether a compound or a mixture of compounds Has a potential effect as an inhibitor, i.e. it is a screening test. The coupons are similar to the metal in a freshly cleaned, new facility and thus stimulate switching on such a system. at However, in a plant that is in operation, the corrosion products arise as an additional problem that act as a copper sink (by removing the copper by chemical Absorb binding), e.g. FeS quickly becomes copper ions from the solution with formation absorb from chalcopyrite, CuFeS2, a poor inhibitor.

Example 1 Solutions containing various compounds and mixtures of Connections are established and, as described above, tested to determine the effectiveness of the compounds as inhibitors. The results are listed below.

Table I Inhibitor% Monoethanol% H2S Rate% Inhibieamine in Water mpy * tion (1) (mm) None 80 saturated 74 -equal to approx. 250C (1.9) 1 1000 ppm CuCO3 80 ditto 14 81 1000 ppm KMnO4 (0.36) Ver none 40 sprays 14.4 - same 16 h w / H2S (0.37) 2 0.3 g (1000 ppm) CuCO3 40 ditto 1.1 92 0.3 g (1000 ppm KMn04 penetration per year corrosion rate in mm 'penetration / year without inhibitor - corrosion rate in (1)% inhibition = mm @, / year with inhibitor x 100 corrosion rate in mm / year without inhibitor Example 2 In a similar manner, the following compounds examined to obtain the results shown in Table II. The number under% inhibition "gives the average number of repetitions at. The values listed below show the usefulness of many of the listed ones Copper salts as well as the effectiveness of the inhibitors according to the invention for reduction the corrosion in various gas treatment solutions that are used technically. These values do not define any lower limits for the compositions according to the invention, but are only an indication that these compositions act as corrosion inhibitors can be used. The lower limits are determined according to the procedures for the test, which will be listed later. For example, it is easy to see that if CuS and S are added to maintain about 90 ppm and 45 ppm, respectively, of the corrosion is essentially inhibited in heavily corroded technical systems, whereas display most of the values from the laboratory listed below, that 100 ppm of any mixture normally gives less than 50% protection.

Table II 80 Monoethanolamine in water, saturated with H2S at room temp.

