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Ind. Eng. Chem. Res. 1999, 38, 310-315
Influence of Process Parameters on Corrosion Behavior in a Sterically Hindered Amine-CO2 System Amornvadee Veawab, Paitoon Tontiwachwuthikul,* and Amit Chakma Process Systems Laboratory, Faculty of Engineering, University of Regina, Regina, Saskatchewan, Canada S4S 0A2
Corrosion behavior in a CO2 absorption process using a sterically hindered amine, 2-amino-2methyl-1-propanol (AMP), was investigated by means of an electrochemical technique. The behavior was evaluated over ranges of three process parameters: 30-80 °C liquid temperature; 0.0-1.0 mol/mol of CO2 loading; 1.0-4.0 kmol/m3 AMP concentration. Experimental results show significant effects of the three process parameters on the corrosion behavior. An increase in each parameter generally aggravates system corrosiveness. Corrosiveness in the AMP system was also compared with that in the MEA system. It was found that the AMP system induces less corrosion rate than the MEA system at elevated temperature. 1. Introduction Sterically hindered amines were first introduced to the application of acid gas separation as absorption solvents by EXXON Research and Engineering Company.1 These solvents include 2-amino-2-methyl-1-propanol (AMP), 1,8-p-menthanediamine (MDA), and 2-piperidine ethanol (PE). Recently, the sterically hindered amines have been receiving a great deal of attention and have become potential competitors against conventional absorption solvents, particularly alkanolamines. This is due to their excellent characteristics in terms of absorption and desorption capacity in comparison with the alkanolamines.2,3 In practice, the sterically hindered amines can be used in an aqueous solution, an aqueous organic medium, and a combination of aqueous potassium carbonate. According to Sartori et al.,3 between 1983 and 1992, the sterically hindered amine-based solvents had already been used in 31 commercial plants under license from EXXON. The industrial usage can be found in processing operations such as natural gas purification, tail gas treating, ammonia manufacture, and hydrogen production. Due to the increasing use of sterically hindered amines, there have been a number of research works published in the literature. Most works mainly focus on solvent performance, e.g., absorption and desorption capacity (solubility of CO2) and kinetics (rate of reaction with CO2). However, the information solely based on such solvent performance is insufficient for evaluating practicability of the promising solvent. Other aspects such as operating problems should be considered. According to Kohl and Nielsen,4 the most serious operating problem encountered with acid gas separation plants is corrosion. The corrosion problem leads to a direct impact on a plant’s economy since it causes unplanned downtime, production losses, reduced equipment life, and even injury or death.5 The cost of downtime in terms of production losses for a typical plant could vary between $10 000 and $30 000 per day.6 Besides the production losses, a large portion of expenditure is also necessary for restoring corroded systems * To whom correspondence should be addressed. Tel: (306) 585-4726. Fax: (306) 585-4855. E-mail: ptonti@ meena.cc.uregina.ca.
and for treatments initiated to mitigate corrosion. As stated by Gerus,7 millions of dollars are annually spent due to corrosion problem in acid gas separation plants. In addition to the above direct impact, the corrosion problem also indirectly affects a plant’s economy via process parameters such as solvent concentration, liquid temperature, and CO2 loading. In practice, flexibility in varying such process parameters is limited due to excessive corrosion. Increase in process parameters beyond the typically operated values normally causes a tremendous increment in plant corrosiveness.1,5 Due to such a limitation, the capacity of existing plants may not be easily increased at a reasonable expense. Although the corrosion problem can cause a significant impact on a plant’s economy, no comprehensive record of corrosion in the CO2 separation process using a sterically hindered amine has been disclosed, except for our preliminary work on the AMP-CO2 system.8 Therefore, the objective of this work is to provide more information on the corrosion behavior of carbon steel in a sterically hindered amine-CO2 system. Since process parameters are considered important factors in causing the corrosion problem as mentioned previously, the studies then emphasize the way in which process parameters affect corrosion behavior. The interested parameters are liquid temperature, CO2 loading, and solvent concentration. This work also provides comparison of corrosiveness between sterically hindered amine and conventional alkanolamine systems. Due to their popularity, AMP and MEA are selected as representatives of sterically hindered amines and conventional alkanolamines, respectively. 2. Chemistry of CO2 Absorption Molecular structures of sterically hindered amines are generally similar to those of amines, except sterically hindered amines have an amino group attached to a bulky alkyl group. For example, 2-amino-2-methyl-1propanol (AMP), considered a hindered form of primary alkanolamines, has an amino group attached to a tertiary carbon atom while monoethanolamine (MEA), a primary alkanolamine, has an amino group attached to an aliphatic carbon atom. The structural formulas of MEA and AMP are schematically illustrated in Figure 1.
