J Kittel

Elisabeth Fleury

Geraldine Laborie

Bruno Vuillemin

Roland Oltra

Corrosion in alcanolamines for natural gas treatment -High temperature experiments in lean and rich conditions

ou non, émanant des établissements d'enseignement et de recherche français ou étrangers, des laboratoires publics ou privés.

Introduction 1.Basics of acid gas removal by alkanolamines

Throughout the petroleum chain, the treatment steps are nearly always designed to purify the fluids, separate various components and eliminate undesirable species, in particular the two acid gases carbon dioxide (CO 2 ) and hydrogen sulfide (H 2 S). Treatments to remove CO 2 and H 2 S from natural gas are often implemented on the production site. At the other end of the chain, the refinery gases may also need to be stripped of these acid gases. Lastly, these separation treatments are becoming increasingly important in the fight against greenhouse gas emissions and might be used in a near future for the post-combustion capture of CO 2 in combustion fumes from industrial processes [START_REF]Current and future corrosion challenges for a reliable and sustainable development of the chemical, refinery, and petrochemical industries[END_REF]. The most widely used process in all these applications uses alkanolamine-based chemical solvents (e.g. MEA, monoethanolamine, DEA, diethanolamine, MDEA, methyldiethanolamine) capable of reacting preferentially with CO 2 and H 2 S. Figure 1 provides a simplified process flow description of this type of treatment unit. The main components and the operating principles are the same in the three broad domains concerned: natural gas processing, treatment of refinery gases and post-combustion CO 2 capture. The gas to be treated is introduced in the unit at the bottom of the absorber where it comes into contact with the solvent. The acid gases (CO 2 and/or H 2 S) react and are absorbed by the solvent according to reactions 1 to 6 below. The reaction with H 2 S, which is the same irrespective of the type of amine considered, consists of direct proton transfer (Reaction 1), where R 1 , R 2 and R 3 represent alkyl groups or a hydrogen atom.

1 2 3 2 1 2 3 R R R N H S R R R NH HS + - + ⇔ + (Reaction 1)
The reaction with CO 2 is slightly more complex. Two different mechanisms may be involved. A first reaction may occur, involving the successive formation of carbonic acid and bicarbonate (Reaction 2 and Reaction 3), followed by direct proton transfer identical to that observed for H 2 S (Reaction 4).

2 2 2 3

CO H O H CO + ⇔

(Reaction 2)

2 3 3

H CO HCO H

-+ ⇔ + (Reaction 3)

1 2 3 1 2 3 H R R R N R R R NH + + + ⇔ (Reaction 4)
This mechanism may occur for all types of amine. The global kinetics is slow, however, since it is limited by dissociation of carbonic acid into bicarbonate (Reaction 3).

For the primary and secondary amines, which have hydrogen bond to the nitrogen, a second mechanism is possible.

2 1 2 1 2 CO R R NH R R N HCOO + - + ⇔ + (Reaction 5) 1 2 1 2 1 2 1 2 2 R R N HCOO R R NH R R NCOO R R NH + - - + + + ⇔ + (Reaction 6)
This second reaction mechanism is generally much faster than the CO 2 hydrolysis reaction (Reactions 2 to 4). Reaction 5 and 6 forms the well-known amine carbamate. For the primary and secondary amines, there is little difference in the reaction kinetics between CO 2 and H 2 S. For the tertiary amines, however, unable to form the carbamate, the reaction kinetics with H 2 S is much faster than with CO 2 . This property is put to good advantage to give some solvents selectivity between CO 2 and H 2 S.

At the liquid output at the bottom of the absorber, the solvent is therefore enriched in acid gas according to one or more of reactions 1 to 6: loaded solvent is rich amine. At the top of the absorber, the gas has been stripped of its undesirable components CO 2 and/or H 2 S. The rich amine is then pre-heated by a heat exchanger then fed into the top of a regeneration column. In column, the solvent is heated to high temperature by the reboiler, up to about 130°C. The heat transferred t o the solvent at high temperature releases the dissolved acid gases. This is due to the fact that the equilibria of reactions 1 to 6 are shifted to the left at high temperature and low pressure. At the liquid output of the regenerator, the solvent is hot (about 130°C) and contains less acid gas: the off-loaded solvent is lean amine. The solvent is then cooled by the feed/bottom heat exchanger, trim cooled and sent back to the top of the absorber to start a new cycle. The acid gases are collected at the top of the regenerator, they are cooled down for their suitable processing.

Corrosion mechanisms and influent parameters

In such complex units, numerous pieces of equipment are exposed to equally numerous types of corrosion. We can nevertheless adopt the classification proposed by Nielsen [START_REF] Nielsen | Corrosion in refinery amine systems[END_REF], who identifies:

-wet acid gas corrosion, -amine solution corrosion.

Wet acid gas corrosion may be encountered in all parts of the unit in contact with an aqueous phase with a high concentration of dissolved acid gases CO 2 , H 2 S, as well as NH 3 and HCN for refinery units. This type of corrosion is found primarily in zones where the gaseous phases have high concentrations of acid gases and where water may condense, mainly at the bottom of the absorber and the top of the regenerator. For gas containing mostly CO 2 , parts of the installation made from carbon steel may suffer fast CO 2 corrosion, up to several mm/year. In the presence of H 2 S, this uniform corrosion is generally lowered by the formation of a protective iron sulfide layer. A minimum H 2 S/CO 2 ratio of 1/20 is often considered as sufficient to avoid risks of CO 2 corrosion [START_REF]API recommended practice n°945, Avoiding envir onmental cracking in amine units[END_REF][START_REF] Baptista | Expert system for corrosion monitoring and control in gas treatment units[END_REF]. In the presence of H 2 S however, specific cracking phenomena may also be encountered (hydrogen embrittlement, HIC, SSC, etc.). In the presence of HCN and/or NH 3 , the risks of cracking are also increased.

The second type of corrosive media found in acid gas removal units is the amine solution itself. Generally, amines are not intrinsically corrosive, since they associate both high pH and low conductivity. They may nevertheless become corrosive when they absorb CO 2 or H 2 S or when exposed to degradation. Furthermore, since the treatment units operate in semi-closed circuit, the solvent may become enriched with possibly corrosive degradation products.

No consensus has yet been reached concerning the mechanisms of corrosion by amine solutions. The models proposed vary depending on the type of amine (in particular, primary, secondary and tertiary), the H 2 S/CO 2 ratio in the gas to be treated, the possible presence of oxygen either as contaminant in the circuit or as component of the input gas (e.g. CO 2 capture in fumes). For more information on specific corrosion models, the reader may refer to the relatively extensive bibliography on this subject [START_REF] Nielsen | Corrosion in refinery amine systems[END_REF][START_REF] Kohl | Gas purification[END_REF][START_REF] Kosseim | Corrosion-Inhibited Amine Guard St Process[END_REF][START_REF] Dupart | Understanding Corrosion in Alkanolamine Gas Treating Plants. 2. Case histories show actual plant problems and their solutions[END_REF][START_REF] Dupart | Understanding Corrosion in Alkanolamine Gas Treating Plants .1. Proper Mechanism Diagnosis Optimizes Amine Operations[END_REF].