Copper source, ppm oxidizing agent, ppm tió inhibition (1) Cu2S 1000 KMnO4 1000 84.28 CuS 100 K-persulfate 100 Corrosion (2) CuS 100 KMnO4 100 Corrosion CuS 500 KMn04 500 90 CuS 1000 KMnO4 1000 96 CuS 500 K-3odat 500 91 CuS 1000 K-iodat 1000 90 CuS 500 K-persulphate 500 88 CuS 500 K-persulphate 1000 92 CuS 500 K-persulphate 100 92 CuS 1000 Na-bromate 1000 93 CuS 500 Na-bromate 100 93 calculated according to the table II 2 Corrosion means no inhibition, i.e. the same or a higher corrosion rate, when observed without an inhibitor Table II (continued) Copper source, ppm oxidizing agent, ppm% inhibition (1) 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 persulphate 2000 Corrosion Cu (oxalate) 2 2000 K persulphate 5000 94 Cu (oxalate) 2 1000 H202 (30%) 5000 88 Cu (oxalate) 2 2000 H2 ° 2 (30%) 1000 85 Cu (oxalate) 2 5000 H202 (30%) 1000 85 Cu (acetate) 2 1000 KMnO4 1000 91 Cu (benzoate) 2 2000 KltnO4 1000 80 CuB407 1000 KMn04 1000 85 CuJ (P # 3) 4 2000 KMn04 1000 80 CuJ (P # 3) 4 1000 KMnO4 1000 35 Cu (CF3C02) 2 1000 KMnO4 1000 77 CuS04 1000 K-persulfate 1000 87 CuS04 1000 Na-bromate 1000 60 CuS04 1000 KMn04 1000 66 copper (II) - 1000 KMnO4 1000 77 chromate Cu (stearate) 2 1000 KMnO4 1000 62 Cu (stearate) 2 2000 Kt4n04 1000 81 Cu (stearate) 2 2000 KMn04 2000 85 Copper (I) perchlorate 1000 KMnO4 1000 64 Cu (BF4) 2 1000 KMn04 1000 84 Copper (II) perchlorate 1000 KMnO4 1000 75 ditto 2000 KMn04 1000 83 ditto 5000 KMnO4 1000 95 copper (II) - 1000 KMnO4 1000 51 acetylacetonate Table II (continued) copper source, ppm oxidizing agent, ppm% inhibition (1) copper (II) acetate 1000 KMnO4 1000 84 Cu2O 1000 sulfur 1000 49 ditto 2000 ditto 1000 82 ditto 1000 ditto 2000 70 ditto 2000 ditto 2000 75 CuC03 1000 ditto 1000 37 ditto 2000 ditto 1000 77 ditto 1000 ditto 2000 72 ditto 2000 ditto 2000 83 Cu (N03) 2 1000 ditto 1000 60 ditto 1000 ditto 5000 46 CuC03 1000 KMnO4 1000 90 ditto 1000 ditto 2000 80 ditto 1000 ditto 5000 75 ditto 1000 ditto 500 Corrosion ditto 1000 ditto 100 ditto ditto 2000 ditto 1000 91 ditto 2000 ditto 500 92 ditto 2000 ditto 100 87 ditto 2000 ditto 50 86 ditto 5000 ditto 1000 91 ditto 5000 ditto 500 90 ditto 5000 ditto 100 88 ditto 5000 ditto 50 86 ditto 10000 ditto 1000 90 ditto 10000 ditto 100 89 ditto 1000 K persulfate 2000 80 ditto 2000 ditto 1000 81 ditto 2000 ditto 2000 85 ditto 1000 K-3odat 1000 79 same as 1000 Na-bronat 1000 85 Table II (continued) Copper source, ppm oxidizing agent, ppm% inhibition (1) CuC03 500 Na persulfate 500 Corrosion ditto 1000 ditto 500 ditto ditto 1000 ditto 1000 ditto ditto 2000 ditto 1000 86 ditto 1000 ditto 2000 84 ditto 2000 ditto 2000 86 ditto 1000 ditto 5000 82 ditto 1000 K-m-period 1000 71 ditto 1000 Na permanganate 1000 26 ditto 1000 ditto 2000 33 ditto 2000 ditto 1000 75 ditto 2000 ditto 2000 81 ditto 1000 Sr-permanganate 1000 66 ditto 1000 ditto 2000 82 ditto 1000 ditto 5000 94 ditto 2000 ditto 2000 96 ditto 5000 ditto 2000 94 ditto 1000 Na-perborat 5000 68 ditto 1000 Zn permanganate 1000 72 ditto 2000 ditto 1000 80 ditto 1000 ditto 2000 59 ditto 1000 Ca-iodate 1000 75 ditto 1000 NaIS03 1000 corrosion ditto 1000 Na-chlorate 1000 ditto ditto 1000 ditto 2000 ditto ditto 1000 KJ 1000 77 KMnO4 1000 ditto 1000 H202 (3050) 5000 63 Cu20 1000 K persulfate 1000 Corrosion ditto 1000 ditto 2000 90 ditto 1000 ditto 5000 93 ditto 2000 ditto 2000 89 ditto 2000 ditto 5000 93 Tabel II (continued) KuDferquelle. pPm oxidizing agent. ppm% inhibition (1) Cu20 1000 KMnO4 1000 Corrosion ditto 2000 ditto 1000 44 ditto 2000 ditto 100 38 ditto 1000 Ca-iodate 1000 87 CuO 1000 Kr4n04 1000 90 ditto 1000 Ca-iodate 1000 91 ditto 1000 K-iodate 1000 95 ditto 1000 Na permanganate 1000 59 Cu (N03) 2 1000 Zn permanganate 1000 63 CuO 1000 K persulfate 1000 94 same as 1000 Na bromate 1000 92 Cu (N03) 2 1000 Na dichromate 1000 40 ditto 1000 ditto 5000 49 ditto 1000 Br2 1000 corrosion ditto 1000 J2 1000 ditto ditto 1000 J2 2000 6 ditto 1000 J2 5000 Corrosion ditto 1000 K persulfate 5000 ditto ditto 1000 ditto 1000 ditto ditto 1000 Na persulfate 1000 42 ditto 1000 ditto 5000 50 ditto 1000 Na chlorate 500 Corrosion ditto 1000 ditto 100 ditto ditto 1000 ditto 1000 ditto ditto 1000 ditto 5000 ditto ditto 5000 ditto 5000 88 ditto 1000 la-perchlorate 1000 corrosion ditto 1000 Na perborate 1000 30 ditto 1000 ditto 5000 35 ditto 1000 Sr permanganate 1000 63 ditto 2000 ditto 2000 91 ditto 5000 ditto 2000 95 ditto 1000 ditto 2000 67 ditto 1000 ditto 5000 79 Table II (continued) Copper source, ppm oxidizing agent, ppm% inhibition (1) Cu (NO3) 2 1000 Na peroxide 1000 Corrosion ditto 1000 Periodic acid 1000 20 ditto 1000 NH4 persulfate 1000 16 ditto 1000 ditto 2000 corrosion ditto 1000 ditto 5000 28 ditto 1000 Izano4 1000 72 ditto 1000 Ca-permanganate 1000 80 ditto 1000 Ca-iodate 1000 13 ditto 1000 K-m-periodate 1000 78 ditto 1000 H202 (80o / a) 5000 45 ditto 1000 H202 (30 ° Ró) 1000 37 ditto 1000 ditto 5000 68 ditto 1000 Cu-selenate 1000 corrosion ditto 1000 Na chlorate 1000 93 copper (II) - 1000 KMnO4 1000 77 chromate Cu (II) molybdate 2000 ditto 1000 70 Cu (II) tungstate 5000 ditto 1000 41 Cu (II) phosphide 5000 ditto 1000 28 CuC12 1000 ditto 500 92 ditto 1000 ditto 1000 84 ditto 1000 K-persulfate 500 92 ditto 1000 K-iodate 500 92 CuJ2 1000 KMnO4 1000 71 CuBr2 1000 same as 1000 77 For explanation the effectiveness of the corrosion inhibitor compositions of the invention on others technical solvents that are used in gas treatment plants a series of experiments were carried out using different solvents, the CuC03 or CuS, an oxidizing agent and one or more acidic gases will.

