corrosion behavior of carbon steel in the co2 absorption process

Corrosion Behavior of Carbon Steel in the CO2 Absorption ProcessUsing Aqueous Amine Solutions

Amornvadee Veawab, Paitoon Tontiwachwuthikul,* and Amit Chakma

Process Systems Laboratory, Faculty of Engineering, University of Regina, Regina,Saskatchewan, Canada S4S 0A2

The present study provides comprehensive information on the effects of process parametervariations on the corrosion behavior of carbon steel in CO2 absorption systems using aqueousamine solutions. The process parameters of interest are amine type, concentration of the aminesolutions, solution temperature, CO2 loading, and oxygen content. An electrochemical testingtechnique was used for determining the system corrosiveness in terms of polarization behaviorand corrosion rate. The experimental results suggest that the corrosion behavior is considerablysensitive to the variations in the process parameters. Increases in amine concentration, solutiontemperature, CO2 loading, and oxygen content accelerate the corrosion rate in the systems. Inaddition, different amine types yield different degrees of the system corrosiveness. Comparisonsof the corrosiveness among single amine systems as well as between mixed amine systems andtheir precursors are also presented.

Introduction

The CO2 absorption process using aqueous aminesolutions has been extensively used for the removal ofCO2 from gas streams in many industries. Commonindustrial applications include natural gas processing,coal gasification, and manufacturing of hydrogen andammonia. In these processes, purification of process gasstreams is to meet the needed requirements of productquality and to minimize operational difficulties, whichmay occur when the gas streams are further used indownstream processes. Other applications involve theproduction of CO2 for uses in food, beverage, andpetroleum industries. Besides such industrial applica-tions, the CO2 absorption process is considered to be apotential technique for reducing greenhouse gas emis-sion from flue gas streams.

Historically, the CO2 absorption process using aque-ous amine solutions has long encountered corrosionproblems. On the basis of plant experiences,1-6 corrosionseems to take place in several plant locations includingthe bottom portion of the absorber, the rich-lean heatexchanger, the regenerator, and the reboiler. Bothuniform corrosion and localized attacks such as pitting,galvanic, erosion, stress cracking, and intergranularcorrosion were commonly detected. In general, the waysin which the process equipment was designed, fabri-cated, installed, and operated are key factors in deter-mining the corrosion types and degrees of the systemcorrosiveness.

According to Kohl and Nielsen,7 corrosion is consid-ered to be one of the most severe operational problemsin the CO2 absorption process. Chronic corrosion canlead to a direct impact on the plant’s economy since itresults in unplanned downtime, production losses,reduced equipment life, and even injury or death.6 Theunplanned downtime of a typical plant can cost between

$10 000 and $30 000 per day in terms of productionlosses.8 Besides, the downtime also leads to a largeportion of expenditure necessary for restoring the cor-roded systems and for treatments initiated to mitigatethe corrosion. As stated by Gerus,9 millions of dollarsare annually spent on this particular purpose.

In addition to the above direct impacts, the corrosionproblems also indirectly affect the plant’s economy bylimiting the operating ranges of the process. Generally,flexibility in varying the operating conditions is reduceddue to excessive corrosion. Operating the process beyondthe typical conditions may also cause a tremendousincrease in the system corrosiveness.6,10 Because of suchlimitations, the capacity of existing plants may not beeasily increased at reasonable expenses.

In practice, corrosion could be controlled by severalapproaches: (i) use of proper equipment design, (ii) useof highly resistant materials, and (iii) use of chemicaltreatments. However, the effectiveness of the controllingapproaches could be affected by variations in theoperating conditions of the process. For instance, byreducing the flow rate of the absorption solution, thecorrosion protection efficiency might be deteriorated dueto increases in the degrees of process parameters suchas CO2 loading and solution temperature. This wouldresult in excessive corrosion in the system. Therefore,understanding the corrosion behavior due to variationsin the process parameters becomes necessary for pre-venting such excessive corrosion. In the present study,comprehensive information on the effect of processparameters on corrosion behavior is provided. Theprocess parameters studied include the type of amine,amine concentration, solution temperature, CO2 loading,and oxygen (O2) content. Ranges of the testing condi-tions are provided in Table 1.