10.1021/ie980325c CCC: $18.00 © 1999 American Chemical Society Published on Web 11/25/1998
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Figure 2. Experimental setup for corrosion test. Figure 1. Molecular structures of MEA and AMP.
By nature of molecular configuration, the bulky alkyl group in sterically hindered amines plays an important role on process performance including capacity of absorption and desorption. Consider the main reactions of CO2 absorption with alkanolamines and sterically hindered amines written as follows:9
Formation of carbamate: 2RNH2 + CO2 h RNHCOO- + RNH3+
(1)
Hydrolysis of carbamate: RNHCOO- + H2O h RNH2 + HCO3-
(2)
where RNH2, RNHCOO-, RNH3+, and HCO3- denote alkanolamine, carbamate ion, protonated alkanolamine ion, and bicarbonate ion, respectively. In the case of primary and secondary alkanolamines, formation of carbamate (reaction 1) is the main reaction while hydrolysis of carbamate (reaction 2) hardly takes place. This is due to stability of the carbamate compound, which is caused by unrestricted rotation of the aliphatic carbon atom around the aminocarbamate group. The overall reaction for the alkanolamines is therefore written as9
2RNH2 + CO2 h RNHCOO- + RNH3+
(1)
For the sterically hindered amines, both reactions 1 and 2 play major roles on the CO2 absorption process. In contrast with the alkanolamines, the rotation of the bulky alkyl group around the aminocarbamate group is restricted in sterically hindered amines. This results in considerably low stability of the carbamate compound. The carbamate compound is thus likely to react with water and forms free amine and bicarbonate ions (reaction 2). Due to the occurrence of reaction 2, only 1 mol of the sterically hindered amine instead of 2 mol of alkanolamine is required to react with 1 mol of CO2. The overall reaction for the sterically hindered amines can be written as10
RNH2 + CO2 + H2O h RNH3+ + HCO3-
(3)
The capacity of absorption and desorption is therefore stoichiometrically superior in sterically hindered amine system. 3. Experiment Experimental Setup. The experiments were carried out in a static corrosion cell using an electrochemical technique for corrosion analysis. Figure 2 illustrates an experimental setup consisting of two main components: corrosion cell, model K47, and potentiostat, model 273 (EG&G Instruments/Princeton Applied Research, NJ). The cell includes a 1 L flask, a pair of highdensity and nonpermeable graphite counter electrodes, a calomel reference electrode, a reference electrode bridge tube, a purge and vent tube, and a leak-proof assembly for mounting specimens. The potentiostat has an accuracy in applied potential and current measurement of (0.2% of reading. A computer is connected to a potentiostat for data acquisition and data analysis. Preparation of Specimens. The specimens for corrosion testing were made of carbon steel 1020. Their chemical compositions are as follows: C, 0.20; Fe, balance; Mn, 0.51; P, 0.013; S, 0.039; Si, 0.17. The specimens were cut into cylindrical shape: 1/2 in. (12.7 mm) long, 3/8 in. (3.75 mm) diameter, drilled to a depth of 1/4 in. (2.5 mm) and tapped to accept a 3-48 thread. Within an hour prior to test, the specimens were prepared by wet grinding with silicon carbide papers up to 600 grit in accordance with ASTM standard E380.11 Preparation of Absorption Solutions. The absorption solutions used in this work can be classified into two types: (i) fresh solution containing no or little trace of CO2; (ii) loaded solution containing some degree of CO2. The fresh solution was simply prepared to any desired concentration by diluting the purchased AMP or MEA with deionized water. Concentration of the prepared solution was determined by titration with 1 N standard hydrochloric acid (HCl) solution using methyl orange as an indicator. For the loaded solution, the preparation involves mixing a fresh solution with a saturated solution prepared by bubbling CO2 gas into the fresh solution for approximately 8 h. The amount of CO2 in the loaded solution represented in terms of CO2 loading (moles of CO2 per mole amine) was determined by a method of chemical analysis involving acidifying a given quantity of liquid sample by adding excess HCl solution.12