Procedure The conditions for testing the various solvents including the gas ratios, as volume ratios, are used in the following Tables described.

The saturated solutions are at the concentrations used Poured into 118 ml (4 oz.) bottles containing the inhibitors and 1020 mild steel coupons (prepared according to the general procedure) that have already been weighed placed in them. The bottles are closed with loosely fitting closures and placed in a pressure vessel, which is then at 125 0C at a total pressure of 2.8 atmospheres (40 psig) with either H 2 S or CO 2 or both for 16 hours. All inhibitor components are divided into parts of inhibitor component and one million parts of absorption medium specified.

Example 3 Solvent used: N-methyl diethanolamine 45% + Water 55% gas loading ratio: 0.2 vol.CO2 / vol.H2S CuCO; KMflO4 mm / year (npy) % Inhibition - - 0.98 (38.5) 0.0 1000 1000 0.29 (11.2) 71.0 1000 - 0.30 (12) 68.8 - 1000 0.16 (61) -58.5 Example 4 Solvent used: 45% diisopropanolamine, 35% sulfolane, 20% water Gas loading ratio: only saturated with H2S.

CuCO3 KMnO4 mm / year (mpy)% inhibition - - 0.47 (18.4) 0.0 25 25 0.28 (11.1) 39.7 50 500 0.08 (3.1) 83.1 500 500 0.14 (5.56) 70 2500 50 0.20 (8) 56.5 2500 2500 0.15 (5.74) 68.8 5000 5000 0.19 (7.46) 59.4 Example 5 Used Solvent: Diglycolamine: 600 / o [2- (2-aminoethoxy) ethanol] + 40% water Gas loading ratio: only saturated with H2S.