Experiments

Experimental Setup. The experiments were carriedout in a corrosion cell using an electrochemical tech-nique for corrosion analysis. The experimental setup

* To whom correspondence should be addressed. Phone:(306) 585-4726. Fax: (306) 585-4855. E-mail: [email protected].

3917Ind. Eng. Chem. Res. 1999, 38, 3917-3924

10.1021/ie9901630 CCC: $18.00 © 1999 American Chemical SocietyPublished on Web 09/08/1999

consisted of two main components, the corrosion cell,model K47, and potentiostat, model 273 (EG&G Instru-ments/Princeton Applied Research, NJ), as shown inFigure 1. The corrosion cell includes a set of a 1 L flask,high-density/nonpermeable graphite counter electrodes,a calomel reference electrode, a reference electrodebridge tube, a purge/vent tube, and a leak-proof as-sembly for mounting the specimen. The potentiostat hasan accuracy of the applied potential and current mea-surement of (0.2% of the reading. A computer with adata acquisition program is connected to the poten-tiostat to record and analyze the produced corrosiondata.

Preparation of Specimens. The specimens forcorrosion tests in this study were made of carbon steel1020. Their chemical compositions are C, 0.20; Mn, 0.51;P, 0.013; S, 0.039; Si, 0.17; and Fe, balance. Thespecimens were cut into cylindrical shape: 1/2 in. (12.7mm) long, 3/8 in. (9.5 mm) diameter, drilled to a depthof 1/4 in. (6.4 mm), and tapped to accept a 3-48 UNC-2A 5/16 in. (8 mm) thread depth. Within 1 h prior tothe tests, the specimens were prepared by wet grindingwith 600 grit silicon carbide papers, degreasing withmethanol, and drying with hot air, in accordance withthe ASTM standard E3-80.11

Preparation of Absorption Solutions. The CO2absorption solvents primarily used in the present study

are aqueous solutions of single amines. Four types ofamines including primary, secondary, tertiary, andsterically hindered amines were examined. Because oftheir popularity, monoethanolamine (MEA), diethano-lamine (DEA), methyldiethanolamine (MDEA), and2-amino-2-methyl-1-propanol (AMP) were chosen asrepresentatives of each amine type. In addition, aqueoussolutions of mixed amines, which have currently gaineda great deal of attention by solvent developers, were aswell investigated. These include mixtures of MEA-MDEA, DEA-MDEA, and MEA-AMP.

The prepared aqueous amine solutions can be clas-sified into two categories: (i) fresh solution containingno or little trace of CO2 and (ii) loaded solution contain-ing certain amounts of CO2. The fresh solution wassimply prepared by diluting the pure solvents withdeionized water to a desired concentration. The concen-tration of the prepared solutions was determined bytitration with a 1 N standard hydrochloric acid (HCl)solution using methyl orange as an indicator. For theloaded solution, the preparation involved mixing a freshsolution with a CO2 saturated solution previouslyprepared by purging CO2 gas into the fresh solution forapproximately 8 h. Amounts of the absorbed CO2 in theloaded solution represented as CO2 loading (mol of CO2/mol of amine) were determined by chemical analysis

Table 1. Process Parameters and Testing Conditions

parameter testing condition

amine type monoethanolamine (MEA)diethanolamine (DEA)methyldiethanolamine (MDEA)2-amino-2-methyl-1-propanol (AMP)mixture of MEA and MDEA (1:1)mixture of DEA and MDEA (1:1)mixture of MEA and AMP (1:1)

at 3 kmol/m3, 80 °C, and CO2 saturationat 3 kmol/m3, 80 °C, and 0.2 CO2 loading (mol/mol)

amine concentration 1-5 kmol/m3

at 80 °C and 0.2 CO2 loading (mol/mol) for MEA, DEA, and AMPtemperature 30-80 °C

at 2 kmol/m3 and 0.2 CO2 loading (mol/mol) for MEA, DEA, and AMPCO2 loading 0.0-0.4 mol/mol

at 2 kmol/m3 and 80 °C for MEA, DEA, and AMPoxygen content nil to 10% feed gas

at 2 kmol/m3 MEA, 80 °C, and 12% CO2 in the feed gas

Figure 1. Experimental setup for the electrochemical corrosion test.