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Experimental Procedure. The experiments started with transferring the prepared solution to corrosion cell and reference electrode bridge tube. The corrosion cell was then assembled by placing graphite counter electrodes, a reference electrode bridge tube, a calomel reference electrode, and a purge and vent tube. The opening for specimen mounting was temporarily closed with a glass stopper in order to prevent losses of amine and CO2. The corrosion cell was then immersed in the water bath where temperature was set and controlled within an accuracy of (0.1 °C. After immersion, a gas stream was introduced into the corrosion cell. The introduced gas could be either nitrogen or a mixture of nitrogen and CO2 depending upon a required CO2 partial pressure suggested by Dow Chemical13 and Kritpiphat and Tontiwachwuthikul14 to maintain the prepared CO2 loading in the tested solution. The glass stopper previously covering the opening of the corrosion cell was then replaced with a specimen holder on which a prepared specimen was mounted. Prior to corrosion measurement, all potentiostat cables were properly connected to three points of the corrosion cell: graphite counter electrodes, calomel reference electrode, and specimen holder. The corrosion potential (Ecorr) of a specimen against a reference electrode at equilibrium was recorded when a reading was stable for 5 min. The potentiodynamic polarization then started with a scanning rate of 0.60 V/h. All experimental data including applied potentials and produced currents were continuously recorded and stored in a computer program. To observe the corrosion behavior in a given experimental run, plots between potential of specimen and current density, namely, polarization curves, were created. The potential indicates an amount of electrical force or energy available for reaction occurrence while the current density is a magnitude of electron flow in a system per specimen surface area. The corrosion rate was finally determined by the Tafel extrapolation technique detailed in ref 15. 4. Results and Discussion Prior to the experiments, the instrumentation and experimental technique were validated to ensure reliability of obtained data by conducting a potentiodynamic anodic polarization test in accordance with ASTM G594.16 After validation, over 30 experimental runs were conducted. The experimental results are divided into two parts. First part involves effects of process parameters on corrosion behavior and second part illustrates corrosiveness in the AMP system in comparison with the MEA system. The corrosion behavior is presented in terms of corrosion rate in mil per year (mpy). Effects of Process Parameters. (a) Liquid Temperature. The experimental results show that liquid temperature has a considerable effect on corrosion rate in the AMP-CO2 system, i.e., an increase in liquid temperature causes a higher corrosion rate. According to Figure 3 showing the results for 2 kmol/m3 AMP solution, the corrosion rate at 0.2 CO2 loading raises from 2.6 to 22.1 mpy when liquid temperature increases from 30 to 80 °C. A similar behavior is also found in case of 0.8 CO2 loading, i.e., corrosion rate raises from 13.0 to 57.5 mpy as liquid temperature increases from 30 to 70 °C. It should be noted that the relationship between liquid temperature and corrosion rate is disproportional. The higher the liquid temperature, the higher the change in corrosion rate.
Figure 3. Effect of liquid temperature on corrosion rate in AMPCO2 system (AMP concentration ) 2 kmol/m3).
Figure 4. Effect of liquid temperature on pH in AMP-CO2 system (AMP concentration ) 2 kmol/m3).