We may nevertheless identify some systematic trends governing the corrosiveness of acid gas chemical solvents. Acid gas loading and temperature are usually considered as the most important factors. The acid gas loading (α) is defined as the quantity of acid gas absorbed by a defined quantity of solvent and is often expressed in moles of acid gas per mole of amine. Increasing the acid gas loading increases the corrosiveness of amine solutions [START_REF] Dupart | Understanding Corrosion in Alkanolamine Gas Treating Plants. 2. Case histories show actual plant problems and their solutions[END_REF][START_REF] Dupart | Understanding Corrosion in Alkanolamine Gas Treating Plants .1. Proper Mechanism Diagnosis Optimizes Amine Operations[END_REF][START_REF] Bich | Corrosion in MDEA sour gas treating plants: correlation between laboratory testing and field experience[END_REF][START_REF] Veawab | Corrosion behavior of carbon steel in the CO2 absorption process using aqueous amine solutions[END_REF]. Temperature generally has an extremely important effect on corrosion phenomena since most electrochemical reactions involved are thermally activated. It is common practice in industry to consider that the corrosion rate is doubled when the operating temperature increases by 10°C to 20°C. For gas treatment units, the effect of temperature is relatively difficult to asses on an individual basis. Temperatures vary widely in the installation, with extreme values ranging from 40°C in the absorber up to 130°C in th e reboiler. However, these temperature variations have a significant effect on the chemistry of the solution, in particular the acid gas loading. Taking into account both the loading and the temperature, we may consider that the main corrosion risks are encountered in areas with high loading and high temperatures [START_REF] Dupart | Understanding Corrosion in Alkanolamine Gas Treating Plants .1. Proper Mechanism Diagnosis Optimizes Amine Operations[END_REF][START_REF] Bonis | A critical look at amines: a practical review of corrosion experience over four decades[END_REF]. These conditions are generally found in the rich amine line after the heat exchanger and up to the regenerator input.

The type of amine is also one important factor. Usually, primary amines (e.g. MEA) are the most corrosive, secondary amines (e.g. DEA) slightly less and tertiary amines (e.g. MDEA) exhibit the lowest risks of corrosion [START_REF] Dupart | Understanding Corrosion in Alkanolamine Gas Treating Plants. 2. Case histories show actual plant problems and their solutions[END_REF][START_REF] Dupart | Understanding Corrosion in Alkanolamine Gas Treating Plants .1. Proper Mechanism Diagnosis Optimizes Amine Operations[END_REF][START_REF] Veawab | Corrosion behavior of carbon steel in the CO2 absorption process using aqueous amine solutions[END_REF][START_REF] Dupart | Comparison of laboratory and operating plant data of MDEA / DEA blends[END_REF][START_REF] Dupart | Comparing laboratory and plant data for MDEA/DEA blends[END_REF][START_REF] Blanc | The part played by degradation products in the corrosion of gas sweetening plants using DEA and MDEA[END_REF][START_REF] Veldman | Alkalonamine solution corrosion mechanisms and inhibition from heat stable salts and CO2[END_REF]. Amine concentration also has an influence on corrosion. Excessively high amine concentrations should generally be avoided with C steel facilities. Nevertheless, the results obtained from the few laboratory studies conducted on the effect of amine concentration on corrosiveness vary widely, between a marked effect [START_REF] Dupart | Understanding Corrosion in Alkanolamine Gas Treating Plants .1. Proper Mechanism Diagnosis Optimizes Amine Operations[END_REF][START_REF] Veawab | Corrosion behavior of carbon steel in the CO2 absorption process using aqueous amine solutions[END_REF] and a moderate or null effect [START_REF] Guo | The effect of corrosion product layers on the anodic and cathodic reactions of carbon steel in CO2-saturated MDEA solutions at 100 degrees C[END_REF][START_REF] Vazquez | The effect of diethanolamine solution concentration in the corrosion of steel[END_REF].

The concentration in degradation products and contaminants can significantly influence corrosion reactions. A distinction must be made between basic and acidic degradation products. Basic amine degradation products mainly result from chain reactions between amine and CO 2 , for example the following compounds: HEOD (3-(2-hydroxyethyl)-2-oxazolidone), BHEP (N,N'-bis(2-hydroxyethyl)piperazine), THEED (N,N,N'-tris(2-hydroxyethyl)ethylenediamine). The studies on corrosiveness by these degradation products date back a number of years, the general conclusion being an absence of specific corrosiveness [START_REF] Dupart | Comparing laboratory and plant data for MDEA/DEA blends[END_REF][START_REF] Blanc | The part played by degradation products in the corrosion of gas sweetening plants using DEA and MDEA[END_REF]. Most acidic degradation products result from reactions with oxygen. The main products include salts of oxalic, glycolic, formic and acetic acids, which are stronger than carbonic acid. As a result these salts are not thermally regenerated in the process, hence their name: Heat Stable Salts (HSS).

The effect of these products on corrosion has been well documented through laboratory tests; they increase corrosion of carbon steel [START_REF] Rooney | Effect of heat stable salts on MDEA solution corrosivity[END_REF][START_REF] Rooney | Effect of heat stable salts on MDEA solution corrosivity .2[END_REF][START_REF] Tanthapanichakoon | Electrochemical investigation on the effect of heat-stable salts on corrosion in CO2 capture plants using aqueous solution of MEA[END_REF].

Finally, the solvent flow rate and conditions favourable to turbulence (gas flash, gas injection zones, etc.) may cause risks of erosion-corrosion. This type of corrosion is specific to carbon steels, since stainless steel grades are far more resistant. This type of corrosion is probably aggravated when the content of degradation products becomes too high: as indicated above, some of these products have a chelating effect on iron and may favour more efficient and faster dissolution of the protective deposits exposed to erosion [START_REF] Nielsen | Corrosion in refinery amine systems[END_REF][START_REF]API recommended practice n°945, Avoiding envir onmental cracking in amine units[END_REF][START_REF] Bich | Corrosion in MDEA sour gas treating plants: correlation between laboratory testing and field experience[END_REF][START_REF] Al-Zahrani | Methodology of mitigating corrosion mechanisms in amine gas treating units[END_REF].

Experimental study 2.1 Objectives

This experimental work follows some return of experience in sweet DEA treatment plants, where corrosion of some stainless steel grades had been observed [START_REF] Bonis | A critical look at amines: a practical review of corrosion experience over four decades[END_REF][START_REF] Kittel | Corrosion control on amine plants: new compact unit design for high acid gas loadings[END_REF]. Thus, the objective of the study is to compare the corrosiveness of different amines, and for different steel grades. Laboratory experiments were performed in hot rich and lean solutions of secondary and tertiary amines. Degraded DEA solution sampled in a treatment plant was also available, and used for tests in the same conditions.

Experimental methods

The first series of experiments was carried out in an industrial DEA solution (4.5 M), sampled in a sweet gas treatment plant. A complete analysis of this solution was performed before it was used in the laboratory for corrosion tests. The results are presented in Table 1. Even though this DEA solution had a dark brown colour, indicating a strong degradation, the concentration in degradation products remained just below usual limits given in the literature (e.g. ref. [START_REF] Rooney | Corrosion in alkanolamine plants: causes and minimization[END_REF]), even though the total HSS content was close to maximum acceptable values (e.g. ref. [START_REF] Kittel | Corrosion control on amine plants: new compact unit design for high acid gas loadings[END_REF]), . For each test solution, two corrosion tests were carried out successively, using the same batch of solution. The first experiment was carried out in a rich solvent (α = 0.45) at 110°C. The second experiment was carried o ut in a lean solvent (α < 0.1) at 120°C. This lean solvent was obtained by N 2 purging during at least 24 hours. Therefore, the lean solutions already contained dissolved metals and some degradation products. In order to obtain rich solutions at the desired CO 2 loading, saturated solutions were first prepared by purging CO 2 for approximately 12 hours at ambient temperature. This saturated solution was then mixed with a lean solution. CO 2 titration was checked after mixing, to ensure that the target loading was reached. The method used to determine the quantity of absorbed CO 2 consisted in a volumetric measurement after adding an excess amount of hydrochloric acid to a sample of the solution [START_REF] Williams | Official Methods of Analysis of AOAC International[END_REF]. Acid gas loading was then expressed as the ratio between the number of moles of CO 2 and the number of moles of amine.