3918 Ind. Eng. Chem. Res., Vol. 38, No. 10, 1999

involving acidifying a given quantity of the liquidsample by adding an excess amount of HCl solution.12

Experimental Procedure. Prior to the experiments,the experimental technique and instrumentation werevalidated to ensure reliability of the obtained data. Thevalidation was performed in accordance with the ASTMG5-94 by conducting a potentiodynamic anodic polariza-tion test on a stainless steel-430 specimen in a 1 Nsulfuric acid (H2SO4) solution at 30 °C.13 The generatedpolarization curve was in good agreement with thereference curves provided by the ASTM, thus validatingthe experimental technique and instrumentation.

To begin the experiments, the corrosion cell wasimmersed in a water bath where the temperature wasset and controlled within an accuracy of (0.1 °C. A gasstream of nitrogen (N2), N2-CO2 mixture, or N2-CO2-O2 mixture was introduced into the corrosion cell tomaintain the prepared CO2 loading in the tested solu-tion. The chemical analysis for the CO2 loading mea-surement was performed periodically to ascertain thatthe CO2 loading was kept at the desired level duringthe experiment. Prior to the corrosion measurement, allpotentiostat cables were properly connected to threepoints of the corrosion cell: the graphite counter elec-trodes, the calomel reference electrode, and the speci-men holder. The corrosion potential (Ecorr) of the speci-men against the reference electrode was recorded atequilibrium when a reading of the potential remainedconstant for at least 5 min. The potentiodynamicpolarization was then initiated with a scanning rate of0.60 V/h. All experimental data including applied po-tentials and produced currents were continuously re-corded and stored in the computer program. To observethe corrosion behavior of a given experimental run, apolarization curve, a plot between specimen potentialand current density, was created. Then, the corrosionrate was finally determined by the Tafel extrapolationtechnique detailed in Baboian.14 It should be noted thatthe corrosion data presented in this paper are theaverage corrosion rates ((5% of replicated data).

Results and Discussion

Amine Type. The effect of amine type on corrosionbehavior was examined by conducting the experimentsin 3 kmol/m3 aqueous amine solutions under two dif-ferent testing conditions: (i) 80 °C and CO2 saturationand (ii) 80 °C and 0.2 CO2 loading. Results from theformer condition reveal corrosion behavior under apractical condition where CO2 loading in each aminesystem could be varied depending upon its CO2 solubil-ity characteristic. For the latter condition, resultsprovide an indication of the actual influence of theamine type under an exactly identical condition wherethe interaction between the process parameters isnegligible.

Under the CO2 saturation condition, the amine typehas a great effect on the system corrosiveness. Corrosionrates for various amines are shown in Figure 2. MEAhad the highest corrosion rate at 136.4 mpy followedby AMP at 125.9 mpy. MDEA was the least corrosivewith a corrosion rate of 67.6 mpy while DEA’s corrosionrate was 89.1 mpy.

A similar sequence of the system corrosiveness canalso be observed from the polarization curves. Bynature, corrosion is an electrochemical process consist-

ing of anodic and cathodic reactions. Metal dissolutionis considered the anodic reaction while oxidizer reduc-tion is considered the cathodic reaction. Higher anodicand/or cathodic current densities basically indicatehigher rates of the metal dissolution and/or the oxidizerreduction, thus leading to a higher corrosion rate.According to Figure 3, among MEA, DEA, and MDEAsystems, the MEA system obviously yields the greatestanodic and cathodic current densities throughout theactive region. When compared with the AMP, the MEAsystem still induces a greater corrosion rate since itproduces significantly higher cathodic current density,despite the relatively smaller anodic current density.This suggests that the MEA system is the most corrosive

Figure 2. Comparison of corrosion rates among single aminesystems under 3 kmol/m3, 80 °C, and CO2 saturation.

Figure 3. Polarization behaviors of carbon steel in single aminesystems under 3 kmol/m3, 80 °C, and CO2 saturation.

Figure 4. Comparison of corrosion rates among mixed aminesystems and their precursors under 3 kmol/m3 with a mixing ratioof 1:1, 80 °C, and CO2 saturation.

Ind. Eng. Chem. Res., Vol. 38, No. 10, 1999 3919

environment. In addition, Figure 3 also indicates thatthe MDEA system is the least active environment; i.e.,it generally generates the smallest current densitiesamong the other systems.

