future science group oxidation reaction

future science group 659ISSN 1758-300410.4155/CMT.11.63 © 2011 Future Science Ltd

Fossil fuel power plants are a major source of CO2 emis-

sions, which gives rise to an enhanced GHG effect. To control emissions and reduce this effect, a

CO

2 capture

technique may be integrated into the power plant. In the case of low pressure coal-derived flue gas streams, the application of a chemical-absorption process using an aqueous alkanolamine solution has been found to be the most effective of such a CO

2 capture approach. However,

corrosion is a major drawback, which prevents the amine process from achieving its highest possible efficiency. Corrosion is an electrochemical process involving the transfer of electrons within the construction material, resulting in its deterioration. The electrochemical pro-cess is a redox reaction, consisting of two chemical reac-tions known as oxidation and reduction [1,2]. When a metal is immersed in a given solution, redox occurs at the surface of the metal, causing the metal to corrode. For example, corrosion of zinc in an acid environment proceeds according to the following reactions:Overall reaction:

Zn + 2H+ ← → Zn2+ + H2

Equation 1

Oxidation reaction:

Zn ← → Zn2+ + 2e-

Equation 2Reduction reaction:

2H+ + 2e- ← → H2

Equation 3At equilibrium, the electrode potential (E) is referred to as reversible electrode potential (E

rev). The corrosion

electrode potential (ECORR

) is equivalent to Erev

and used specifically for corrosion reactions. When a potential is applied to an equilibrium system, it causes the potential to shift and deviate from E

CORR to E. The potential

deviation is known as polarization (h), which can be either positive or negative. When h is positive, the metal surface is driven toward the anodic side of the reac-tions and loses its electrons, which is termed as anodic polarization, while cathodic polarization occurs when h is negative.

When a number of half-reactions occur simultane-ously on the metal surface, ‘mixed potential theory’ must be utilized to create polarization curves. The theory

Carbon Management (2011) 2(6), 659–675

Part 3: Corrosion and prevention in post-combustion CO2 capture systems

Chintana Saiwan*1, Teeradet Supap2, Raphael O Idem2 & Paitoon Tontiwachwuthikul2,3

This article is part 3 of the review series on ‘Recent progress and new development of post-combustion carbon capture technology using reactive solvents’. This review focuses on alkanolamine absorption during post-combustion CO2 capture from coal-fired flue gas, looking at a range of absorbents, including those that are commonly used, as well as blended and new solvents. The effects on corrosion of blended and new absorbents and process parameters (e.g., amine concentration, CO2 loading, oxygen concentration, SO2 concentration and temperature) are reviewed. Also reviewed is the effect of corrosion on the formation of heat-stable salts in the absorbent stream, as well as the presence of impurities in flue gas. Finally, corrosion mechanisms are discussed and corrosion inhibition approaches are reviewed.

Review SeRieS

1Petroleum and Petrochemical College, Chulalongkorn University, Bangkok 10330, Thailand2International Test Center for CO2 Capture, Faculty of Engineering and Applied Science, University of Regina, SK S4S 0A2, Canada3Joint International Center for CO2 Capture and Storage, Department of Chemical Engineering, Hunan University, Changsha, 410082, PR China*Author for correspondence: Tel.: +1 662 218 4137; E-mail: [email protected]

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Carbon Management (2011) 2(6) future science group660

Review Series Saiwan, Supap, Idem & Tontiwachwuthikul

states that, at equilibrium, the net oxidation rate must be equal to the net reduction rate. That is, the sum of anodic oxidation currents must equal the sum of cathodic reduction currents and the net measurable current is zero.

i ia c=/ /

Equation 4Electrochemically, corrosion rate measurement is based on the determination of the oxidation current (also called corrosion current, i

CORR) at the corrosion

potential. The corrosion current is calculated as follows:

0 ati i ECORRa c- =/ /

Equation 5

i i iCORR a c= =/ /

Equation 6Application of mixed potential theory allows the deter-mination of the corrosion rate using a method known as Tafel plot.

Since the corrosion current is related directly to the corrosion rate, Tafel plot and potentiodynamic tech-niques are performed to experimentally determine i

CORR, from which the corrosion rate is calculated.

This paper reviews corrosion studies in a CO2 capture

plant. Effects of various factors including type of amine and its concentration, CO

2 loading, process parameters

(e.g., temperature) and flue gas contaminants (e.g., O2

and SO2) on corrosion are presented. Corrosion pre-

vention strategies using corrosion inhibitors are also reviewed.

Background of amine absorptionAlkanolamines as absorbents for acid-gas removal in gas-treating plants have been used in gas purification processes for more than 60 years. Commercial interest in gas purification has focused primarily on two amines, monoethanolamine (MEA) and diethanolamine (DEA), but can include other alkanolamines such as tri-ethanolamine, diisopropanolamine, methyldiethanol-amine (MDEA) and diglycolamine. Triethanolamine was first used in gas-treating plants, but was replaced by MEA, due to the latter’s low reactivity and relatively low stability. MDEA has been proven to be a selective solvent for removal of H

2S in the presence of CO

2 [3].

MDEA is less basic and has greater capacity to react with acid gas due to the fact that it is used in higher concentrations than MEA. MEA is the most widely

used solvent for CO2 absorption, due to the fact that it

has the highest alkalinity and highest volume of acid- gas removal at the fastest rate. The alkalinity of amines increases in the order of MDEA < DEA < MEA [4]. On the other hand, MEA also has some drawbacks based on its own physical characteristics, such as the high energy consumption required for CO

2 regeneration and high

vapor pressure compared with other alkanolamines, which leads to considerable vaporization and solvent loss. In addition, amines are degraded upon contact with oxygen, following which the degradation prod-ucts become corrosive agents and consequently cause equipment corrosion in the absorption plant [5,6]. The corrosion rates of amines increase in the order of MEA > DEA > MDEA [4].

Rooney and DuPart reviewed the role of oxygen in oxidative degradation of amines and corrosivity of these degradation products [7]. To reduce the corrosion rate, the solvent strength is kept at 20–30% amine by weight in water, resulting in relatively large equipment sizes and solvent regeneration costs. Also, there have been attempts to use blended solvents, such as pair-ing the slower rate of MDEA with the faster rate of DEA [3] or mixing MDEA with piperazine (PZ), a rate-promoting agent [4,8,101]. The process might also be modified to incorporate inhibitors that reduce solvent degradation and equipment corrosion. For instance, Bhat et al. reported the use of inorganic inhibitors in an aqueous solution for oil and gas applications [102]. The corrosion inhibitions combine the effects of anodic inhibitors (ammonium heptamolybdate or sodium orthovanadate), cathodic inhibitors (cerium chloride) and metal complexing ligand (trisodium citrate-2-hy-drate). Khusnutdinov et al. disclosed 2-propyl-3-ethyl-8-oxychinoline-ZnCl

2 complex as a steel corrosion

inhibitor [103]. The complex inhibitor was applied in petroleum production in mineralized media with high O

2 content. Abdrakhmanov et al. proposed an organic

inhibitor, N-acetyl-2-(2,3-dihydroxycilopentenyl) ani-line in mineralized water petroleum solutions including H

2S [104].