All experiments were carried out in a 1L autoclave made of Hastelloy C276, and were performed for four weeks.

The autoclave was first filled with the test solution at the set CO 2 loading. It was then closed and heated to the desired temperature. During this heating, a new equilibrium between the gaseous and dissolved CO 2 was established. Nevertheless, the gaseous volume in the autoclave was sufficiently low to consider that the loading remained unchanged. Furthermore, after all corrosion tests CO 2 titration was systematically performed to ensure that the loading did not significantly evolve during the experiment.

Corrosion coupons were made of AISI 1020, AISI 304L and AISI 316L. Those grades are representative of C steel and of austenitic stainless steel used in gas treatment units. The chemical composition is given in Table 2. The specimens were cut from thin plates into 26 mm x 26 mm squares. Before each experiment, all specimens were ground with 600 grit SiC paper, degreased with ethanol and rinsed with deionised water. The specimens were mounted to the rotating axle with polymer spacers to prevent galvanic coupling effects. Stir speed was maintained constant, and the peripheral speed of the specimen was close to 0.4 m/s (< 1.3 feet / s) . Before final weighing, each specimen was rinsed with distilled water and dried. When needed, corrosion scales were removed using a plastic brush and/or by a chemical cleaning method, as proposed in ASTM G1 standard [START_REF]ASTM G1-03[END_REF]. Analysis of the test solutions were performed in order to determine the concentration of dissolved metals.

Results

Corrosion rates and dissolved metals measured after the experiments are gathered in Table 3 to Table 6. Obviously, active corrosion of AISI 304L can be encountered in rich DEA solutions.

The effect is more pronounced in the industrial DEA solution, indicating some probable effect of degradation products. For this solution, some uniform corrosion of 316L is observed, even if the corrosion rate remains moderate (65 µm/year). This tendency is confirmed by the high level of soluble metals in the rich DEA solutions after the experiments. According to work done by other researchers [START_REF] Dupart | Comparing laboratory and plant data for MDEA/DEA blends[END_REF], this indicates that the solution contains chelating agents, capable of complexing chromium and nickel constituting the protective passive film of AISI 304L. This complexing power is increased in the industrial DEA solution compared to the laboratory DEA solution, which indicates that degradation products should play an important role.

Carbon steel corrosion follows a slightly different trend in the rich DEA solutions. Even if the content of soluble iron is also quite high, the corrosion rate remains moderate, in the same range as that of AISI 304L. However, a thick and dense iron carbonate layer was observed at the surface of the carbon steel specimens after the experiments (Figure 2). This layer might have had some protective action.

Corrosion in rich MDEA and in rich MDEA / DEA is radically different than in rich DEA. In the former solutions, corrosion rates of both stainless steel and carbon steel remained extremely low. Nevertheless, surprisingly high levels of soluble chromium and nickel were measured, in a comparable range than in DEA solution. Some chelating compounds should then also be expected in MDEA and in MDEA + DEA blend. This also indicates that metal solubility might not always be a good indicator of solution corrosiveness, as already mentioned by Rooney and co-workers [START_REF] Rooney | Why metals solubility may not be a good indicator of corrosion in alkanolamine systems[END_REF].

In lean DEA solutions, both stainless steel grades exhibited perfect corrosion resistance. During these experiments, soluble chromium and nickel content also decreased (the initial concentration corresponding to the concentration measured at the end of the experiment in rich condition), indicating some precipitation. It is therefore probable that the complexing tendency is not only related to degradation products, but also to some carbonic species. On the other hand, in MDEA and MDEA / DEA solutions, soluble chromium and nickel levels remained constant or increased slightly. The difference might then be associated with amine carbamate, which forms only by reaction between CO 2 and primary and secondary amine, but not with tertiary amine like MDEA. The most marked difference between experiments in lean solvents was observed for the carbon steel coupons. In DEA solutions, the corrosion rate of carbon steel appeared more severe than in rich solution. In that case, no protective scale was observed at the steel surface. In the lean solvent, the lower concentration in carbonic species induces a higher solubility of iron, thus less scaling tendency. This assumption is confirmed by the chemical analysis, revealing extremely high levels of soluble iron. Unexpectedly, we also observed faster corrosion of carbon steel in the laboratory lean DEA solution than in the industrial solution. This result might be the consequence of a poor regeneration of the test solutions before the experiment. Indeed, the procedure only ensured that the lean solvent contained less than 0.1 mol of CO 2 / mol of amine. At such levels, a sufficiently high residual oxidizing power might be found. This result also shows that the higher HSS level in the industrial solution is not sufficient to generate a higher corrosiveness.

Conclusions

These experiments confirm that DEA solutions used for acid gas treatment present severe risks of corrosion.

In hot rich conditions, austenitic stainless steel grade 304L might suffer depassivation and severe uniform corrosion. The mechanism probably involves some chelating agents, capable of complexing nickel and chromium. These specific risks are increased with acid gas loading and with concentration in degradation products. Carbon steel also suffers corrosion in DEA solutions. In our experimental conditions, corrosion was more severe in lean than in rich solvent. In the latter case, precipitation of iron carbonate was observed at the surface of the specimens, and provided some protection. This phenomenon is however highly dependent on the hydrodynamics, and it would be extremely hazardous to rely on it in a gas treatment plant. In lean DEA solutions, the concentration in carbonate species was too low to allow for iron carbonate scale formation, and severe uniform corrosion was observed.

MDEA and MDEA / DEA solutions showed much less risks of corrosion for stainless steel grades and also for carbon steel. Contrary to tertiary amine, DEA has the faculty to form amine carbamate by reaction with CO 2 . This molecule has probably some role in the increased corrosiveness and solubility of metals. However, the levels of dissolved metals after corrosion tests in MDEA and MDEA / DEA remained high as compared with the observed corrosion rates. In that sense, metals solubility should not be regarded as a universal indicator of the solution corrosiveness.

The last important result of this work concerns the variability of metals solubility between rich and lean solutions. In a closed loop system of the process, one could then expect to dissolve iron in the lean sections, and precipitate iron carbonate in the rich sections. This also highlights the importance to select with care the sampling points, when an analytic survey of the solvent composition is made.

Figure 1 :

 1 Figure 1: Simplified diagram of an alkanolamine acid gas removal unit

Figure 2 :

 2 Figure 2: iron carbonate layer formed at the surface of AISI 1020 coupon after 4 weeks exposure in rich DEA at 110°C.

Table 1 :

 1 Analysis of the industrial DEA solution used for corrosion tests.

	Family	product	concentration	Family	product	concentration
	Amine	DEA	477 g/L	HSS	formiates	43 mg/L
	acid gas CO2	8 mg/L		acetates	496 mg/L
	anions	chloride	4 mg/L		propionates 22 mg/L
		thiosulfate	< 10 mg/L		oxalates	< 10 mg/L
		sulfate	42 mg/L		glycolates	< 10 mg/L
	cations	iron	667 mg/L	basic	MEA	0.02 wt. %
		chromium	65 mg/L	degradation	MAE	0.002 wt. %
		nickel	7 mg/L	products	BAE, BEA,	< 0.01 wt. %
					DEP
		molybdenum 13 mg/L		HEED	< 0.2 wt. %
		sodium	15 mg/L		HEP	< 0.01 wt. %
		manganese 1 mg/L		others	1.1 wt. %
	Other test solutions were prepared with analytical grade DEA and MDEA and
	deionised water.