Corrosiveness in the mixed amine systems was alsoinvestigated for MEA-MDEA, DEA-MDEA, and MEA-AMP mixtures. Total amine concentration was kept at3 kmol/m3, and the experiments were conducted at 80°C and under CO2 saturation. From Figure 4, it can beseen that the corrosiveness in a particular mixed aminesystem appears to be a combination of those in itsprecursor systems. For instance, a mixed MEA-MDEAsystem (a mixing ratio of 1:1) yields a corrosion rate of77.6 mpy while the MEA and the MDEA systems inducethe rates of 136.4 and 67.6 mpy, respectively. Similartrends of such behavior are also found in the mixedsystems of DEA-MDEA and MEA-AMP. However, itshould be noted that the corrosion rates in the mixedamine systems presented in this study were generatedon the basis of only a mixing ratio of 1:1. With differentmixing ratios, the corrosiveness relationship between

the mixed amine systems and their precursors could bedifferent.

The corrosion behavior in the mixed amine systemscan also be seen from polarization results shown inFigure 5. The hybrid polarization behavior is found inthe cases of the MEA-MDEA and the DEA-MDEAsystems, both the cathodic and anodic current densitiesof which are between those produced in the precursorsystems. This obviously indicates the hybrid corrosionrates in the mixed amine systems. Unlike the above,the MEA-AMP system presents the hybrid polarizationbehavior only at the cathodic side even though itscorrosiveness is a combination of the precursors.

The influence of the amine type on the corrosionbehavior is probably caused by differences in theamounts of CO2 absorbed into the tested solutions underthe CO2 saturation condition. The greater the CO2loading, the higher the corrosion rate. This trend canbe seen from Table 2, containing data of saturated CO2loading and corrosion rate in single and mixed aminesystems. It is conceivable that the CO2 loading is aprimary contributor to the effect of amine type oncorrosiveness in both single and mixed amine systems.

As previously mentioned, the corrosion experimentswere conducted under the testing condition of 3 kmol/m3, 80 °C, and 0.2 CO2 loading. The experimentalresults shown in Figure 6 indicate that the amine typeitself also has an affect on the system corrosiveness eventhough the influence of the CO2 loading is eliminated.From the figure, corrosion rates in the MEA and theDEA systems seem to be comparable while the corrosionrate in the AMP system is apparently superior to thosein the other two systems. This is perhaps due todifferences in the amounts of active components, par-ticularly bicarbonate ion (HCO3

-), in the solutions.At the identical CO2 loading, temperature, and amine

concentration, the AMP system tentatively contains agreater amount of the HCO3

- than the MEA and theDEA systems. Consider the main CO2 absorption reac-

Figure 5. Polarization behaviors of carbon steel in mixed aminesystems and their precursors under 3 kmol/m3, mixing ratio 1:1,80 °C, and CO2 saturation: (a, top) mixture of MEA and MDEA,(b, middle) mixture of DEA and MDEA, (c, bottom) mixture of MEAand AMP.

Table 2. CO2 Loading in Aqueous Amine-CO2 System atthe Testing Condition of 3 kmol/m3, 80 °C, and CO2Saturation

amine typeCO2 loading

(mol/mol)corrosion rate

(mpy)

MEA 0.565 136.4DEA 0.442 89.1MDEA 0.243 67.6AMP 0.554 125.9mixture of MEA and MDEA 0.435 77.6mixture of DEA and MDEA 0.365 72.4mixture of MEA and AMP 0.561 127.3

Figure 6. Comparison of corrosion rates among single aminesystems under 3 kmol/m3, 80 °C, and 0.2 CO2 loading.


tions taking place in the aqueous amine-CO2 systemsas follows:

RNH2, RNHCOO-, RNH3+, and HCO3

- denote amine,carbamate ion, protonated amine ion, and bicarbonateion, respectively. For the MEA and the DEA systems,formation of carbamate (reaction 1) is a major reactionwhile hydrolysis of carbamate (reaction 2) hardly takesplace. On the contrary, both reactions 1 and 2 playmajor roles in CO2 absorption in the AMP system. Thisis basically due to low stability of the carbamatecompound.16 As a consequence, the greater amount ofthe HCO3

- species is expected to be present in the AMPsystem rather than in the MEA and the DEA systems.