Post-combustion CO2 capture from coal-fired flue gas CO

2 comprises the largest fraction of GHG emitted into

the atmosphere. In order to comply with anticipated future environmental regulations, CO

2 in flue gas will

need to be captured prior to release into the atmosphere. CO

2 capture using chemical or physical absorption is a

likely technology for efficiently reducing large volumes of CO

2 at emission sources to comply with these antici-

pated regulations. An effective technique is chemical absorption using aqueous alkanolamine solutions [9]. Amine absorption technology for gas processing has

Key terms

Corrosion: Electrochemical process involving the transfer of electrons in oxidation–reduction reaction within the construction material, resulting in its deterioration.

Corrosion inhibitors: Chemical additives added to a process to decrease corrosion rate of construction materials, such as metal or alloy.

Corrosion & prevention in post-combustion CO2 capture systems Review Series

future science group www.future-science.com 661

been readily adapted for capturing CO2 from coal-fired

power plants and could be for other worldwide large CO

2 emission sources, such as steel manufactories,

cement production, chemical industries and oil refin-eries (Table 1). However, power plants using fossil fuels generate the most CO

2 emissions [201].

Natural gas feed composition is typically composed of 75% light hydrocarbons (C

1–C

5), 13–15% CO

2 and

no O2 [10], while fl ue gas composition from coal combus- while fl ue gas composition from coal combus-while flue gas composition from coal combus-

tion also includes O2, N

2 and trace contaminants such

as SO2 and NO

x (Table 2) [11,12]. Fly ash is also present

in flue gas streams and typically consists of inorganic oxides of SiO

2, Al

2O

3, Fe

2O

3, CaO, MgO, Na

2O, K

2O

and P2O

5, which have undesirable effects on the amine

solution and must be removed before entering into the treating unit. Oxygen in the flue gas originates from air and excess combustion in the boiler. The presence of O

2 introduces oxidative degradation of alkanolamine

solvents and causes the formation of heat-stable salts (HSS) [13,14,101].

As amine technology for acid-gas absorption has been adopted for capturing CO

2 from flue gas, most of the

process configurations from natural gas processing are still used in CO

2 capture. However, modification and

optimization of the processes are still needed to reduce energy consumption and decrease solvent losses and corrosion problems. Nielsen and Hansen [15] reviewed corrosive agents, including acid gases, NH

3, O

2, HSS

and amine degradation products; they specifically looked at the mechanisms of corrosion of carbon steel in refinery amine systems. These variable parameters in amine absorption must be reviewed and become well understood for CO

2 capture from flue gas.

Successful precommercial demonstration of CO2

capture from a coal-fired power plant using aque-ous MEA absorption occurred at Boundary Dam in Canada [9]. However, the existing problems, especially corrosion from using coal fuel, may be more compli-cated than seen in natural gas systems. These SO

2, NO

x,

CO and particulate matter, if passing through the filter into the amine solution, could participate in the amine reactions and subsequently induce corrosion. Thus, a pretreatment of the flue gas feed is required.

A generalized process diagram of CO2 absorption

using aqueous alkanolamine (MEA) solutions is illus-trated in Figure 1. Flue gas from coal firing is first filtered to remove particulate and scrubbed to remove SO

x and

NOx. The flue gas is fed into the bottom of the absorber

column, flowing upward against the aqueous amine solution, where it is introduced to the top of absorber column. CO

2 in the flue gas stream rapidly reacts with

MEA and remains in the solution. This stream is then called a rich-amine solution. The free CO

2 flue gas

leaves the solution at the top section of the absorber. The

temperature of the rich amine solution, while leaving the absorber, is approximately 60°C. The rich-amine solu-tion exits at the bottom section of the absorber, is heated to a higher temperature in the rich-lean heat exchanger, and then returned to the top section of the stripper. In the stripper, the rich-amine solution is heated by the hot vapor steam from the reboiler at the bottom of the col-umn resulting in gas mixtures of CO

2, water and amine.

These gas mixtures exit at the top section of the stripper, flow to the condenser and reflux accumulator to recover, and return both water and amine back to the stripper. The aqueous amine solution containing a low concentra-tion of CO

2 (called lean-amine solution) at the stripper

bottom, now at a solution temperature of approximately 120°C, is pumped and cooled down through the rich-lean heat exchanger before being reintroduced to the absorber to complete the process cycle.

It is suggested that the stripper be operated at tem-peratures below 120oC to avoid corrosion [16,17]. Types of corrosion, which can be both uniform and localized, include pitting, galvanic, erosion, stress cracking and inter-granular corrosion [4]. Kittel et al. presents the

Table 1. Worldwide CO2 emissions from large sources as reported by the IPCC.

Process Number of sources Emissions (MtCO2/yr)

Fossil fuels

Power 4942 10,539Cement production 1175 932Refineries 638 798Iron and steel industry 269 646Petrochemical industry 470 379Oil and gas processing Not available 50Other sources 90 33

Biomass

Bioethanol and bioenergy 303 91Total 7887 13,468Data from [201].

Table 2. Typical concentrations of coal-fired power plant flue gases after SO2 scrubbing.

Composition Concentration (mol %)

CO2 7–15O2 2–12N2 65–75H2O 5–15SO2 2–400 ppmSO3 1–10 ppmNOX 1–400 ppmParticulates 0.1–0.5 grains/standard

cubic footReproduced with permission from [11].



major results of corrosion testing from two pilot plants (coal-fired power station in Esbjerg [Denmark] and natural gas burner at the International Test Centre for CO

2 Capture in Regina [Canada], under MEA opera-

tion [18]. In addition, the highest corrosion rates were always found in the hottest parts of the unit, includ-ing the inlet and outlet of the stripper. Gao et al. also reported that the most serious corrosion occurs at the rich-liquid side outlet of the heat exchanger [19].