CuCO3 KMnO4 mm / year (mpy)% inhibition - - 0.52 (20.4) 0.0 50 50 1.0 (37.5) -84 50 2500 0.16 (6.21) 69.5 500 500 0.08 (3.22) 83.7 2500 50 0.08 (3.19) 84.3 2500 2500 0.08 (3.1) 84.8 5000 5000 0.10 (4) 80.4 Example 6 Solvent used: 3-Dimethylamino-1,2-propanediol 50% + 50% water Gas loading ratio: blowing in of CO for 30 min, blowing in H2i for 20 min, an external H2S gas pressure is applied to generate a pressure of 2.8 atmospheres (40 psig) CuCO3 KMnO4 mm / year (mpy) 16 inhibition - - (25.55) 0.0 1000 1000 0.28 (11.11) 56.5 Beisr, iel 7 Solvent used: Potassium carbonate Gas loading ratio / 50/50 C02 / H2S saturated CuC03 KMflO4 mm / year (mpy)% inhibition - - 0.70 (27.63) 0.0 1000 100 0.50 (20.0) 27.6 1000 1000 0.47 (18.6) 32.6 1000 2000 0.38 (15.1) 45.0 In the following three tables explain that a high CO 2 content, i.e. CO 2 alone or in Ratios above 1: 1 of C02: H2S in potassium carbonate or diethanolamine systems is not effectively inhibited. However, if the C02: H2S ratio is 1: 1 or less than 1: 1, e.g. 1 / 4.5, or H2S alone, an inhibition occurs.

Comparative Example 1 Solvent used: Potassium carbonate Gas ratio: CO2 CuS only S ° mm / year (mpy)% inhibition - - 1.07 (42) 0 500 - 1.42 (56) -30 - 500 2.04 (80.2) -86.6 100 100 1.53 (60.2) -40 500 1000 1.75 (69) -58 1000 1000 2.21 (87) -104 1000 3000 1.37 (54) -28 3000 1000 2.67 (lot) -144 Comparative example 2 Solvent used: 3096 diethanolamine (DEA) + 70% H20 gas ratio: 9/1 CO2 / H2S CuCO3 S ° mm / year (mpy)% inhibition - - 0.24 (9.3) 0 100 5000 0.58 (22.76) -148 500 5000 0.71 (27.8) -205 1000 5000 0.67 (26.2) -185 5000 5000 0.84 (33.02) -260 Example 8 Solvent used: 40% diethanolamine (DEA) + 60% H20 gas loading ratio: CO2 / H2S 1 / 4.5 CuCO3 KMnO4 mm / year (mpy)% inhibition - - 0.37 (14.35) 0.0 25 50 0.43 (16.8) -17.07 25 5000 0.29 (11.6) 19.2 500 25 0.20 (8.05) 44.0 500 1000 0.20 (7.91) 45.0 500 5000 0.22 (8.84) 38.4 1000 50 0.24 (9.27) 35.4 1000 2000 0.28 (11.0) 23.3 5000 50 0.26 (10.1) 29.6 Example 9 Used Solvent: 80% diethanolamine (DEA) + 20% H20 gas ratio: only saturated with H2S CuCO3 KMnO4 mm / year (mpy)% inhibition - - 0.44 (17.25) 0.0 1000 1000 0.14 (5.66) 67.2 1000 2000 0.16 (6.5) 62.3 1000 5000 0.15 (6.00) 65w2 2000 1000 0.17 (6.85) 60.0 2000 2000 0.12 (4.8) 72.2 5000 1000 0.18 (7.06) 59.07 5000 5000 0.17 (6.7) 61.2 From the above values it can be seen that the inventive Copper inhibitor composition is not a satisfactory inhibitor for diethanolamine solutions with less than 50% diethanolamine, when used to dissolve acid gases with high carbon dioxide content. Similarly, the inhibitor composition has limited usability for potassium carbonate solutions with more than 50 ° h CO2. Irenn however, as the H2S content increases, the inhibitory effect is evident.