HCO3- is basically considered a corroding agent in a

typical aqueous solution containing dissolved CO2. Acorrosion reaction between iron and HCO3

- can bewritten as17

According to reaction 3, the greater the amount ofHCO3

-, the higher the amount of iron dissolved. Thisresults in a higher corrosion rate. With this principle,the corrosion rate in the AMP system is thereforegenerally greater than those in the MEA and the DEAsystems.

Amine Concentration. Amine concentration ap-pears to have a considerable effect on the systemcorrosiveness. According to Figure 7, the corrosionbehavior affected by the amine concentration is mani-fested in two distinct manners.

First, the corrosion rate increases as the amineconcentration increases. This is found in the MEA, DEA,and AMP systems with the concentration below 3 kmol/m3. At a constant CO2 loading, increasing the amineconcentration generally leads to an increase in the totalamount of CO2 absorbed into the amine solution, result-ing in higher amounts of RNHCOO-, RNH3

+ (reaction

1), and HCO3- (reaction 2). The increasing amount of

HCO3- thus causes a greater corrosion rate in the

system.An increase in the corrosion rate with amine concen-

tration can also be observed from the polarization curvesas shown in Figure 8. Apparently, changes in the amineconcentration have an impact on the current densitiesespecially on the anodic side. The higher concentrationleads to the greater anodic current density, thus in-creasing the rate of corrosion.

Second, the corrosion rate seems to retard anddecrease gradually as the amine concentration in-creases. This behavior is found in the AMP system withthe concentration beyond 3 kmol/m3 as shown in Figure7. The decreasing corrosion rate is probably caused bythe hydrolysis of RNHCOO- shown in reaction 2. Oncethe AMP concentration increases, available water in theliquid solution tends to decrease. Therefore, the amountof HCO3

- resulting from the hydrolysis reaction isdiminished due to the limited water. This basically leadsto a reduction in the amount of the corroding oxidizer,thus decelerating the corrosion rate.

Solution Temperature. According to the experi-mental results shown in Figure 9, a variation in thetemperature of the liquid solution has a significant effecton the corrosion rate in the amine-CO2 systems.Increasing the liquid temperature considerably acceler-ates the rate of corrosion. For instance, in a 2 kmol/m3

MEA solution, the corrosion rate rises from 2.6 to 16.2mpy when the liquid temperature increases from 30 to80 °C. A similar behavior is also found in the DEA andthe AMP systems. It should be noted that the relation-ship between liquid temperature and corrosion rate isshown in exponential form.

The increasing corrosiveness resulting from the varia-tion in solution temperature could be explained by

Figure 7. Effect of amine concentration on corrosion rate under80 °C and 0.2 CO2 loading.

formation of carbamate15

2RNH2 + CO2 a RNHCOO- + RNH3+ (1)

hydrolysis of carbamate16

RNHCOO- + H2O a RNH2 + HCO3- (2)

Fe + HCO3- f FeCO3 + H+ + 2e- (3)

Figure 8. Effect of MEA concentration on polarization behaviorunder 80 °C and 0.2 CO2 loading.

Figure 9. Effect of solution temperature on corrosion rate under2 kmol/m3 and 0.2 CO2 loading.


reactions 1 and 2 together with other reactions occurringin the amine-CO2 systems as written below.15

where CO32- denotes carbonate ion. In general, tem-

perature is an essential parameter for the kinetics ofthe absorption system. Increasing the temperature coulddisturb the equilibrium among chemical species in thesystem. According to a correlation between the equilib-rium constant (K) and temperature,18 equilibrium con-stants for reactions 2, 4, and 5 increase with the solutiontemperature, thus reflecting the greater amounts of H+

and HCO3- present in the system. Under this circum-

stance, the equilibrium between the metal dissolutionand the oxidizer reduction is disturbed. To maintain theequilibrium, more metal (iron) is dissolved into thesolution and subsequently generates more electrons forthe oxidizer reduction, thus accelerating the corrosionrate. The increase in the amount of H+ as the liquidtemperature increases can be confirmed in terms of pHreduction as illustrated in Figure 10.

The effect of liquid temperature on the corrosionprocess is also indicated by polarization curves. Thepolarization results suggest that the variation in theliquid temperature obviously affects the corrosion be-havior. According to Figure 11, an increase in the liquidtemperature causes anodic and cathodic current densi-ties to rise, resulting in an acceleration of the corrosionprocess through both metal dissolution and oxidizerreduction.