Such corrosion behavior caused by liquid temperature changes could be explained by reactions occurring in the AMP-CO2 system as shown below.
Absorption of CO2:10 RNH2 + CO2 + H2O h RNH3+ + HCO3-
(3)
Dissociation of protonated alkanolamine ion:9 RNH3+ h RNH2 + H+
(4)
Formation of carbonate ion:9 HCO3- h CO32- + H+
(5)
where CO32- denotes carbonate ion. As known, temperature is an essential parameter for reaction kinetic. Increase in temperature generally expedites rate of chemical reaction. In CO2 absorption with AMP, reaction 3 can readily be accelerated when liquid temperature increases, resulting in increases in amounts of RNH3+ and HCO3-. Because of the increasing amounts of such products, reactions 4 and 5 are subsequently shifted in order to maintain system equilibrium, thereby generating a higher amount of H+ in
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Figure 5. Effect of liquid temperature on polarization curve in AMP-CO2 system (AMP concentration ) 2 kmol/m3 and CO2 loading ) 0.2).
Figure 6. Effect of CO2 loading on corrosion rate in AMP-CO2 system (AMP concentration ) 2 kmol/m3).
the system. The increase in amount of H+ as liquid temperature increases can be illustrated in terms of pH reduction in Figure 4. By nature, corrosion is an electrochemical process consisting of anodic and cathodic reactions.17 Metal dissolution (reaction 6) is considered an anodic reaction while oxidizer reduction (reaction 7) is considered a cathodic reaction. In the case of a deaerated and uninhibited system, hydrogen evolution serves as an oxidizer reduction.
Metal dissolution: Fe f Fe2+ + 2e-
(6)
Oxidizer reduction: 2H+ + 2e- f H2 Fe2+
Figure 7. Effect of CO2 loading on pH in AMP-CO2 system (AMP concentration ) 2 kmol/m3).
(7)
denote ferrous and ferrous ion, where Fe and respectively. When the amount of H+ increases due to increasing liquid temperature, the equilibrium between metal dissolution (reaction 6) and oxidizer reduction (reaction 7) is disturbed. To maintain the equilibrium, more metal is dissolved into solution and generates more electrons for oxidizer reduction. Because of the response to the equilibrium disturbance, the effect of increased temperature is to increase both the metal dissolution and oxidizer reduction rates, thus accelerating corrosion rate. The effect of liquid temperature on the kinetic of corrosion process is confirmed by polarization curves as shown in Figure 5. Increase in liquid temperature obviously increases anodic and cathodic current densities. This behavior indicates an expedition of corrosion process through both metal dissolution and oxidizer reduction. (b) CO2 Loading. CO2 loading is apparently an important process parameter influencing corrosiveness in the AMP system as shown in Figure 6. The results show that higher CO2 loading induces higher corrosion rate. With increasing CO2 loading from fresh to high loading, corrosion rate in the 2 kmol/m3 AMP system
increases from a negligible value to 24.2 and 56.9 mpy at 30 and 80 °C, respectively. The influence of CO2 loading on corrosion rate can be simply explained by reactions 3, 4, and 5. An increase in CO2 loading yields higher amounts of RNH3+ and HCO3- which in turn dissociate and produce more hydrogen ion (H+). The increasing amount of H+ due to the higher CO2 loading can be expressed by pH reduction in Figure 7. As mentioned previously, increasing the amount of H+ allows the corrosion process to proceed faster, thus causing higher corrosion rate. The effect of CO2 loading on corrosion behavior can also be illustrated by polarization curves in Figure 8. The polarization curves mainly show an effect of CO2 loading on cathodic current density, i.e., an increase in CO2 loading enhances rate of oxidizer reduction. As a result, corrosion rate of the system is accelerated. (c) AMP Concentration. AMP concentration also plays an important role on system corrosiveness. Two distinct corrosion behaviors affected by AMP concentration are illustrated in Figure 9. First behavior involves an increase in corrosion rate when AMP concentration increases. Considering a curve tested at 80 °C and 0.2 CO2 loading, corrosion rate raises from 4.3 to 30.9 mpy as AMP concentration increases from 1 to 3 kmol/m3. A reason for this behavior can again be explained by
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Figure 8. Effect of CO2 loading on polarization curve in AMPCO2 system (AMP concentration ) 2 kmol/m3 and liquid temperature ) 30 °C).