CorrosionCorrosion in CO

2 absorption processes is one of the

most severe operational problems in gas purification plants [6]. Carbon steel is usually used as plant con-struction material for absorption and stripping units to reduce investment cost. However, carbon steel is more vulnerable to corrosion than stainless steel. Nevertheless, it is possible that corrosion in amine plants might not be inevitable and could be minimized or controlled. Before any corrosion prevention or protection is performed, it is important to understand the system being operated and the effects of impurities and process parameters on corrosion.

� Types of aminesDifferent amines for CO

2 capture yield different

degrees of system corrosion. The order of absorption efficiency of amines is MEA > DEA > MDEA, but the degree of corrosiveness is also MEA > DEA > MDEA. Corrosiveness of amines were tested under conditions in ranges of 1–5 kmol/m3 amine concentration, 30–80°C,

0–0.4 CO2 loading, and 0–10%

feed gas O2 concentration. For pri-

mary amines, the sterically hindered amine of 2-amino-2-methyl-1-pro-panol (AMP) has slightly less CO

2

solubility than MEA, but the cor-rosion rate of AMP is much higher than that of MEA under the same conditions [20]. AMP’s greater cor-rosiveness is explained in terms of the preferable formation of HCO

3-

rather than carbamate, while MEA and DEA favor more stable car-bamate formation in the solution. HCO

3- is known to be one of corro-

sive agents responsible for corrosion in an amine system.

For blended amines, including MDEA–DEA, MEA–MDEA, and MEA–AMP, the corrosion rates of mixed amine systems at equal amine mixing ratio and CO

2 saturation

appear to be a combination of the rates seen in single amine systems. The corrosion behav-ior of the mixed amine systems for MEA–MDEA and DEA–MDEA also exhibit cathodic and anodic cur-rent density values in between those produced in the individual single amines constituting the mixed sys-tems. For MEA–AMP, the corrosion behavior shows only cathodic current. It has been explained that this was probably caused by differences in the amounts of CO

2 absorbed under the condition of CO

2 satura-

tion [20]. MDEA in a blended system of MEA–MDEA–H

2O–CO

2 and, in the presence of O

2, is preferentially

thermally degraded at high temperature and drasti-cally reduces loss of MEA due to degradation. It also decreases the amount of non-environmentally benign degradation products. This allows MEA to be more available for CO

2 absorption [21]. Eustaquio-Rincón et

al. conducted corrosion experiments using conditions of MDEA, DEA and their various ratio mixtures in a concentration range of 15–60% mass fraction, with and without acid gases, different amounts of H

2S and CO

2

at a pressure range of 276–5861 kPa and 120°C [22]. The corrosion rate of carbon steel reported after averaged test time of 350 h was determined by the weight loss method in aqueous solutions of individual and blended MDEA and DEA. For a given blended mass ratio, the corrosion rate decreases as the total amine concentration increases in relation to increased amounts of MDEA. The overall corrosion rate was less than 1 mils per year unit (mpy). In the presence of CO

2 loading less than 0.35 mol/mol

amine and a mass ratio of MDEA to DEA of 3.5/1, the effect of CO

2 on corrosion was negligible.

Treated gas

Feed gas

Lean solution

AbsorberRich solution

Lean solution

Rich solution

Reboiler

Regenerator

Condenser

Reflux accumulator

Rich-lean heat exchanger

Cooler

Figure 1. Simplified process flow diagram of a typical amine treating process.



New types of amines have been introduced for CO2

capture in the absorption process, including hetercy-clic PZ and its derivatives [23–26]; analog structures of PZ [27]; amino alcohols such as 4-diethylamino-2-butanol [28,29], 2-(isopropylamino)ethanol, 2-(iso-butylamino)ethanol, 1-methyl-2-piperidineethanol, and 2-(isopropyl)diethanolamine [30,31]; and sterically hindered amines including AMP, with the intention of increasing absorption and cyclic capacities, which results in a lower circulation rate. This creates energy savings in the CO

2 regeneration step as compared with

conventional amines [32]. The structure of PZ is a heterocyclic six-member

ring containing two secondary amines in the struc-ture. PZ has been found to have similar volatility to MEA but has almost double the CO

2 absorption rate

and capacity, and is more resistant to oxidative and thermal degradation [25]. A CO

2 capture pilot plant

using concentrated PZ has also been constructed [33]. The kinetic reaction of PZ and its derivatives with CO

2 identified using the stopped-flow technique are in

the order of PZ > 2-methyl-PZ > 1-ethyl-PZ > N-(2-hydroxyethyl)-PZ > 1-methyl-PZ [24]. The degradation rates of 1-methyl-PZ and 2-methyl-PZ are faster than PZ under the same conditions at 150oC [27]. For amino alcohols, modification of different chemical structures, including changing an alkyl group relative to the posi-tion of an amino group in an alcohol structure, results in a high absorption rate and low heat of reaction when compared with AMP and MDEA [30]. When hydroxyl functions are placed relative to the amino position, some amino alcohols, such as 4-propylamino-2-butanol, show the highest CO

2 absorption, and 4-(ethyl-methyl-

amino)-2-butanol shows the highest cyclic capacities among the amino alcohols studied in comparison to MEA [28]. These new solvents have a very high potential for application in CO

2 absorption processes. However,

the physical characteristics, oxidative and thermal deg-radation, as well as corrosion behavior of these new solvents, must first be studied extensively. Thus, it will take some years for these solvents to be commercialized. Blending the new solvents with existing commercially available amines to improve their CO

2 absorption effi-

ciency and reduce operating costs have been reported. However, studies of corrosion on this set of solvents have not been reported.

Several attempts have been made to formulate blended amines in order to overcome the limitations of single amine absorption [19]. The objectives are to increase CO

2 capture efficiency, increase CO

2 solubil-

ity in amine solution [34] and decrease energy require-ment in the stripping process [35,36]. MEA–AMP can absorb CO

2 with a similar capacity to MEA–MDEA,

but at a much higher rate and with higher mass-transfer

coeff icients [37]. Blended K2CO

3-hindered cyclic

amine [25], a K2CO

3-promoting amine [38], have been

claimed to have very low heat absorption, low volatility, and high resistance to thermal and reactive degradation. PZ has been found to rapidly react with CO

2 and forms

carbamates, which could be used as an effective pro-moter in existing amine absorption. Extensive study of PZ blends includes MEA–PZ [39,40], MDEA–PZ [41,42], and K

2CO

3–PZ [23,43]. Blended PZ with MEA for CO

2

showed increased absorption 1.5–2.5 times greater than that of MEA alone. The degree of absorption capacity increases in order of MEA–PZ > AMP–PZ or MDEA–PZ and MEA alone [34]. However, PZ not only increases the CO

2 absorption capacity, but also increases the cor-

rosion rate. The corrosion rate of carbon steel in the blended MEA–PZ solutions is more corrosive than MEA at the same total concentration and under the same operating conditions. The corrosion rate in the blended MEA–PZ system is more pronounced with increasing total amine concentration, and it also rises with an increase in the ratio of PZ to MEA. Corrosion rates of MEA–PZ system determined under conditions of 5–8.7 kmol/m3 total amine concentration with vari-ous mixing ratio, 0.2–0.63 CO

2 loading, 0–10.13 kPa

feed gas O2 partial pressure, and 80°C (test time was

not given) was reported to increase in the presence of O

2, CO

2 loading and high temperature [39]. Table 3 also

summarizes various corrosion studies conducted using different amines and test conditions.