CO2 Loading. CO2 loading is apparently an impor-tant process parameter influencing the corrosiveness in

the amine-CO2 systems. Increasing the CO2 loading inthe system generally leads to a greater corrosion rate.As shown in Figure 12, by increasing the CO2 loadingfrom fresh (0.0) to 0.4 mol/mol, the corrosion rate in theMEA system (2 kmol/m3 at 80 °C) increases from anegligible value to 24 mpy.

The influence of the CO2 loading on the corrosion ratecan be simply explained by reactions 1-5. An increasein CO2 loading yields higher amounts of HCO3

- andRNH3

+, which in turn dissociates and finally producesmore hydrogen ion (H+). The increase in the H+ amountdue to the increasing CO2 loading can be confirmed bythe pH reduction reported in Figure 13. As mentionedpreviously, increasing the amounts of H+ and HCO3

-

drives the corrosion process to proceed faster, thuscausing a higher corrosion rate.

Figure 14 demonstrates the effect of CO2 loading onthe corrosion polarization behavior. The polarizationcurves indicate that the variation in the CO2 loadinghas a significant effect on the cathodic current densitybut a small effect on the anodic current density. This

Figure 10. Effect of liquid temperature on pH under 2 kmol/m3

MEA and 0.2 CO2 loading.

Figure 11. Effect of solution temperature on polarization behav-ior under 2 kmol/m3 MEA and 0.2 CO2 loading.

dissociation of protonated amine ion

RNH3+ a RNH2 + H+ (4)

dissociation of bicarbonate ion

HCO3- a CO3

2- + H+ (5)

Figure 12. Effect of CO2 loading on corrosion rate under 2 kmol/m3 and 80 °C.

Figure 13. Effect of CO2 loading on pH under 2 kmol/m3 MEAand 80 °C.

Figure 14. Effect of CO2 loading on polarization curve under 2kmol/m3 MEA and 80 °C.


behavior suggests that an increase in the CO2 loadingprimarily enhances the rate of oxidizer reduction, caus-ing a more corrosive environment.

Oxygen Content. The effect of oxygen content on thesystem corrosiveness is illustrated in Figure 15. Theresults show that higher oxygen content leads to ahigher corrosion rate. As can be seen from Figure 15,the corrosion rate of the MEA system (under 2 kmol/m3, 80 °C, and 12% CO2 in the feed gas) increases from32.3 to 45.7 mpy when the oxygen content in the feedgas increases from 0 to 10%. A similar effect of theoxygen content can also be observed from the corrosionexperiments conducted at a temperature of 30 °C. Anexplanation for this effect involves the reactions ofoxygen corrosion on iron as shown below.19

where Fe(OH)2 and Fe(OH)3 denote ferrous hydroxideand ferric hydroxide, respectively. According to reactions6 and 7, once the dissolved oxygen content increases,more metal is oxidized and forms ferrous and ferrichydroxide to maintain the system equilibrium, resultingin a higher corrosion rate.

In addition, Figure 15 also provides a comparisonbetween the influences of the oxygen content and thetemperature on the system corrosiveness. Despite thelower content of dissolved oxygen in the solution, thecorrosion rates at the elevated temperature (80 °C) arestill greater than those tested under the lower temper-ature (30 °C). This suggests that the oxygen content hasrelatively less influence on the system corrosivenessthan the solution temperature.

Conclusions

Variations in the process parameters obviously haveinfluences on the corrosion behavior of carbon steel inthe aqueous amine-CO2 systems. Principal conclusionscan be drawn as follows.

Amine type affects system corrosiveness. The corro-sivity of CO2 saturated amines decreases in the orderMEA > AMP > DEA > MDEA, and corrosion rates inthe mixed amine systems lie between those in theprecursor systems. CO2 loading appears to be theprimary cause of corrosion. However, under an identical

CO2 loading condition, the corrosion rate still varieswith amine type.

Two different corrosion behaviors are observed as aresult of the amine concentration variations. First,increasing the amine concentration accelerates thesystem corrosion rate. Second, the corrosion rate de-creases gradually as the amine concentration increases.

Variations in the liquid temperature, the CO2 loading,and the oxygen content have significant impact on thesystem corrosiveness. Increasing each parameter leadsto a greater corrosion rate.