Table 2 :

 2 Chemical composition (wt. %) of steels used for the corrosion tests.

	Fe	Cr	Ni	Mo	C	Mn	Si	S
	AISI 1020 bal.	0.01	0.01	<0.005 0.17	0.75	0.01	0.003
	AISI 304L bal.	19.14	9.27	022	0.02	1.62	0.04	0.001
	AISI 316L bal.	16.86	10.30	2.18	0.02	1.34	0.45	0.002

Table 3

 3

	: Corrosion rates (µm/year) for different steel grades in rich (α = 0,45 at 110°C) solutions of
	different amines.
		316L 304L 1020 Observation
	Industrial DEA 45%, rich	65	130	160 FeCO 3 scale
	DEA 40%, rich	15	80	150 FeCO 3 scale
	MDEA 40% + DEA 5%, rich	< 5	10	30
	MDEA 40%, rich	< 5	< 5	20

Table 4 :

 4 Corrosion rates (µm/year) for different steel grades in lean (α < 0,1 at 120°C) solutions of

	different amines.
		316L 304L 1020 Observation
	Industrial DEA 45%, lean	< 5	< 5	485
	DEA 40%, lean	< 5	< 5	1790
	MDEA 40% + DEA 5%, lean	< 5	< 5	25
	MDEA 40%, lean	< 5	< 5	11

Table 5 :

 5 Solubility of different ions (mg/L) measured after four weeks of corrosion testing in rich (α =0,45 at 110°C) solutions of different amines.

	Fe	Cr	Ni

Table 6 :

 6 Solubility of different ions (mg/L) measured after four weeks of corrosion testing in lean (α < 0,1 at 120°C) solutions of different amines.

	Fe	Cr	Ni

Acknowledgements

The authors would like to thank M. Bonis (Total) and G. Perdu (Prosernat) for helpful discussion in the preparation of this manuscript. A. Bonneau is also acknowledged for his active participation in the experimental part of the work.


Elisabeth Fleury
email: elisabeth.fleury@ifp.fr

Jean Kittel
email: jean.kittel@ifp.fr

Bruno Vuillemin
email: bvuillem@u-bourgogne.fr

Roland Oltra
email: oltra@u-bourgogne.fr

François Ropital
email: francois.ropital@ifp.fr

Corrosion in amine units for acid gas treatment : a laboratory study

Keywords: Corrosion, alkanolamine, DEA, gas treatment 2

ou non, émanant des établissements d'enseignement et de recherche français ou étrangers, des laboratoires publics ou privés.

Introduction

Basics of acid gas absorption by alkanolamines

The primary function of alkanolamine units is to remove acid gases, usually hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ).

A typical process flow diagram of alkanolamine units is given in Figure 1.

Figure 1: Process flow diagram of gas absorption system [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF].

The acid gas absorption process is performed through the following steps. The raw gas enters the unit at the bottom of the absorber column, where acid gases are absorbed by the lean amine solvent that flows countercurrent to the raw gas. The treated gas is the overhead product while the rich amine solution flows from the bottom of the absorber to the lean/rich cross exchanger where it is heated before entering the regenerator column. In the regenerator, acid gases are stripped from the rich amine by heat and steam produced by the reboiler. Acid components leave off at the top of the regenerator and go to the overhead condensers and the reflux accumulator. The hot lean amine from the bottom of the regenerator is cooled via the lean/rich heat exchanger prior to re-entering the absorber.

The main reactions between CO 2 and amines are given below.

Carbon dioxide reacts with amines by the following reactions where R designates an organic group. These reactions can lead to the formation of carbamates (R.1), bicarbonates (R.2) and carbonates (R.3):

- -- - + + + + + + + + ⇔ ⇔ ⇔ ⇔ + + + + NCOO R R NH R R CO NH R R 2 - -- - + + + + + + + + ⇔ ⇔ ⇔ ⇔ + + + + + + + + 3 2 1 2 2 2 1 HCO NH R R O H CO NH R R (R. 2) - -- - + + + + - -- - + + + + ⇔ ⇔ ⇔ ⇔ + + + + 2 3 3 3 2 CO O H HCO O H (R. 3)
Carbonate formation (Reaction R.3) is possible but negligible in amine solutions because of its too high pKa of 10.33 in comparison with the pH observed in these media. Usually, a decrease of the pressure or an increase of temperature displaces the equilibrium from the right to the left side of the reaction. This principle is applied in the regenerator for stripping the CO 2 from the solvent.

Corrosion Issues in Amine Units

Recently, applications for sweet gases (containing only CO 2 without H 2 S) have gained interest and an increased number of sweet units were installed. Most often the design criteria based on the experience of sour units were used for sweet units. However, in these sweet conditions, some unusual corrosion problems were experienced on materials which have proven to be satisfactory in sour gas [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF][START_REF] Dehart | [END_REF][START_REF] Wagner | Proceedings of the Laurance Reid Gas Conditioning Conference[END_REF]. Some corrosion failures were even reported for AISI 410 absorber trays (Figure 2) and for AISI 304L internals of a regenerator, with estimated corrosion rates as high as a few mm per year [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF]. In both cases, corrosion appeared when temperature and CO 2 loading were high.

Corrosion mechanisms

Several authors have studied the impact of operational parameters on corrosion of carbon steels [START_REF] Dupart | [END_REF]6] or stainless steels [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF]7].

It is well admitted that high temperature is detrimental to corrosion [START_REF] Dupart | [END_REF]8], through an acceleration of the electrochemical reactions, and also through the thermal degradation of amines into corrosive by-products. CO 2 loading is also one of the most important parameters controlling the corrosivity of acid gas solvents. It is considered that an increase of CO 2 loading increases the corrosion rate [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF][START_REF] Dupart | [END_REF]6,9].

However, the corrosion mechanisms are not well understood. Some authors proposed a list of hypothetic electrochemical reactions that may occurs in CO 2 -DEA solutions [10,[START_REF] Veldman | NACE[END_REF]:

Oxydation of iron :

→ + + + + - -- - - -- - - -- - (R. 6)
Reduction of protonated amine :

) g ( 2 H DEA 2 e 2 DEAH 2 + + + + → → → → + + + + - -- - + + + + (R. 7)
Reduction of undissociated water :

) g ( 2 2 H OH 2 e 2 O H 2 + + + + → → → → + + + + - -- - - -- - (R. 8)
Nevertheless, it is still not clear which reduction reaction(s) is (are) predominant. The objectives of this paper are to investigate relationships between the chemical composition of CO 2 -DEA solutions and the corrosion rates of different steel grades. This was performed by corrosion tests under various temperatures and CO 2 loadings. At the same time, thermodynamic calculations of the system composition were made for each experimental condition using home-made programs.

Experiments

Experimental Apparatus

The experiments were carried out in a glass electrochemical corrosion cell as shown in Figure 3. Two thermostated baths, for heating the double-wall electrochemical cell, and for a condenser used to prevent water evaporation from the cell.

A thermometer controlling the inner cell temperature. A gas preparation system for feeding the test cell with carbon dioxide (CO 2 ) or nitrogen (N 2 ).

A potentiostat Bio-Logic VMP2 with its data acquisition system.