� Heat stable saltsThe main problem of solvent loss is due to oxidative and thermal degradation experienced in the absorption process. Amine solvents can be degraded. Degradation products such as carboxylic acids can react with amine to form alkanolamine salts or HSS, which cannot be removed under solvent regeneration conditions and remain in the amine absorption solution throughout the plant. Various kinds of HSS and their negative effects are often reported [21,44–47]. Tanthapanichakoon et al. investigated the effects of HSS (oxalate, formate, malo-nate, glycolate, succinate and acetate) of various concen-tration on corrosion of carbon steel and stainless steel using 5 kmol/m3 MEA, 0.20 mol/mol CO

2 and 80°C

(test time was not provided) [48]. Degrees of corrosive-ness varied depending on type and concentration of salt. For carbon steel under the same conditions when dif-ferent HSS were added, oxalate was the most corrosive (corrosion rate increase 54–64% as compared with the solution without added HSS), followed by malonate (14.7–17.2%), formate (12.2%) and the others (<4%). For stainless steel, the most corrosive oxalate did not reduce the corrosion resistance of stainless steel or have any impact on the corrosion behavior. The corrosion



rate of carbon steel in MEA–PZ blends at 80oC, with CO

2 loading and in the presence of 1% wt of HSS

(acetate, formate, oxalate and thiosulfate), is faster and shows greater degrees of deterioration [39]. Anions of HSS were found to be an oxidizing agent in the corro-sion process, which altered the corrosion mechanisms on both the anodic and cathodic sides. The order of corrosiveness was formate, followed by acetate, oxalate and thiosulfate; however, in the presence of O

2, acetate

was more corrosive than formate.

� Process parameters Most corrosion behavior in all amine systems is sensitive to the variations in type of amines, amine concentration, solution temperature, CO

2 loading, and amounts of

oxygen, HSS and impurities. The effects of the process parameters are typically studied in any new equipment or system process or in testing any new solvent.

Effect of O2

Coal-fired power plant flue gas is composed of CO2, N

2,

O2, SO

2 and NO

2. Considerable efforts have focused

on understanding O2-induced degradation of MEA.

Dissolved oxygen in liquid solvent experiences high temperature at various locations in the capture plant,

including the heat exchanger, stripper and reboiler/reclaimer, and this leads to a higher corrosion rate, especially in these areas [47]. Bello and Idem proposed pathways for the formation of O

2 degradation products

in MEA solution during CO2 absorption [44]. O

2 was

not initially present in the feed gas stream, but could be produced as a degradation product. Thus, an oxidative degradation environment could be created without the presence of O

2 in the flue gas feed. In the absence of

O2, corrosion reactions occur due to iron dissolution

(anodic reaction) and reduction of oxidizers (H2O and

HCO3

- in cathodic reactions), and black slime of FeCO3

was also observed during the experiment [48]. Increasing the O

2 partial pressure increased O

2 solubility in the

solution. In an MEA system with CO2 loading, the cor-

rosion rate increased with increasing O2 concentration

under the test conditions of 5–9 kmol/m3 MEA concen-tration, 0.2–0.55 CO

2 loading, 40–80°C, 0–10.13 kPa

feed gas O2 partial pressure and 0–2000 rpm solution

velocity [49]. Similar effect of O2 concentration was also

reported using 1–7 kmol/m3 MEA, 0–100% feed gas O

2, 0–204 ppm SO

2, 0–0.5 CO

2 and 30–80°C [50,51].

Quantitative information (i.e., corrosion rate) usually dependent on operating parameters (e.g., amine type, temperature and feed gas concentrations) was also given

Table 3. Summary of various corrosion studies conducted with different amines and test conditions.

Amine Temperature (oC)

CO2

concentrationO2

concentrationMethod Corrosiveness Mechanism Ref.

3 M various amines 80 Saturated 0–10% Electrochemical MEA > AMP > DEA > MDEA

CO2 solubility

[19]

3 M various mixed amines (1:1)

Saturated MEA/AMP > MEA/MDEA > DEA/MDEA

3 M various amines 0.2 mol/mol amine

AMP > MEA ≥ DEA

MEA/PZ (5:1.2) vs 6.2 M MEA

80 0.2 mol/mol amine

N/A Electrochemical MEA/PZ > MEA Corrosive agent: HCO3

-

[38]

MEA and AMP (1–7M) 100 100% 48% air Static weight loss MEA > AMP [75]

52% N/A5 M MEA containing HSS: acetic, formic, glycolic, malonic, oxalic and succinic acids

80 0.2 mol/mol amine

NA Electrochemical Oxalic > Malonic > Formic > Succinic > Acetic > Glycolic

N/A [48]

5 M MEA 80 0.4 mol/mol amine

0–100% Electrochemical Increase with increase of % O2 in feed gas

N/A [51]

5 M MEA with SO2 (0–204 ppm)

Slightly increase with increase of SO2 concentration

MDEA: DEA of 3.5:1 and 2:1 with various H2S concentrations

120 Various CO2 loadings

N/A Weight loss Rate not affected by 0–0.35 CO2 loading range but increased with an increase of H2S and amine concentrations

N/A [21]

AMP: 2-amino-2-methyl-1-propanol; DEA: Diethanolamine; HSS: Heat-stable salts; MDEA: Methyldiethanolamine; MEA: Monoethanolamine; NA: Not applicable; PZ: Piperazine.



for MEA–H2O-CO

2-O

2-SO

2 system to represent the

effects of specific variables (i.e., MEA, O2, CO

2 and

SO2 concentrations and temperature) on corrosion rate

of carbon steel [50]. The rate equation is also given as follows:

Equation 7Chemical ana lysis of the amine solution by inductively coupled plasma–MS and capillary electrophoresis found an increase of dissolved iron but no change in carbon-ate/bicarbonate ions in the solution, and ana lysis of sur-face of corroding of specimen using a scanning electron microscope–energy dispersive spectrometer showed a relative decrease in Fe and increase in O and C on the specimen surface. The corrosion products proposed were Fe(OH)

2, Fe(OH)

3 and FeCO

3 [50,51].