B e i 8 P i e l 10 A gas scraper in a medium-sized refining plant Size measured at 121 0C (2500F) on the reboiler and with 17 to 19% aqueous monoalkanolamine absorbent, 22.7 kl (6000 US gallons), is badly corroded. On an electrical resistance corrosion test probe a corrosion rate of 0.95 mm / year (37.4 mpy) is measured at the reboiler outlet and 1.89 and 243 mm / year (74.6 and 95.5 mpy) corrosion rates are shown on coupons on Determined reboiler outlet or at the reboiler cross exchange. This corrosion rate will observed for a period of 5 days following the periodic shutdown.

On day 6, copper sulfide and sulfur become the aqueous amine solution continuously at a rate of about 22.7 kg (50 pounds) CuS every 6 to 8 days and given about 10.9 kg (24 pounds) of sulfur each day.

Starting on the 6th day of the experiment, from the day after the corrosion inhibitor was added, up to the 12th day the corrosion rates are 0.25, 0.12 and 0.41 mm / year (9.75, 4.77 and 16.08 mpy) at the probe of the reboiler outlet or the coupons at the reboiler outlet and at the reboiler cross exchanger. From the 12th day to the end of the The experimental corrosion rates are as follows: Day probe on re-coupons ooiler outlet reboiler outlet cross exchanger mm; year (mpy) mm / year (mpy) mm / year (mpy) 12-14 0.05 (1.85) 0.03 (1.26) 0.24 (9.44) 19-26 0.05 (1.85) 0.03 (1.25) 0 , 37 (14.6) 27-39 0.03 (1) 0.27 (10.5) o.35 (13.7) 39-45 0.03 (1) 0.12 (4.7) 0.46 (18.1) In several cases, the corrosion rate of the probe could be around 0.61 mm / year (24 mpy) by interrupting the addition of the inhibitor, then the inhibitor addition resumed. Within an hour after the addition resumed the probe showed a corrosion rate of 0.03 mm / year (1 mpy) or less at.

Method for determining corrosion rates and inhibitor efficiencies There are two methods that are used to determine the corrosion rate and also the Effectiveness of the copper-based inhibitors of the invention in various Places within the system can be used where solvents, such as monoethanolamine, to remove mixtures of acidic gases such as H2S and C02, from liquid or gas entrainment streams can be used. The first is in using metallic corrosion test coupons.

The second is that you have a metal resistance probe and an electrical resistance bridge, as used by Corrosion Monitoring Systems, Inc., 33 Lincoln Rd., Springfield, New Jersey 07081.

A very good probe, the F. Jefferies probe, is particularly useful since it is constructed entirely of metal and is essentially free from changes in sensitivity in temperature dependence. This probe is also made by the company mentioned above expelled. Another probe that too useful will manufactured by Magna Corporation, which also makes a resistor bridge, by which the corrosion detected on their probes can be determined.

It is not uncommon to have different sections on any gas treatment plant to have that is made of different metals. If, therefore, the rate of corrosion of a particular part of the system is to be determined, it is necessary, to measure the corrosion on a probe or coupon made of the same alloy and which is placed in the system at this point.

A useful coupon testing procedure for mild steel is the im the following procedure. Similar tests are available for other alloys.

First, a metal coupon of interest is machine made. A suitable size of 1 / 2x2x1 / 16 in. (1.27 cm x 1.27 cm x 0.16 cm) is used. A 0.95 cm (3/8 in.) Hole is drilled near one end so that the coupon can open a coupon holder can be mounted. This holder is put in its place and holds the coupon in electrical isolation from the base metal of the plant the location of the plant that is of interest.

Second, the machine-made coupon is cleaned, as at the general test procedure described, weighed exactly to 10 mg on a scale and attached to the coupon holder and placed in the solution of the system.

The entry of the corrosive environment occurs with one of several, well known procedures. With such a Procedure is the coupon and its holder passed through a packing seal and then through an open valve.