Preparation of corrosion specimens and of test solutions

Three different steel grades were used for the electrochemical tests : AISI 1018 carbon steel, AISI 304L austenitic stainless steel, and AISI 410 martensitic stainless steel. The composition of each steel grades is given in Table 1. Before experiments, the working electrode was wetpolished to 1200-grit silicon carbide (SiC) papers, rinsed with ethanol and distilled water. Then, it was dried with compressed air and immediately immersed in the test solution. For all test solutions, CO 2 loading was determined by chemical analysis: a small amount of test solution was sampled and an excess of strong acid was added. The volume of degassed CO 2 could then easily be measured [START_REF] Horowitz | Association of Official Analytical Chemists (AOAC) Methods[END_REF]. Such measurements were systematically made before and after each corrosion test. Range of test solution loading and temperature are given in Table 2. Before polarization, the potential of the working electrode was measured until steady state. Then, potentiodynamic polarization experiments were carried out with a scan rate of 1 mV/s. The scan began from cathodic (-1.1 V vs Ag-AgCl) to anodic (1V vs Ag-AgCl) potentials.

Results and discussion

Influence of the CO 2 loading Figure 4 presents the polarization curves of different steel grades in 4 mol/L DEA solutions at 30°C and with different levels of CO 2 loading. From the polarization curves, we can observe that carbon steel exhibits an important anodic peak, followed by a passive region at higher potentials. The anodic peak is also seen for the AISI 304L steel grade, but with lower current levels. Surprisingly, AISI 410 exhibits a fully passive behaviour, suggesting that it has a higher corrosion resistance than AISI 304L. However, these results have to be analysed in the light of free corrosion potential measurements. Indeed, we can observe in Figure 5 that the free corrosion potential of AISI 304L remains in the passive region for all CO 2 loadings at 30°C. On the other hand, AISI 1018 is passive only in the lean condition (α = 0), and becomes active as soon as CO 2 is present in the system. AISI 410 presents intermediate evolution of free corrosion potentials, with a passive to active transition between 0.25 and 0.45 CO 2 loading.

Even though the temperature of these tests was not representative of real operating conditions, these results point out extremely interesting facts: some stainless steel grades might present an active anodic dissolution region passive to active transitions might occur when the corrosivity of the test solution increases This could probably explain the extremely rapid uniform corrosion observed on industrial units for AISI 410 and AISI 304L under high temperature and high loading conditions [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF].

The results reported in Figure 4 also indicate that both cathodic and anodic reaction rates are increased for high CO 2 loading. This increase is most effective for the cathodic reactions measured on AISI 304L and AISI 410. When the CO 2 loading is increased from 0 to 0.65, the cathodic current density is increased by nearly two orders of magnitude. In order to better understand the origin of this increase, thermodynamic calculations were performed to determine more accurately the solution compositions at the different CO 2 loadings. A homemade program developed at IFP were used for this purpose. The results are summarised in Table 3.

Table 3: Concentrations of major species contained in DEA solutions as a function of CO 2 loading (DEA at 4 mol/L -30°C).

Among these species, the candidate oxidising elements are: hydronium ion bicarbonate ion protonated amine

For each experimental condition, the concentrations of these species were compared to current density measured in the cathodic region, corresponding to the reduction reactions. In Figure 6 are presented in a same graph the cathodic currents measured at E= -1V/Ag-AgCl on AISI 410 and the concentration of each oxidising species as a function of CO 2 loading. The following trends are observed when the CO 2 loading increases: the cathodic current density increases the concentrations of hydronium, bicarbonate and protonated amine increase

The concentrations of all oxidising species follow the same trend than the cathodic current, i.e. an increase with CO 2 loading. Nevertheless, we can notice that the concentration of hydronium is extremely low compared to that of bicarbonate or protonated amine. The hypothesis of a significant contribution of hydronium reaction to the cathodic current is therefore very unlikely considering the pH of the solutions (around 8.5).

Then, bicarbonate and protonated amine are the most serious oxidising candidates. However, at this stage, it is not possible to conclude for one or another species and additional experiments with synthetic solutions with controlled levels of each element need to be performed in a next step of this experimental program.

Furthermore, we can also notice from the thermodynamic calculations that the concentration of amine carbamates (DEACOO -) is also rising when CO 2 loading increases. Carbamates are often presented as good chelating agents that easily complex with metals, and might then increase the corrosivity of the solution.

Even if this is far beyond the scope of this paper, this might be one of the causes of the passivity breakdown which was observed for some conditions in this study.

Influence of the temperature Figure 7 presents the influence of the temperature on the current versus potential curves for different steel grades in 4 mol/L DEA solutions and with a constant CO 2 loading (α = 0.45). In the anodic region, the same trends are observed at higher temperature than previously at 30°C. The anodic peak for carbon steel is more pronounced than for AISI 304L stainless steel, while AISI 410 exhibits a fully passive behaviour. When the temperature is increased, an increase of the cathodic and anodic currents are also observed, in agreement with the literature [START_REF] Wagner | Proceedings of the Laurance Reid Gas Conditioning Conference[END_REF].

The same thermodynamic calculations were performed for these experimental conditions, and are reported in Table 4. According to these data, the following trends are observed when the temperature increases: the concentrations of bicarbonate and hydronium slightly increase the concentration of water is constant the concentration of protonated amine slightly decreases However, the temperature influences the kinetics of reaction and particularly accelerates the rates of reduction reactions. This influence of the temperature is illustrated in Figure 8, where it is shown that the cathodic current measured at -1V/Ag-AgCl obeys an Arrhenius law. These results confirm that the thermic activation of the amine-CO 2 system increases the cathodic currents of nearly one or two magnitude when the temperature is increased from 30°C to 80°C. An extrapolation for higher temperatures of 100°C and 120°C has been done, allowing to predict the cathodic currents in more extreme conditions and also the corrosivity of DEA solvents towards the various steel grades that are tested.

Conclusion

The objectives of this study were to illustrate the influence of temperature and CO 2 loading on the corrosivity of CO 2 -amine systems and to correlate the chemical compositions of solvents with the shape of the polarization curves.

It appeared that CO 2 loading was the most influent parameter, with a difference of one or two orders of magnitude between the cathodic currents of a lean amine than that of a rich. The temperature is also a relevant parameter to take into account, especially since the temperature used in this study are lower than that of industrial gas treatment units. In that way, highest temperature can imply much corrosion damages even on stainless steel grades as it was shown by extrapolation curves till 120°C.

These results also underline a better corrosion resistance of stainless steels (AISI 304L and AISI 410) than that of carbon steel (AISI 1018). Indeed, free potentials of carbon steel indicate an active behaviour in CO 2 -amine solutions whereas stainless steels are passive but deactivation might occur in these experimental conditions. Especially, martensitic steel AISI 410 seems to loose his passivity as soon as CO 2 loading is too high. The tests have not yet been performed for highest temperatures but it is expected that both higher CO 2 loading and temperature lead to higher corrosion rates.

The chemical compositions of the solutions were calculated in order to highlight the influence of oxidising species like bicarbonate, hydronium ions, undissociated water and/or protonated amine. These results are not sufficient to conclude on the influence of one or another species, but can allow us to focus on some mechanisms and especially on the influence of bicarbonate.

In our future investigations, it will be important to consider more agressive experimental conditions, such as highest temperatures, in order to reproduce industrial conditions. Furthermore, it appears also necessary to take into account some others species of CO 2 -DEA solutions such as carbamates and other degradation by-products of amine which can act as chelating agents.

Figure 2 :

 2 Figure 2: Examples of uniform corrosion on AISI 410 internals in sweet service amine unit [4].

Figure 3 :

 3 Figure 3: Experimental setup for the electrochemical corrosion tests.

Figure 5

 5 Figure 5 reports the value of the free corrosion potential measured for each condition (steel grade and test solution) before the polarisation experiment.

Figure 4 :

 4 Figure 4: : Influence of CO 2 loading on polarization curves measured in 4 mol/L DEA at 30°C for different steel grades.