Effect of amine concentrationMost amines show similar behavior with respect to cor-rosion rate, in that it tends to increase with increasing amine concentration. The corrosion behavior shows a greater impact on current densities on the anodic side. Higher amine concentrations result in larger amounts of absorbed CO

2, carbonate/bicarbonate formation

and dissolved iron being present in the solution. The increase in carbonate/bicarbonate anion concentration is responsible for the increased corrosiveness of the sys-tem [50,51]. It is noted for AMP and amine concentration above 3 kmol/m3, the corrosion rate of AMP gradually deceases as AMP concentration increases. This was explained as being due to the decrease of the hydrolysis of carbamate, resulting in less HCO

3- being produced.

There is a limitation of amine concentration of 20–30% amine to minimize the corrosion rate, and there have been research attempts to overcome this limitation. For instance, it was reported that there was no MEA degradation when 40% MEA was used with oxidative inhibitors [52].

Effect of CO2

High CO2 absorption capacity of amines is one of

the most important parameters in decreasing operat-ing costs of CO

2 capture. Increasing the CO

2 loading

in most systems, however, leads to a greater amount of HCO

3- and, consequently, a higher corrosion rate.

Higher CO2 loadings result in both higher anodic and

cathodic current densities in electrochemical reactions and, thus, higher amounts of HCO

3-. The solution pH

also becomes more acidic, suggesting increased amounts of H+ or RNH

3+ might occur in the solution. Both

HCO3

- and H+ accelerate the corrosion rate.

Effect of temperatureTemperature is an essential term in the study of kinetic rate of reaction. It shifts many reaction equilibria, including CO

2 absorption, carbamate formation, hydro-

lysis of carbamate, pH of the solution and solubility of chemical species. Raising the solution temperature, therefore, accelerates corrosion reactions [49,50]. A cor-rosion study conducted at 30–80°C, 0.0–1.0 mol CO

2

loading and 1.0–4.0 kmol/m3 AMP concentration showed that for AMP systems operated at a high tem-perature and lean CO

2 loading, the corrosion rate was

less than in MEA systems [53]. At elevated temperatures, CO

2 solubility of AMP was usually lower than that of

MEA, thus a smaller CO2 loading. A decrease in CO

2

loading in AMP then produced a smaller concentration of corroding species, particularly bicarbonate (HCO

3-

), protonated amine (RNH3

+), and proton (H+), thus corrosion rates were reduced. On the other hand, an increase of CO

2 loading of AMP solution increased the

corrosion rate of the carbon-steel material. Based on the polarization curves at different CO

2 loadings, the

curves exhibited the most change in current density on the cathodic side as compared with a slight change on the anode. This work demonstrated more activity in the cathodic region where reduction normally occurs. This observation led to the conclusion that CO

2 load-

ing enhanced the rate of reduction, whereby it provided more oxidizing species (HCO

3-, CO

32- and H+). The

corrosion inhibitors used for CO2 absorption in vari-

ous amine solutions are summarized in Table 4. To our knowledge, no data are available in terms of compari-son of temperature effect of different contaminants. Typically, any study is usually conducted to evaluate the effect of parameters of interest in a step-wise man-ner. It usually compares the effect of temperature on corrosion rates induced by different concentrations of the different species at the same time. An example can be found in a study, which showed the effect of differ-ent temperatures on various CO

2 loadings [53]. A similar

study also applies to effect of O2 on corrosion rates. In

the case of SO2, in which very limited studies are avail-

able, its effect was only evaluated at 80°C [50]. However, this study proposed a corrosion rate equation, previously given in Equation 7, which could indicate the effect of temperature on each corrosion species (i.e., MEA, SO

2,

O2 and CO

2).

Effect of SO2

SO2 in flue gas streams arises from coal combustion.

Concentration of SO2 is dependent on the quantity

of sulfur contained in the original coal and the con-ditions of the combustion process. High SO

2 concen-

tration (>10 ppm) has a marked depolarizing effect on cathodic reactions on polished metal surfaces and

Corrosion

1.77 10 5955 SO O CO MEAexp T

rate

92

0.00112

0.00062

0.9 0.0001

=-

# #; 6 6 6 6E @ @ @ @' "1 ,



also creates low pH in the surface film. Consequently, it generates a low rate of sulfate production and appreciable amounts of tetravalent sulfur (dithionite and S

2O

4-), which

can be reduced to sulfide. Ferrous sulfide is a stable corrosion product.

Although it is present in small amounts, SO

2 is more acidic than CO

2; its regenera-

tive removal requires the use of weaker bases than primary amines [54]. The strong basicity of primary amines results in an irreversible reaction with SO

2 that

produces corrosive and HSS, reducing the CO2 absorp-

tion rate and capacity of the absorbent. However, it has been reported that the absorption of CO

2 in indus-

trial gas streams that contain a typical concentration of SO

2 might lead to a loss of only 2 mol of MEA/

(mol of SO2) [55]. Thus, very low concentrations of SO

2

(<10 ppm) might be desirable in order to avoid exces-sive loss of costly solvent [56]. So far, the information on the effects of SO

2 and NO

x on amine degradation

and corrosion is scant. Uyanga and Idem have made a comprehensive study of the effects of SO

2 and O

2

on the degradation of MEA [57]. The effect of SO2 as

well as other process parameters (CO2 loading, O

2 con-

centration and temperature) on degradation of MEA was also reported in [13]. The SO

2-O

2-N

2 gas mixture

was in contact with aqueous MEA solutions at elevated temperatures. In the absence of CO

2, the rate of MEA

degradation increased with raising O2 concentration

and further increased when SO2 was added, continuing

to climb as the SO2 concentration rose. In the pres-

ence of CO2, the effects of O

2 and SO

2 became neg-

ligible. Later, Kladkaew et al. investigated the effect of SO

2 (0–204 ppm) on corrosion of carbon steel in a

similar system and simulated the conditions of absorp-tion–regeneration sections [50,51]. The corrosion rate increased with increasing SO

2 due to the increase of

hydronium ion formation from the reactions of SO2

and H2O, as well as SO

2, O

2 and H

2O. However, the

corrosion rate was slight as compared with the effects of MEA concentration, CO

2 loading and operating

temperature. Gao et al. evaluated the influence of SO

2 on the cor-

rosion of carbon steel and stainless steel, and degrada-tion of blended amine solvent in a pilot plant [19]. More serious amine degradation and HSS formation occurred with increasing SO

2 concentration. In addition, SO

2 has

been found to play an important role in formation of corrosion protection films.