Acknowledgment

Financial support from the Faculty of GraduateStudies and Research of the University of Regina, theNatural Sciences and Engineering Research Council ofCanada (NSERC), and Saskferco Products Inc. is grate-fully acknowledged.

Literature Cited

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(2) Hall, W. D.; Barron, J. G. Solving Gas Treating Problems-ADifferent Approach. Proceedings of Gas Conditioning Conference,31st Annual, University of Oklahoma, 1981; pp C1-C13.

(3) Heisler, L.; Weiss, I. H. Operating Experience at Aderklaawith Alkanolamine Gas Treating Plants for Sour Natural GasSweetening. Proceedings of Gas Conditioning Conference, 25th

Annual, University of Oklahoma, 1975; pp H1-H22.(4) Litschewski, M. J. More Experiences with Corrosion and

Fouling in a Refinery Amine System. Proceedings of Corrosion 96,Denver, CO, 1996; National Association of Corrosion Engineers:Houston, TX; paper no. 391.

(5) Smith, R. F.; Younger, A. H. Operating Experiences ofCanadian Diethanolamine Plants. Proceedings of Gas ConditioningConference, 22nd Annual, University of Oklahoma, 1972; pp E1-E17.

(6) DuPart, M. S.; Bacon, T. R.; Edwards, D. J. Part2-Understanding Corrosion in Alkanolamine Gas Treating Plants.Hydrocarbon Processing 1993 (May), 89-94.

(7) Kohl, A. L.; Nielsen, R. B. Gas Purification, 5th ed.; GulfPublishing Co.: Houston, TX, 1997.

(8) Hawkes, E. N.; Mago, B. F. Stop MEA CO2 Unit Corrosion.Hydrocarbon Processing 1971, 50 (8), 109-112.

(9) Gerus, B. R. D. Detection and Mitigation of Weight LossCorrosion in Sour Gas Gathering Systems. In H2S Corrosion inOil & Gas ProductionsA Compilation of Classic Papers; NationalAssociation of Corrosion Engineers: Houston, TX, 1981; pp 888-903.

(10) Kohl, A. L.; Riesenfeld, F. C. Gas Purification, 4th ed.; GulfPublishing Co.: Houston, TX, 1985.

(11) ASTM Standard E3-80 Standard Methods of Preparationof Metallographic Specimens. Annual Book of ASTM Standards;1989; Vol. 03.01.

(12) Horowitz, W. Association of Official Analytical Chemists(AOAC) Methods, 12th ed.; George Banta: 1975.

(13) ASTM Standard G5-94 Standard Reference Test Methodfor Making Potentiostatic and Potentiodynamic Anodic Polariza-tion Measurements. Annual Book of ASTM Standards; 1994; Vol.03.02.

(14) Boboian, R. Electrochemical Techniques for Corrosion;National Association of Corrosion Engineers: Houston, TX, 1977.

(15) Danckwerts, P. V.; McNeil, K. M. The Absorption of CarbonDioxide into Aqueous Amine Solutions and the effect of Catalysis.Trans. Inst. Chem. Eng. 1967, 45, T32.

(16) Chakraborty, A. K.; Astarita, G.; Bischoff, K. B. CO2Absorption in Aqueous Solutions of Hindered Amines. Chem. Eng.Sci. 1989, 41, 997-1003.

Figure 15. Effect of oxygen content on corrosion rate under 2kmol/m3 MEA and 12% CO2 in feed gas.

2Fe + 2H2O + O2 f 2Fe(OH)2 (6)

2Fe(OH)2 + 2H2O + (1/2)O2 f 2Fe(OH)3 (7)


(17) Burstein, G. T.; Davies, D. H. The Effects of Bicarbonateon the Corrosion and Passivation of Iron. Corrosion 1980, 36 (8),416.

(18) Austgen, D. M.; Rochelle, G. T.; Peng, X.; Chen, C. Modelof Vapor-Liquid Equilibria for Aqueous Acid GassAlkanolamineSystems Using the ElectrolytesNRTL Equation. Ind. Eng. Chem.Res. 1989, 28, 1060-1073.

(19) Fontana, M. G. Corrosion Engineering, 3rd ed.; McGraw-Hill Book Co.: New York, 1986.

Received for review March 4, 1999Revised manuscript received July 7, 1999

Accepted July 9, 1999

IE9901630


corrosion behavior of carbon steel in the co2 absorption process

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