Figure 5 :

 5 Figure 5: Free potentials of carbon steel AISI 1018 and stainless steels AISI 304L and AISI 410 depending on CO 2 loading of DEA solutions.

Figure 6 :

 6 Figure 6: Evolution of cathodic currents at -1V/Ag-AgCl and concentrations of candidate oxidising species as a function of CO 2 loading.

Figure 7 :

 7 Figure 7: Effect of temperature on carbon steel AISI 1018 and on stainless steels AISI 304L and AISI 410 (4M DEA -0.45 mol CO 2 / mol DEA)

Figure 8 :

 8 Figure 8: Evolution of cathodic currents at E= -1V/Ag-AgCl as a function of 1/T for each steel grades.

Table 1 :

 1 Composition of alloys used for corrosion experiments.The corrosion experiments were carried out in 4.0 mol/L aqueous solution of DEA at various CO 2 loadings and temperatures. At the beginning of each experiment, 300 mL of fresh solvent was introduced in the corrosion cell.For the experiments in rich amine, the solution was saturated by bubbling CO 2 for 2 hours. Until saturation, the CO 2 loading obtained at 80°C is about 0.45 mol CO 2 / mol DEA and 0.65 mol CO 2 / mol DEA at 30°C. For the experiments in lean conditions, nitrogen (N 2 ) was used to deaerate the solvent and avoid any CO 2 charging during the tests. For intermediate CO 2 loadings of 0.25 mol CO 2 / mol DEA (or 0.45 mol CO 2 / mol DEA at 30°C), saturated and deaerated solutions were mixed. N 2 bubbling was kept in the cell to maintain the CO 2 loading during the experiment.

	ALLOY		COMPOSITION OF ALLOY ELEMENTS (%)
	GRADES	C	Mn	Si	Cr	Mo	Ni	S	P
	AISI 1018	0.16 -0.22	0.4 -0.7	0.15 -0.35	0.40	0.1	0.4	<0.035 < 0.035
	AISI 304L 0.03	2	1	18-20 0	8-11	0.03	0.045
	AISI 410	0.15	1	1	11-13 -	0	-	-

Table 2 :

 2 Range of temperature and CO 2 loading of experimental tests.

CO 2 Loading, (mol CO 2 / mol DEA)

			0.0	0.25	0.45	0.65
	Temperature (°C)	30 50 80	X --	X --	X X X	X
	Experimental Procedure

Table 4 :

 4 Concentrations of principal species contained in DEA solutions depending on temperature (4M DEA -0.45 mol CO 2 / mol DEA).

Acknowledgements

The authors would like to thank Alexandre Bonneau, for his assistance in electrochemical measurements and Pascal Mougin for his thermodynamic model development.


Elisabeth Fleury
email: elisabeth.fleury@ifp.fr

Jean Kittel

Bruno Vuillemin

Roland Oltra

François Ropital

Corrosion in amine solvents used for the removal of acid gases

Processes using amine solvents for the removal of CO 2 have long been used for the treatment of natural gas. More recently, developments in the field of postcombustion CO 2 capture have gained considerable interest for greenhouse gas mitigation. Even though the nature of the amine is different for both applications, the process flow diagrams are very similar. The raw gas is contacted with the amine solvent in an absorber column, and the CO 2 is absorbed by the solvent. The rich solvent containing the CO 2 then circulates to a regenerator, where the temperature is increased to strip the CO 2 . The lean solvent then returns to the absorber for a new cycle.

For these processes, corrosion is known to be a major issue. Usually, amines are not corrosive but during operation of amine units, degradation of the solvent may occur due to the reaction with contaminants like oxygen. As a result, corrosive species are formed including other amines and acids products like oxalates, formates and acetates also known as Heat Stable Salts (HSS). Corrosion problems may also depend on other parameters for instance type and concentration of the alkanolamine, temperature of the solvent or CO 2 loading.

In order to extend the limits of gas treating processes, but also to develop the new processes for CO 2 capture, a better understanding of corrosion in amine solvents is required. This paper presents the first results of a study where the impact of several parameters will be evaluated by electrochemical methods. The corrosivity of Monoethanolamine (MEA), Diethanolamine (DEA) and methyl-diethanolamine (MDEA) was compared. Other parameters were studied, among which the impact of CO 2 loading and the concentration in HSS. Back

Introduction

Basics of acid gas absorption by amines

The primary function of alkanolamine units is to remove acid gases, usually hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ). Amine processes have long been used for the treatment of natural gas. Indeed, sales specification for natural gas often require to lower the CO 2 content to less than 2%, and H 2 S to less than 4 ppm.

More recently, these processes gained interest as a solution that can be used for capturing CO 2 from flue gas streams emitted by coal-fired power stations, which are major contributors to the greenhouse effect and global warming.

Depending on the application, the operation conditions (temperatures, partial pressure of acid gases, ...) may vary. However, for CO 2 capture or gas treatment, the process flow diagram (PFD) is quite similar. A typical PFD is given in Figure 1.

Figure 1: Process flow diagram of gas absorption system. [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF] The acid gas absorption process is performed through the following steps. The raw gas enters the unit at the bottom of the absorber column, where acid gases are absorbed by the lean amine solvent that flows countercurrent to the raw gas. The treated gas is the overhead product while the rich amine solution flows from the bottom of the absorber to the lean/rich cross exchanger where it is heated before entering the regenerator column. In the regenerator, acid gases are stripped from the rich amine by heat and steam produced by the reboiler. Acid components leave off at the top of the regenerator and go to the overhead condensers and the reflux Back accumulator. The hot lean amine from the bottom of the regenerator is cooled via the lean/rich heat exchanger prior to re-entering the absorber.

The basic reactions between CO 2 and amines are given below.

Carbon dioxide reacts with amines by the following reactions where R designates an organic group. These reactions can lead to the formation of carbamates (R.1), bicarbonates (R.2) and carbonates (R.3):

- -- - + + + + + + + + ⇔ ⇔ ⇔ ⇔ + + + + NCOO R NH R CO NH R 2 2 2 2 2 2 (R.1) - -- - + + + + + + + + ⇔ ⇔ ⇔ ⇔ + + + + + + + + 3 3 2 2 3 HCO NH R O H CO N R (R.2) - -- - + + + + - -- - + + + + ⇔ ⇔ ⇔ ⇔ + + + + 2 3 3 3 2 CO O H HCO O H (R.3)
For tertiary amines, the formation of carbamates (Reaction R.1) is impossible. This reaction occurs only with primary and secondary amines, which possess a labile hydrogen. Bicarbonate formation (Reaction R.2) is possible with the three type of amines. Carbonate formation (Reaction R.3) is also possible but negligible in amine solutions because of its too high pKa of 10.33. Usually, a decrease of the pressure or an increase of temperature displaces the equilibrium from the right to the left. This principle is applied in the regenerator for stripping the CO 2 from the solvent.

Corrosion issues in amine units

Many studies have already been made on the corrosion by amine solvents. Most of the studies were made by weight loss measurements and in conditions of gas treatment [START_REF] Rooney | [END_REF]3] . A few recent studies used electrochemical measurements, but focused mainly on CO 2 capture [4,5] . The following parameters are recognised to have an impact on corrosion:

Type of amine

As already explained, the choice of amine depends mainly on the application. It is usually admitted that primary amines (like MEA) are more corrosive than secondary amines (like DEA). Tertiary amines (like MDEA) are considered to present the lowest corrosivity. However, it is also well admitted that all amines are usually not intrinsically corrosive. It is only when they react with CO 2 , or when they form degradation by-products that their corrosivity can be increased to a high level [6] .