Corrosion mechanism Corrosion in amine-treating units is normally quan-tified using a corrosion rate measured by two major

techniques: weight loss and electrochemical measure-ments. The weight loss technique uses a metal coupon of known weight immersed into the amine solution at pre-determined conditions. The weight after a specific time is determined and used to calculate the corrosion rate during the test period. The electrochemical technique measures current densities of the anode and cathode, dictated by the strengths of oxidation (metal dissolu-tion) and reduction (reduction of corroding species) when corrosion occurs. In any technique, the corrosion rate is normally expressed in mpy. In electrochemical measurement, electrochemical polarization consists of an anodic reaction (oxidation of metal or iron disso-lution, Equation 8) and cathodic reactions (reduction of oxidizing agents, Equations 9 & 3). Although redox potentials are important, all of the works reviewed did not include the potentials for the reactions; all of the studies proposed a specific system of various amines and corrosion inhibitors. Objectives set by these works were mostly focused on showing corrosiveness, effects of the studied parameters, and how corrosion occurred in the systems. Redox potentials were not used to explain any reported results, thus they were not available from their studies.

Anodic reaction:

Fe ← → Fe+2 + 2e-

Equation 8Cathodic reaction:

O2 + 2H

2O + 4e- ← → 4 OH-

Equation 9

In an aqueous amine-CO2 system, the reaction of

amine (primary and secondary) with CO2 yields revers-

ible formations of carbamate and protonated amine as follows:

Formation of carbamate [58]:

2RNH2 + CO

2 ← → RNHCOO- + RNH

3+

Equation 10In the aqueous amine solution, water as a bulk phase

plays an important role in hydrolysis of carbamate.Hydrolysis of carbamate [59]:

RNHCOO- + H2O ← → RNH

2 + HCO

3-

Equation 11Hydrolysis of bicarbonate:

HCO3

- + H2O ← → H

3O+ + CO

32-

Equation 12

Key term

Electrochemical technique: Technique used to determine corrosion rate and behavior of a system of interest, based on plot of its potential and current densities, generated on anode and cathode during the test.



Under conditions in ranges of 1–5 kmol/m3 amine concentration, 30–80°C, 0–0.4 CO

2 loading, and

0–10% feed gas O2 concentration, 3 kmol/m3 amine

and 80oC, the corrosion rates of different amines are in order MEA > AMP > DEA > MDEA and for the blended amines (1:1) are MEA–AMP > MEA–MDEA > DEA–MDEA, which the corrosion rates are in between of the amine precursors. The polarization curves of the amines also show higher anodic and cathodic current densities in the same order. The different corrosion rates of the amines are due to the different CO

2 absorption capacity, 0.565,

0.554, 0.442 and 0.243 mol/molCO2, for MEA, AMP,

DEA and MDEA, respectively. For low CO2 loading, ex

0.2 mol/mol CO2 loading, 3 kmol/m3 amine and 80oC,

the corrosion rates are AMP >> MEA ≥ DEA, corre-sponding to 30, 20 and 19 mpy, respectively. Higher cor-rosion of AMP is explained due to the presence of HCO

3-,

corrosive species. Carbamate compound formation of MEA and DEA is stable, while that of AMP is unstable and thus undergone hydrolysis to generate HCO

3- [20].

For MEA–PZ system evaluated at 5–8.7 kmol/m3 total amine concentration with various mixing ratio, 0.2–0.63 CO

2 loading, 0–10.13 kPa feed gas O

2 partial pressure

and 80°C (test time was not given), specifically at 0.2 CO

2 loading, 80oC, constant total amine 6.2 kmol/m3

(MEA 5 kmol/m3–PZ 1.2 kmol/m3 vs MEA 6.2 kmol/m3), the mixed system (21.79 mpy) is more corrosive than MEA (19.23 mpy). The corrosiveness of PZ is more pronounced when PZ is increased and the evidence is also seen in the increase of the cathodic current densities. Possibly, there was a change in reduction of oxidizing

agents in the presence of PZ; for example, metal complex formation [39].

Corrosiveness of HSS can be viewed by polarization. There are also changes in anodic (ba) and cathodic (bc) Tafel slopes. Linear polarization resistance is decreased as HSS concentration increased. For oxalic acid, both anodic and cathodic current densities in the presence of oxalic acid are greater than that of the same system with no acid, implying the change in iron dissolution and chelation of iron. With increasing oxalic acid concen-tration, ba is decreased, while bc remains unchanged as compared with no acid system, and linear polarization resistance is also decreased. The polarization parameters are more pronounced as the acid concentration greater than 1000 ppm for oxalic and 10,000 ppm for formic and malonic acids [48].

Reviews of mechanisms are mostly relied on ana lysis of electrochemical polarization and its data. Postulation is based on electrochemistry and changes in polariza-tion plot (potential related to standard electrode versus logarithm of current density) due to what are added and cause change in the environment. There is no confirma-tion of what definite chemical species are taking part in corrosion or inhibition. Most recent studies report, 13C-NMR was used to determine AMP–protonated AMP (AMP/AMPH+), AMP carbamate (AMPCOO-) and HCO

3-/CO

32- in 30 wt% aqueous solution of AMP

with different amount of CO2 at 25oC [60]. Yamada et

al. also used 13C-NMR to demonstrate that the product ratios of carbamate to bicarbonate of MEA are greater than that of AMP [61].

Table 4. Various corrosion inhibitor studies of different amine systems.

Amine Temperature (oC)

CO2 loading Test Corrosion inhibitor Inhibition efficiency (%)

Ref.

MEA and AMP 100 Saturated Weight loss 10–75 ppm NaVO3 93–99.9 [75]

2–16 ppm NaVO3 >90–933 M MEA 80 Saturated Electrochemical 1000–5000 ppm A: Imidazole,

B: piperaxzine, C: hexamethyl eneimine, D: cyclohexylamine and E: 2,4-lutidine

<60 (C turn the solution to orange)

[76]

100 ppm F: long-chain aliphatic amine 75–92 (G > H > F)1000–5000 ppm G: carboxylic acid1000 ppm H: sulfoxide1000 ppm NaVO3 97

40 vs 80 F, G and H: VS NaVO3 F, G and H increased with a temperature increasewhile NaVO3 remain 97

5 M MEA 40 vs 80 0.2–0.55 mol/mol amine

Electrochemical 250 ppm CuCO3 >80 [77]

A: Imidazole; B: Piperaxzine; C: Hexamethyleneimine; D: Cyclohexylamine; E: 2,4-lutidine; F: Long-chain aliphatic amine; G: Carboxylic acid; H: Sulfoxide. AMP: 2-amino-2-methyl-1-propanol; MEA: Monoethanolamine.