Third, the coupon becomes corrosive after being in the corrosive for several days Environment was removed. The exact number of days is not important, except times of 20 to 30 days are preferred based on the measured corrosion rates to attach greater importance. However, there can also be times that are as short as a day to be used.

Very good test times generally give higher obvious ones Corrosion rates than you would expect from trials during longer test periods became. The coupon is then cleaned again according to the following procedure.

The corroded metal coupon is in 15 ° oige HCl solution, the one contains good acid corrosion inhibitor. Then the same instructions, as indicated above for the initial cleaning of the coupon.

After the coupon has been weighed again, the difference is determined the weight is subtracted from the weight of the untested coupon. The original Weight minus the final weight is reported as weight loss in grams.

Using the following procedure, a corrosion rate for the solution-alloy system.

Corrosion rate. 0.183 x weight loss (mg) Impyj stripping factor x Coupon weight before (g) x (mm x 39.37) time (days) where: 0.183 is the conversion factor from mg / dm² / day (mdd) to mil penetration / year (mpy) for mild steel 1020).

Area in decimeters of the comparison coupon. Stripping factor = weight of the comparison coupon in grams (the stripping factor for the coupons used is 0.0176.) Fourth, the inhibitor is based on the present Registration described type and in the amount used according to the invention for the plant given and the new corrosion rate is determined by the procedure just described above certainly.

Fifth, the% inhibition for the particular inhibitor concentration, which is used is measured as follows: non-inhibited corrosion rate -inhibited Corrosion rate inhibition non-inhibited corrosion rate Sixth, the amount the inhibitor increased or decreased in order to obtain the desired corrosion protection, determined with the coupon procedure just described. Usually 0.13 mm / year (5 mpy) reached. The corrosion was in hot, corrosive environments decreased from 0.51 mm / year (20 mpy) to values below 0.03 mm / year (1 mpy) according to this procedure which was found to be in good correlation with the inspection of the installation and the measurements made on specific elements be carried out by a state-approved boiler inspector.

The rate of corrosion of the solution in the plant can also be measured using 14 metal probes such as those previously described. In this case, the probe is built in such a way that it can use the coupon as described above, can replace. The probe can be used directly as it was received from the manufacturer, used if or it can be blown off with sand before shipping be cleaned with uninhibited HCl, as above for the coupon cleaning procedure described.

After the corrosion probe has been cleaned, it will go into the solution set in the system at the point in question and the temperature can rise balance. A resistance reading is made with a resistance bridge.

The bridge sold by the probe manufacturer is well suited. Provides a graph of the resistance probe versus time the corrosion rate can be calculated from the slope of the curve using the formula, which is supplied by the probe manufacturer.

When the non-inhibited corrosion rate has been determined, the Inhibitor added according to the invention and the corrosion rate is determined and the measurements described above are carried out.

It often happens that less inhibitor is required than that Seem to indicate laboratory tests. In fact, it is found that the laboratory tests indicate the ability of the inhibitors to passivate new or heavily corroded metals, and that once passivation has been achieved, significantly less inhibitor is required to keep corrosion to a minimum. Furthermore, test facilities explain and sales trials or field trials, the method required for in-series measurements which indicate the potential for corrosion before actual corrosion. Such an in-line system would be necessary for larger concentrations of inhibitors.

It is therefore desirable to have a technical Provide inhibitor composition for starting the plant and for passivation the metal surfaces of the system are used during normal operation can, and to have a method available with which the appropriate Times for the addition of the inhibitor can be determined during the operation of the system could.

The metal surfaces of the gas treatment system are effectively passivated and the appropriate times for the correct amounts of inhibitor composition to be added are determined by going into the absorbent medium or product by reaction of monoalkanolamine at 21 to 1000C with sulfur and an inorganic sulfide and an oxygenating agent is formed, together with copper or a copper salt, sulfide or oxide is added over 0.1 to 20 hours until the resulting mixture is stable is when it is diluted with water. The sulfur or sulfur compounds are in a ratio of 3 to 30 parts by weight copper / Gesr.-part sulfur and present in an amount of 1 to 40% by weight based on the total composition. This composition becomes the absorbent medium in the gas treatment unit in given in an amount sufficient to provide at least 0.0091 g (0.00002 pounds) of copper and at least 0.045 g (0.0001 pounds) sulfur / 454 g (pounds) absorbent medium / day can be obtained.