Acid gas loading

Reactions between alkanolamines and acid gases lead to different complexes. In the case of CO 2 , the main by-products are carbamate and bicarbonate, as well as protonated amine (Reaction R.1 and R.2). It is well admitted [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF]7,6,8,4] that an increase of CO 2 loading increases the corrosion rate. However, the corrosion mechanisms are not yet clearly identified.

Degradation products and Heat Stable Salts (HSS)

Reactions of alkanolamines with both CO 2 and O 2 yield degradation products. Basic degradation products, such as HEOD [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF] , BHEP 2 and THEED 3 , are formed by reaction of amine with CO 2 [START_REF] Blanc | Laurence Reid Gas Conditioning Conference[END_REF]10] . Several studies have shown that these degradation products are not corrosive but are good chelates. They are able to easily form complexes with iron. Thus, they reduce the stability of sulphide or carbonate protective layers formed on the surface of steels.

Acid degradation products mainly come from reactions of amine with oxygen (O 2 ) or from thermal degradation. The main degradation products are salts of carboxylic acid such as oxalic, formic, acetic or glycolic acids. These species are stronger acids than carbonic acid, therefore, they are not regenerated at the reboiler temperature. They are usually named Heat Stable Salts (or HSS).

In this paper, we propose to examine some of the factors involved in corrosion mechanisms of amine-CO 2 systems. The corrosivity of MEA and that of DEA and MDEA are compared. Other parameters such as the CO 2 loading, the HSS contents, and the presence of CO 2 in the raw gas are also studied.

Experiments

Experimental Apparatus

The experiments were carried out in a glass electrochemical corrosion cell as shown in Figure 2. The experimental setup consisted of :

A three-electrode corrosion cell with a flat circular working electrode made of carbon steel (AISI 1020) with a surface area of 1 cm², an Ag/AgCl reference electrode and a circular Platinum-counter electrode.

One thermostated bath for heating the doubled-wall test cell, and another bath for the condenser, to prevent water evaporation.

A thermometer controlling the inner cell temperature.

A potentiostat (Solartron 1286) and a frequency response analyser (Solartron 1255). A gas preparation system for feeding the test cell with blends of carbon dioxide (CO 2 ), nitrogen (N 2 ) and air. A data acquisition system.

1 3-(2-hydroxyéthyl)-2-oxazolidone 2 N,N'-bis(2-hydroxyéthyl)pipérazine 3 N,N,N'tris(2-hydroxyéthyl-éthylènediamine

Specimens and Solutions

The corrosion experiments were carried out in 5.0 mol/L aqueous solution of MEA, DEA or MDEA at 80°C.

At the beginning of each experiment, 300 mL of fresh solvent was introduced in the corrosion cell.

For the experiments in rich amine, the solution was saturated with CO 2 by bubbling for 2 hours until saturation. The obtained loadings (α, in mol of CO 2 per mol of amine) were respectively 0.51 for the MEA, 0.44 for the DEA, and 0.29 for the MDEA. For the experiments in lean conditions, nitrogen (N 2 ) was used to deaerate the solvent and avoid any CO 2 charging during the tests. Gas bubbling was kept during all the experiments to maintain the equilibrium conditions.

The impact of HSS was evaluated only for MEA. Oxalic acid was used because it leads to the most corrosive heat stable salts identified by Rooney et al. [START_REF] Rooney | NACE[END_REF] . To simulate a degraded MEA system, oxalic acid was added to the CO 2 -saturated MEA solutions with varying concentrations from 0 g/L to 50 g/L.

Before each experiment, the working electrode was wet-polished to 1200-grit silicon carbide (SiC) papers, rinsed with ethanol and distilled water. Then, it was dried with compressed air and immediately immersed in the test solution.

Experimental Procedure

At the beginning of each experiment, the potential of the WE was measured until it remained constant. Then two different kinds of measurements were performed.

When successive measurements had to be made in the same test solution, Electrochemical Impedance Spectroscopy (EIS) was used. The measurements were made at the free corrosion potential, with an amplitude of 10 mV and from 100 kHz to 5 mHz.

From the EIS diagrams, the polarisation resistance (Rp) was evaluated as the diameter of the semicircular loop in the Nyquist plan. The corrosion current density was then determined as:

c a c a corr . . Rp 1 J β β β β + + + + β β β β β β β β β β β β = = = = (Eq.1)
where J corr is the corrosion current density in A/cm², Rp is the polarization resistance in Ohm.cm², a et c are the anodic and cathodic Tafel coefficients in V. The corrosion rate could then easily be estimated from J corr using the Faraday's law.

At the end of each experiment, potentiodynamic polarization experiments were carried out with a scan rate of 1 mV/s. The scan began from cathodic (-1.5 V vs Ag-AgCl) to anodic (1V vs Ag-AgCl) potentials.

Results

The experimental results focus on the following parameters: -type of amine, -CO 2 loading, -HSS and oxygen contents.

The objectives are first to qualify the experimental methodology, and then to compare the impact of the different parameters on amine solutions corrosivity. The polarization resistance in the MEA solution is about 800 /cm² which corresponds to a corrosion rate of 0.6 mm/year. In the DEA solution, Rp is approximately 1600 /cm², corresponding to 0.3 mm/year. The corrosivity of MDEA is even lower, with a Rp around 45000 /cm², i.e., a corrosion rate of 0.01 mm/year. These results are in good agreement with the ranking usually agreed in the literature [6,4] . An explanation for this difference in amine corrosivity was proposed by Teevens [START_REF] Teevens | [END_REF] who noticed that MEA is a stronger Lewis base than DEA and MDEA. In fact, MEA reacts with CO 2 to form amine carbamates, which in turn, undergo internal dehydration to yield various degradation products. DEA can also react with CO 2 to yield carbamates, however it is a weakest Lewis base so DEA forms less carbamates than MEA. The formation of carbamate from MDEA is impossible, since they fail to yield amides necessary in carbamate ions formation. Moreover, the presence of carbamates in solution would increase the conductivity of amine solution and lead to higher solution corrosivity.

Effect of type of amine

Effect of CO 2 Loading

Figure 4 presents the polarization curves of AISI 1020 CS in a rich or lean 5M MEA solution at 80°C. The consequence of CO 2 loading is an important increase of the cathodic and anodic current densities, by one or two orders of magnitude. Therefore, in a CO 2 saturated solution, we can expect the corrosion rate to be multiplied by 10 to 100 as compared with a lean solution. (MEA -5M-80°C -AISI 1020)

The influence of CO 2 loading on the corrosion rate has to be examined in the light of reactions R.1 to R.3, which show that an increase of CO 2 loading yields higher amounts of RNH 3 + and HCO 3 -which in turn dissociate and produce more hydrogen ion (H + ). Consequently, the amount of hydrogen ion (H + ) increases and the corrosion process is accelerated [START_REF] Veawab | [END_REF] .

Effect of Oxygen and Heat Stable Salts

The effect of oxygen was evaluated in a 5M MEA solution at 80°C, using a gas feed composed of 75% CO 2 , 20% N 2 and 5% O 2 . The corresponding impedance diagram is presented in Figure 5, and compared with the reference case of pure CO 2 loading, i.e. without oxygen. Polarization resistance seems to be lower when oxygen is present. Indeed, corrosion rate of CS in MEA without O 2 is about 0.6 mm/year whereas the corrosion rate is about 0.9 mm/year in the O 2 -MEA system.