In the amine–CO2 aqueous system, CO

2 is bound

in the form of carbamate, bicarbonate and carbonate. Increased CO

2 loading accelerates the formation of

these chemical species.

2HCO3

- + Fe → FeCO3 + H

2

Equation 13An increase in CO

2 loading also shows a shift of

cathodic current density towards a greater value. This also indicates an increase of bicarbonate con-centration in the solution, thus enhancing the cor-rosion rate [50,62]. Bicarbonate as a primary oxidizer in an aqueous MEA solution was also identified as playing an important role in corrosion in a mecha-nistic corrosion model [62]. Corrosion occurs due to iron dissolution (anodic reaction) and reductions of oxidizers (H

2O and HCO

3- in cathodic reactions).

Insoluble black particles of FeCO3 (Equation 13) were

also observed [49]. Oxidized iron can be stabilized in the solution

and formed into complexes with HSS anions such as formate and acetate [46]:

Fe+2 + 6H2O ← → Fe(H

2O)

6+2

Equation 14Complex formation [63]:

Fe(H2O)

6+2 + n (HSS) ← → Fe(HSS)

n(2-n) + (6-n)H

2O

Equation 15where n = 1 to 6. The complexation with HSS anions will increase dissolution of FeCO

3 into the solution

with increased HSS anion concentration. As demon-strated by Cummings et al., solubility of FeCO

3 was

significantly increased in the presence of bicine due to the complex formation of iron-hydroxide-bicine [63]. Diamines as degradation products of primary and sec-ondary amines have no effect on corrosion, but can be strong chelators of iron and promote corrosion by CO

2.

Similar to the effect of CO2, an increase in amine

concentration intensifies the formation of carbamate, bicarbonate and carbonate. Also, increased amine con-centration has a more pronounced effect on the anodic side of reactions, which accelerates the corrosion rate, as seen from the increase of carbonate/bicarbonate in the solution. There is also an increase in carbamate formation, as well as protonated amine and carbonate/bicarbonate [64].

It is known that the corrosion rates of individual amines are in the order of AMP > MEA > DEA > MDEA. For sterically hindered amines, the stability of carba-mate is greatly reduced when the number of carbon

atoms between the amine and alcohol groups increases from two to three, which increases bicarbonate forma-tion [65,66]. It was also noted that the corrosion rate of AMP is higher than that of MEA under the same operating conditions because of increasing bicarbon-ate. The existence of chemical species of AMP–CO

2

system confirmed by 13C-NMR consist of the amine/protonated amine AMP/AMPH+ and the carbamate (AMPCOO-) [60,61]. The carbamate stability con-stant (on mol fraction basis) was calculated to be 0.47 at 25oC [60]. Reactions responsible for AMP–CO

2

absorption are given as follows [60]:

CO2 + 2H

2O ← → H

3O+ + HCO

3-

Equation 16

AMPH+ + H2O ← → AMP + H

3O+

Equation 17

AMP + CO2 + H

2O ← → AMPCOO- + H

3O+

Equation 18

AMP + HCO3

- ← → AMPCOO- + H2O

Equation 19Increased dissolved O

2 in solution means there is an

increased presence of oxidizer in the solution [1,67] and an increased tendency for iron to be oxidized.

The oxidation–reduction reactions of iron (Equation 8) and O

2 (Equation 9) in the solution:

2Fe + O2 + 2H

2O ← → 2Fe(OH)

2

Equation 20According to Fontana, Fe(OH)

2 identified as a reac-

tion intermediate is usually oxidized further to form a more stable compound such as Fe(OH)

3 [1]:

2Fe(OH) 2 + 1/

2O

2 + H

2O → 2Fe(OH)

3

Equation 21SO

2 is a stronger acid gas than CO

2, quickly solubilizing

in aqueous solution and producing hydrogen ions [68].

SO2 + H

2O ← → H+ + HSO

3-

Equation 22

HSO3

- ← → H+ + SO3

+

Equation 23



SO2 + 1/

2O

2 + H

2O ← → 2H+ + SO

4+

Equation 24HSO

3-, SO

3-, and SO

4- can react with protonated

amine and form inorganic HSS, which cannot be regen-erated by heat under stripping conditions. Hydrogen ions decrease solution pH and also act as an oxidizer in the solution. However, since the reduction of H+ pro-vided by SO

2 hydrolysis shown in Equations 22–24 and

3 can be controlled by the strength of the amine as a base, there will be less possibility for free hydrogen ions to react with iron:

In the solution, SO2 can react directly with water

and O2 [69].

Fe + SO2 + O

2 → FeSO

4

Equation 25Temperature also has a profound effect on cor-

rosion rate in the SO2-amine system. In the MEA–

O2-CO

2-SO

2 system, as temperature raised to 30, 50

and 80°C, the polarization curve shifted toward greater values of both anodic and cathodic current densities, which corresponded to corrosion rates of 13 mpy, 41 mpy and 161 mpy, respectively [50]. These corro-sion rates were measured under conditions of 1–7 kmol/m3 MEA, 0–100% feed gas O

2, 0–204 ppm SO

2, and

0–0.5 CO2, and 30–80°C; however, test time was not

specified.

Corrosion inhibition Equipment corrosion and solvent loss are the essen-tial problems in amine absorption and represent the most expensive costs in operating an amine system. The causes of corrosion include HSS from oxidation of amine, products from degradation of amine, and contaminants in flue gas and preparation water. It is possible that corrosion can be controlled and prevented, depending upon its route, using such approaches as fil-tering contaminants in flue gas before feeding it into the absorber unit, use of high purity water in preparation of amine solution, or separating [45] or neutralizing [70] HSS and degradation products to controlled levels. Since the anodic and cathodic reactions occurring during cor-rosion are mutually dependent, it is possible to reduce the rates of either reaction to reduce the corrosion [1]. Corrosion inhibitors slow corrosion processes by inter-fering with either the anodic and cathodic reactions or both, and injection of corrosion inhibitors is inex-pensive. Chemical inhibitors, however, could accumu-late and build up concentration over a period of time, causing a change in solution physical properties. Such changes cause surface tension to decrease when corro-sion inhibitor is added in the MEA solution, leading to a

foaming problem in the CO2 absorption process [71]. In

addition, the effectiveness of chemical inhibitors might be affected by variations in the process parameters. As well as the inhibitor type and concentration, operating temperature can have an impact on different corrosion inhibitors. A study showed that sodium metavanadate (VND) inhibition performance was not affected sig-nificantly with temperature change while the opposite was true for undisclosed inhibitors F, G and H [72]. It is important, therefore, to understand corrosion behavior when inhibitors are used.