The reaction for preparing the composition becomes appropriate and preferably in an alkanolamine, e.g. B. monoethanolamine performed, although it can also be carried out in another amine solvent, which in in the gas treatment industry, e.g. diethanolamine, at ambient temperature stable, non-precipitating up to about 1000C for a time sufficient Result in composition. Times from 0.1 to 20 hours are expediently used. The products formed in this way can be converted into an absorbent stream from the gas treatment plant, such as an aqueous alkanolamine as used in U.S. Patent 3,349,544, be admitted. The addition can be continuous or batch take place in amounts sufficient to substantially affect the circulating absorbent medium to be kept non-corrosive to the metal surfaces of the system. In particular will give the product so that a corrosion protection for the parts of the system which is sensitive to elevated temperatures, e.g.

93 0C (2O00F) and above, mainly the regenerator, wherein the acid gases are released. The viscosity of the inhibitor can vary Addition of small amounts of water to facilitate handling and additions is discontinued will.

The amount of inhibitor composition used can vary widely from 0.0091 g (0.00002 pounds) / 454 g (pounds) absorbent (20 ppm) copper equivalent / day up to 9.1 g (0.02 pounds) / 454 g absorbent (20,000 ppm) copper equivalent / day and 0.045 g (0.0001 pounds) / 454 g absorbent (100 ppm) sulfur equivalent / day to 91 g (0.2 pounds) / 454 g absorbent (200,000 ppm) sulfur equivalent / day vary. The lower Concentrations range from about 20 to 100 ppm copper equivalent / day, and about 100 to about 1000 ppm sulfur equivalents / day are in the technical operation a system that has been in operation with the inhibitor for several weeks is. The higher concentrations, which range from about 500 to about 2000 ppm Copper equivalents / day and about 5000 to about 20,000 ppm sulfur equivalents / day are the quantities that may be required to maintain the non-corrosive condition as found with a metal resistance corrosion probe will.

Indeed, this is true regardless of whether the inhibitor is currently has been added to the system, or whether the inhibitor has been in use for some time and the plant is restarted after a shutdown.

The advantage of the inhibitor composition of the invention is that Possibility of adding inhibitor to a system quickly and in measured quantities. The worker can follow the effect of the addition and the appropriate amount of inhibitor add to the metal surfaces of the system that is in contact with the absorbent, to passivate.

EXAMPLE 11 Preparation of the inhibitor To a stirred and 14.3 is added to a heated kettle containing 30.6 kg (67.5 lbs) of monoethanolamine kg (31.5 lbs) sulfur. The mixture is heated at 90 ° to 1000 ° C. for 1 hour while stirring. Then 1.36 kg (3 lbs) of copper metal in the form of shredded copper wires added with stirring, and then at 90 to 1000C with stirring a heated for another hour. The solution obtained in this process is filtered and can cool to room temperature without stirring. It remains free from precipitation or solids. The mixture is against repeated heating and freezing cycles stable between 100 and -500C.

By adding 15So water, no free sulfur is precipitated the sulfur can still be extracted with carbon disulfide. This inhibitor solution is used as a stock solution for periodic addition to the absorbent in the system, as described below.

The inhibitor is placed in the rich monoethanolamine stream of a sour gas conditioning test facility initiated where acid gas (natural gas containing high concentrations of H2S and C02) is processed. The operating conditions for the plant, the rate for inhibitor introduction and corrosion rates are as follows.