Oxygen is known to degrade amines and to form numerous compounds as glycine, ammonia, amides, bicine, as well as several weak acids as formic, acetic, oxalic, glycolic acids. Then, these carboxylic acids yield to formate, acetate, oxalate and glycolate usually named Heat Stable Salts (or HSS). However, no such reaction was expected for the very short duration experiments under O 2 . Therefore, the observed increase of corrosivity could be attributed to dissolved O 2 rather than to any degradation product. This increase of corrosivity might be a direct consequence of an increased oxidizing power with dissolved oxygen. The influence of heat stable salts was also examined. Oxalic acid was chosen because it seems to lead to one of the most corrosive HSS [START_REF] Rooney | NACE[END_REF] . Impedance diagrams were measured in MEA solutions with increasing oxalic acid contents from 0 g/L to 50 g/L. The results are presented in Figure 6.

Figure 6: Effect of HSS (oxalic acid) on carbon steel corrosion.

The results show that a higher HSS content leads to a higher corrosion rate. Indeed, the polarization resistance is about 750 /cm² when there is no oxalic acid in solution and decreases to 430 /cm² when oxalic acid content rises to 50 g/L. The corresponding corrosion rates are 0.7 mm/year when there is no oxalic acid and 1.2 mm/year for the highest oxalic acid concentration.

In gas treatment units, oxalic acid content is usually controlled, and it is recommended to maintain its concentration below 250 ppm. For such low concentrations, the results of this study predict hardly no impact on the corrosion rate. However, it would be erroneous to conclude that the HSS limits are too conservative. Indeed, as explained by Rooney et al. [START_REF] Rooney | NACE[END_REF] , HSS are good chelates, and they can easily complex with iron. As a consequence, they contribute to dissolve the protective layers formed on the surface of steel, allowing an easier access of the corrosive solution to the bare metal. HSS are therefore not intrinsically corrosive, as also shown by the results of this study, but they can weaken the protective corrosion product layers, allowing a more rapid corrosion of the metal.

Discussion

From the results of this study, a preliminary ranking can be proposed for the impact of the tested parameters on the corrosivity of amine solutions.

It is quite clear that CO 2 loading has the most significant influence on corrosion rate. For MEA 5M at 80°C, the difference between lean and rich amine was between one and two orders of magnitude. Comparatively, the corrosivity of different amines varied by a factor five or less. The direct impact of HSS additions was even lower: the corrosion rate was only doubled for a concentration of oxalic acid as high as 50 g/L.

Nevertheless, this does not mean that the type of amine and the presence of HSS do not have an important long term impact for the long real units. The choice of amine is of major importance regarding the degradation. It is expected to have a more rapid degradation with primary and secondary amines compared to tertiary amines. And the presence of HSS also can have more practical impact on real plants than during short exposure laboratory tests. Indeed, synergies between high flow rates and chelating action of HSS can result in erosion-corrosion, which is one of the most important form of corrosion observed in real plants.

These results can also be used to discuss the differences between CO 2 capture and gas treatment applications. Table 1 summarizes the most significant differences in operating conditions with a direct impact on corrosion. For CO 2 capture, primary amines have to be used because of their high reactivity with CO 2 , allowing a fast reaction necessary for the treatment of huge quantities of gas streams. MEA represents the n°1 choice for such applications. For gas treatment, secondary or tertiary amines can be used.

Another difference between CO 2 capture and gas treatment relies in the composition of the gas. In the former case, oxygen is often present at a concentration between 5 and 10%. The consequence is an extremely high risk of solvent oxidative degradation. For gas treatment, O 2 is usually not present in the flue gas.

The last difference between the two processes is the lean amine loading. For gas treatment, the regeneration is usually complete, i.e. the lean loading is close to zero. For CO 2 capture, it is more efficient from the energetic point of view to regenerate the amine only partially. Lean loadings around 0.25 mol CO 2 /mol amine represent the base case.

Considering the three parameters of this study, it can be seen that CO 2 capture accumulates all the worst cases. MEA is the most corrosive amine, and also the one which is more prone to degradation. Degradation is also favoured by the presence of O 2 in the flue gas. Finally, the corrosivity due to CO 2 loading concerns both the rich and the lean amine sections of the plant.

Finally, the present study considered only carbon steel. Initially, most of the equipment and piping of alkanolamine plants were made of carbon steel, but corrosion problems occurred in the process and led to severe damages, with an important increase of the production costs of the plants. Even if it is possible to reduce corrosion by keeping amine regenerator operating at low temperatures and by minimizing amine solution concentration and CO 2 loading, it is now common practice to replace carbon steels by stainless steels at selected locations. Stainless steels are now mainly used in areas where corrosion is very severe such as the bottom of the absorber, the piping from the absorber to the regenerator and the top of the regenerator, in areas with hot temperatures and high acid gas loadings.

All these aspects have to be taken into account for the future studies in this field. The behaviour of stainless steel grades has to be examined in the worst operating conditions, i.e. high temperature, high acid gas loading, degradation products... This is particularly important in the gas treatment area, where severe corrosion of some stainless steel grades was recently reported for sweet service units (flue gas containing only CO 2 ) [START_REF] Bonis | GPA Annual Convention Proceedings[END_REF] .

For CO 2 capture, the main issues that need to be studied are: 1/ the real impact of CO 2 loading, especially for intermediate loadings representative of the lean sections; 2/ a closer examination of the degradation products that will be present due to O 2 in the flue gas. Long term experiments with corrosion product layers and flow rate simulations could be useful for a better prediction of corrosion in degraded solutions.

Conclusions

The objectives of this study were to illustrate the impact of several parameters on the corrosivity of CO 2 -amine system.

It appeared that CO 2 loading was the most influent parameter, with a difference of one or two orders of magnitude between the corrosion rate of a lean amine and that of a rich solvent. Comparatively, in CO 2 saturated solutions, MEA corrosivity was found to be twice more corrosive than DEA, and thirty times more corrosive than MDEA. The presence of degradation products had only a slight impact on the corrosivity. However, it has to be emphasised that the type of amine and degradation reactions must still be considered with great care for real units operations. Especially, HSS have a chelating action, leading to less protective corrosion product layers. This long term impact could not be well illustrated by short term exposure tests in the laboratory.

These results could be used for comparing the cases of CO 2 capture and gas treatment. It appeared that CO 2 capture cumulates all the more corrosive factors: MEA is the reference solvent, oxygen is present in the flue gas leading to oxidative degradation, and the lean amine loading is 0.25 mol CO 2 /mol amine, whereas it is zero in gas treatment units. All these differences have to be taken into account for the design of CO 2 capture plants.

Finally, for future studies, it is also important to consider not only carbon steel, which has long been the preferred material for such units, but also stainless steel grades.

Figure 2 :

 2 Figure 2: Experimental setup for the electrochemical corrosion tests.

Figure 3

 3 Figure 3 presents the impedance diagrams of AISI 1020 carbon steel in CO 2 saturated solutions of 5M MEA, DEA and MDEA at 80°C.

Figure 3 :

 3 Figure 3: Effect of amine type on carbon steel corrosion. (MEA, DEA and MDEA at 5 mol/L -80°C -AISI 1020)

Figure 4 :

 4 Figure 4: Effect of CO 2 loading on carbon steel corrosion.(MEA -5M-80°C -AISI 1020)

Figure 5 :

 5 Figure 5: Impedance diagram obtained on carbon steel 1020 with and without O 2 . (WE: CS 1020, RE: Ag/AgCl, CE: Pt, MEA, 5M, 80°C, =0.51 mol CO 2 / mol MEA)

Table 1 :

 1 Differences in operating conditions of CO 2 capture and gas treating units.

	Parameters	CO 2 Capture	Gas Treatment
	Type of amine	MEA	DEA or MDEA
	Composition of raw gas	5 -10% O 2	no O 2
	Lean loading	0.25	nearly 0

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Acknowledgements

The authors would like to thank Alexandre Bonneau, for his assistance in electrochemical measurements. Back