Figure 10. Comparison of corrosiveness (AMP concentration ) 3 kmol/m3 and liquid temperature ) 80 °C).
Figure 11. Polarization curves for AMP and MEA systems at lean CO2 loading condition (AMP concentration ) 3 kmol/m3 and liquid temperature ) 80 °C). Figure 9. Effect of AMP concentration on corrosion rate in AMPCO2 system (AMP concentration ) 2 kmol/m3).
reactions taking place in the system. Once AMP concentration increases, its CO2 absorption capacity is greater. As a result, higher amounts of RNH3+ and HCO3- are produced in a main absorption reaction as shown in reaction 3. The increasing amounts of these products consequently yield higher amounts of corroding oxidizer, thereby causing a higher corrosion rate. For a second behavior, the corrosion rate seems to retard and gradually decrease when AMP concentration is beyond 3 kmol/m3. From Figure 9, the corrosion rate at 80 °C and 0.2 CO2 loading decreases from 30.9 to 22.9 mpy when AMP concentration changes from 3 to 4 kmol/ m3. This might be due to hydrolysis of the carbamate compound shown in reaction 2. Once AMP concentration increases, available water in liquid solution tends to decrease. The amount of bicarbonate ions (HCO3-) that results from hydrolysis of carbamate is therefore diminished because of the limited water. This leads to reduction of corroding oxidizer, thus decelerating corrosion rate. Comparison of Corrosiveness with the MEA System. Regarding the results of process parameter effects, the plant areas exposed to elevated temperature and/or high CO2 loading are likely to encounter severe corrosion. Therefore, corrosiveness comparison between
AMP and MEA systems was focused on elevated temperature with different degrees of CO2 loading. Two testing conditions selected for this work are 80 °C and lean CO2 loading and 80 °C and saturation CO2 loading. The former simulates plant areas subject to hot-lean solution after regeneration, e.g., pump and lean side of rich-lean heat exchanger, while the latter represents plant areas subject to hot-rich solution before regeneration, e.g., rich side of heat exchanger. The results in Figure 10 show that the AMP system generally induces less corrosiveness than the MEA system at 80 °C. Considering the lean condition, corrosion rate in the AMP system is 4.2 mpy while that in the MEA system is 15.5 mpy. A possible explanation for this is that AMP contains less CO2 loading than MEA does at lean condition, i.e., 0.030 CO2 loading for AMP and 0.157 CO2 loading for MEA. Such relatively mild corrosiveness in the AMP system can also be observed from polarization curves. As illustrated in Figure 11, the polarization curve for AMP apparently lies on the left side of that for MEA. The anodic and cathodic current densities of the AMP curve are generally less than those of the MEA curve. This means the AMP system always provides a less active environment for carbon steel than the MEA system throughout the active-passive potential range at this testing condition.