Operating conditions H2S / C02 (ratio). 9: 1 load 0.6 to 0.8 Mole acid gas / mole MEA¹ IEA1 concentration 30 wt.% In water flow rate 0.95 to 1.13 l / min (Q, 25-0.3 US gallons / min) MEA approach 38.8 1 (10 US gal) absorber 27-660C (Gradient) (80-1500F) Stripping reboiler 111 to 1160c (232-240 ° F) inhibitor addition continuous 1 tEA = monoethanolamine. In the course of 168.5 h the corrosion rate is held at about 0 mil penetration per year (mpy) (mm x 39.37) as determined by a Corrosometer with the amounts of inhibitor solution given in Table III below.

Table III Duration Amount of Injected Equivalent Corrosion Rate¹ (h) ter, liquid preparation (ml / day) (mm) preparation (ml) 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 1 mm penetration / year, determined with an electrical resistance probe.

In a manner similar to that given above, 2.04 kg (4.5 lbs) of CuS used in place of the Cu metal. The results are similar to those listed above.

3 e i s p i e 1 12 The following experiment uses the same test facility operated at lower daily inhibitor injection rates to determine whether corrosion occurs and, if it does, major additions of inhibitor Bring the system back to a more passive (less corrosive) state Became. Table IV illustrates these results. The first eight values show the results of Example 1, and the remaining values show the results of two lower daily rates followed by two larger rates. The lower rates of 0.000011 copper and 0.000132 sulfur allow corrosion, whereas the Return to 0.000056 copper and 0.000674 sulfur the non-corrosive or passive State of the system is restored.

Table IV Time Injected Equivalent Daily Rate Condition of (h) Preparation daily rate [g / day (lbs / day)] Plant (ml) (ml / day) Cu S 27 143 127 0.032 (0.00007) 0.38 (0.00084) no corrosion 24 88 88 0.022 (0.000048) 0.26 (0.00058) ditto 23 184 192 0.045 (0.00010) 0.57 (0.00126) ditto 25 155 148 0.036 (0.00008) 0.44 (0.00098) ditto 21.5 48 53 0.014 (0.00003) 0.16 (0.00035) ditto 24 43 43 0.011 (0.000025) 0.14 (0.00030) ditto 24 216 216 0.054 (0.00012) 0.64 (0.00142) ditto 6 34 136 0.033 (0.000075) 0.41 (0.00090) ditto 12 10 20 0.005 (0.000011) 0.06 (0.000132) Corrosion 12 10 20 0.005 (0.000011) 0.06 (0.000132) same as 27 115 102 0.025 (0.000056) 0.31 (0.000674) no corrosion 9 50 133 0.033 (0.000073) 0.40 (0.00088) same as above

Claims (2)

Claims 1. Corrosion inhibitor composition for ferrous metal and its alloys upon contact with stripping absorbent solutions for acid gas prepared from solvents selected from the group comprising (a) alkanolamines of the formula in which each of the substituents R1 and R2 is hydrogen or -C (R3) 2C (R3) 2-OH and fl3hydrogen or a C1-3-alkyl group, (b) tetrahydrothiophene-I, I-dioxide, (c) potassium carbonate or (d ) Diglycolamines, each alone or together with one or more of the other than aqueous solutions or glycol solutions, characterized in that the inhibitor composition essentially contains (e) a source of copper ions, selected from copper metal, copper sulfide and copper salts, and (f) a source of sulfur atoms selected from (1) sulfur or (2) hydrogen sulfide and / or COS together with an oxidizing agent which forms sulfur atoms in solution, at least a part of which is polysulfide, under the operating conditions in an acid-gas stripping system the thermal regeneration process can be used to separate the bound acid gas from the strip absorbent, and a solvent for (e) and (f) selected from (a), (b), (c) or (d). 2. Corrosion inhibitor composition for ferrous metal, characterized in that it contains (a) copper as copper metal, copper sulfide or copper salt and (b) an oxidizing agent which converts the sulfur into sulfur atoms and / or copper in the presence of sulfur or a sulfur-containing compound Oxidizes copper ions, and an alkanolamine of the formula in which each of the substituents R1 and R2 is hydrogen or -C (R3) 2C (R3) 2-OH and R3 is hydrogen or a C1-3-alkyl group.