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Considering corrosiveness in the AMP system at the saturation condition in Figure 10, the corrosion rate in the AMP system is also less than that in the MEA system. However, it should be noted that a difference in corrosion rate between AMP and MEA systems at saturation condition is relatively small in comparison with that at lean condition. This is probably due to similarity between CO2 loadings in both systems at the saturation condition, i.e., 0.554 CO2 loading for AMP and 0.565 CO2 loading for MEA. 5. Conclusion Process parameters play an essential role on corrosiveness in the AMP-CO2 system. Increases in liquid temperature and CO2 loading significantly increase corrosion rate. The relationship between either liquid temperature or CO2 loading and corrosion rate is disproportional. The corrosion rate is also affected by AMP concentration in two distinct ways, i.e., it increases with AMP concentration under 3 kmol/m3 and decreases with AMP concentration beyond 3 kmol/m3. In comparison with the MEA system, the AMP system apparently induces less corrosiveness at elevated temperature. Relatively mild corrosiveness in the AMP system is mainly due to CO2 loading in the liquid solution. This behavior is shown especially at lean conditions where the AMP solution by nature contains much less CO2 than the MEA solution. Acknowledgment Financial support from the Faculty of Graduate Studies and Research, University of Regina, the Natural Sciences and Engineering Research Council of Canada (NSERC), and Saskferco Products, Inc., are gratefully acknowledged. Literature Cited (1) Kohl, A. L.; Riesenfeld, F. C. Gas Purification, 4th ed.; Gulf Publishing Co.: Houston, TX, 1985. (2) Tontiwachwuthikul, P.; Meisen, A.; Lim, C. J. Solubility of CO2 in 2-Amino-2-Methyl-1-Propanol Solutions. J. Chem. Eng. Data 1991, 36, 130-133.
(3) Sartori, G.; Ho, W. S.; Thaler, W. A.; Chludzinski, G. R.; Wilbur, J. C. Sterically hindered Amines for Acid Gas Absorption. In Carbon Dioxide Chemistry: Environmental Issues; Paul, J., Pradier, C., Eds.; The Royal Society of Chemistry: Cambridge, U.K., 1994. (4) Kohl, A. L.; Nielsen, R. B. Gas Purification, 5th ed.; Gulf Publishing Co.: Houston, TX, 1997. (5) DuPart, M. S.; Bacon, T. R.; Edwards, D. J. Part2Understanding Corrosion in Alkanolamine Gas Treating Plants. Hydrocarbon Process. 1993, May, 89-94. (6) Hawkes, E. N.; Mago, B. F. Stop MEA CO2 Unit Corrosion. Hydrocarbon Process. 1971, 50 (8), 109-112. (7) Gerus, B. R. D. Detection and Mitigation of Weight Loss Corrosion in Sour Gas Gathering Systems. In H2S Corrosion in Oil & Gas Production - A Compilation of Classic Papers 1981; pp 888-903. (8) Veawab, A.; Tontiwachwuthikul, P.; Bhole, S. D. Studies of Corrosion and Corrosion Control in CO2-2-Amino-2-Methyl-1Propanol (AMP) Environment. Ind. Eng. Chem. Res. 1997, 36, 264-269. (9) Danckwerts, P. V.; McNeil, K. M. The Absorption of Carbon Dioxide into Aqueous Amine Solutions and the Effect of Catalysis. Trans. 1nst. Chem. Eng. 1967, 45, T32. (10) Chakraborty, A. K.; Astarita, G.; Bischoff, K. B. CO2 Absorption in Aqueous Solutions of Hindered Amines. Chem. Eng. Sci. 1989, 41, 997-1003. (11) ASTM Standard E3-80 Standard Methods of Preparation of Metallographic Specimens. Annu. Book ASTM Stand. 1989, 03.01. (12) Horowitz, W. Association of Official Analytical Chemists (AOAC) Methods, 12th ed.; George Banta, 1975. (13) Gas Conditioning Fact Book; The Dow Chemical Co., 1962. (14) Kritpiphat, W.; Tontiwachwuthikul, P. New Modified KentEisenberg Model for Prediction Carbon Dioxide Solubility in Aqueous 2-Amino-2-Methyl-1-Propanol (AMP) Solutions. Chem. Eng. Commun. 1996, 144, 77-83. (15) Boboian, R. Electrochemical Techniques for Corrosion; National Association of Corrosion Engineers: Houston, TX, 1977. (16) ASTM Standard G5-94 Standard Reference Test Method for Making Potentiostatic and Potentiodynamic Anodic Polarization Measurements. Annu. Book ASTM Stand. 1994, 03.02. (17) Jones, D. A. Principles and Prevention of Corrosion; Macmillen Publishing Co.: New York, 1992.
Received for review May 27, 1998 Revised manuscript received October 1, 1998 Accepted October 16, 1998 IE980325C