Many corrosion inhibitors have been developed, patented and commercialized, and can be categorized into two types. The inorganic category includes salts of ar senic, vanadium, copper, cobalt, molybdenum, antimony and stannous [105]. The organic category includes nitro-substituted aromatic acids and its salts and naphthoquinone [106]. Inorganic inhibitors are more favored in practice than organic compounds because of their superior inhibition performance. However, these inorganic corrosion inhibitors are not environmentally friendly; as such inhibitors contain toxic arsenic, anti-mony, and vanadium. Vanadium compounds, particu-larly VND, are the most extensively and successfully used in amine treating plants. However, VND has been known to be toxic, as indicated by a much lower lethal dose to rat (10 mg/kg LD

50-oral) when compared with

MEA solvent [72]. In addition, it also has a detrimen-tal effect to MEA by boosting up the solvent degra-dation rate during CO

2 absorption operation [73]. The

attractive, less toxic and more environmentally friendly inorganic corrosion inhibitor sodium molybdate, as indicated by a higher LD

50-oral of 4,000 mg/kg [202] is

widely used in cooling water systems [74]. This inhibitor shows high performance in inhibiting both uniform and localized corrosion and pitting of ferrous and nonferrous metal [75].

Corrosion inhibition of VND and 2-aminothiophe-nol organic inhibitor (a good inhibitor for hot K

2CO

3

system) at various concentrations were compared using National Association of Corrosion Engineers and American Standard for Testing and Materials complied static weight loss methods in a 5 kmol/m3 AMP satu-rated with mixture of 52% CO

2 and 48% air (equiva-

lent to 10% O2) under boiling conditions [76]. To evalu-

ate performance of the inhibitors (i.e.,% protection), a base run without inhibitor was initially conducted to obtain uninhibited corrosion rate, which was later used to compare with inhibited corrosion rates obtained from runs with inhibitors. For the tested period (not provided in this work), system containing 75 ppm VND yielded only 0.1 mpy corrosion rate equivalent to 99.9% protection, as compared with uninhibited system. On the other hand, 2-aminothiophenol failed the screen



test due to nonreproduced corrosion data. The authors suggested that 2-aminothiophenol spiked AMP solu-tion could be degraded under heat, CO

2 and O

2 during

a test, which was observed from successive change of solution color from light yellow to purple.

For CO2 separation using aqueous solutions of MEA,

the possibility of using three types of low-toxic organic corrosion inhibitors (amines, carboxylic acid and sulf-oxide), instead of inorganic heavy metal inhibitors, was investigated and compared with the commercial inor-ganic inhibitor VND in carbon steel and MEA solution under CO

2 saturation [72]. Inhibitors A–F respectively

identified as imidazole, PZ, hexamethyleneimine, cyclo-hexylamine, 2,4-lutidine (or 2,4-dimethylpyridine) and long-chained aliphatic amine are amines that have nitrogen functional groups with different molecular structures, that is, aromatic and long-chain aliphatic. Based on this study, no inhibitors contain changes in both aromatic and aliphatic structures. Either aromatic or aliphatic compounds were tested for corrosion inhi-bition performance. The role of compound structures (except electron density) was rarely discussed in this study. The inhibition efficiency, shown by percent-age of corrosion protection, depended on the inhibitor concentration and system temperature. VND provided the highest percentage of protection of 97% followed carboxylic acid with 92%, sulfoxide and long-chain aliphatic amine respectively. Mechanisms of inhibitors F-H were proposed as providing enhancement of cor-rosion resistance by suppressing reduction of HCO

3- at

the cathodic side and adsorption of the inhibitor at the surface of metal. Increase of temperature from 40oC to 80oC had no significant effect on the inhibition perfor-mance of VND, in which percentage of protection still remained as high as 97%. However, temperature had a significant impact on the F–H inhibitors, in which it increased percentage of protection of all inhibitors when temperature rose from 40oC to 80oC. For example, percentage corrosion protection of system containing inhibitor G doubled when the temperature was raised from 40oC to 80oC.

The inhibition performance of less toxic copper carbonate (CuCO

3) with 1350 mg/kg LD

50 [203], as

compared with vanadium based inhibitors such as VND having LD

50 of only 10 mg/kg, was also inves-

tigated [77]. Under the tested conditions of 5 kmol/m3 MEA, 0.20 CO

2 loading, various CuCO

3 concentra-

tion, 0–10% feed gas O2 concentration, 0–2000 rpm

solution velocity and 40–80oC, the addition of cop-per carbonate decreased the corrosion rate of carbon steel but might induce pitting corrosion. The inhibi-tion efficiency was found to be greater at 40oC than at 80oC. This was probably due to the nature of the passive film. The inhibition performance was found

negligibly affected by solution velocity range (i.e., 0–2000 rpm) used in this study, as observed from no apparent change in both anodic passive current den-sity and cathodic Tafel slopes. Solution velocity only accelerated cathodic reactions by inducing more mass transfer rate of corroding species available for the metal surface. To our knowledge, there are no reports in the reviewed papers in regards to structure/nature of pas-sive films. In real systems, corrosion is often determined by placing metal coupons in different location within the process to determine their weight loss after specific times or using a corrosometer. Determination of corro-sion in pilot plants using these techniques can be found in literature [18].

Jovancicevic et al. studied inhibition of N-based surfactant inhibitor of imidazolines and their amide/amine counterparts containing different hydrocarbon chain lengths [78]. The corrosion tests were all con-ducted in CO

2-saturated brine done at 1 atm, 150°C

and 6000 rpm rotating speed of electrode using inhibi-tor concentration in a range of 3–50 ppm. The corrosion rate was measured at steady state after 3–4-h test peri-ods. In this study, contribution of inhibitor structures helps understand inhibitor molecular arrangements (e.g., spherical/nonspherical micelles) which strongly affect their adsorption strength at the metal surface for corrosion protection. These inhibitors function by forming an ordered structure known as micelle (i.e., an aggregate composing of hydrophilic head regions in contact with surrounding solvent while hydropho-bic tails pointing into micelle center) to adsorb as monolayer or bilayer (i.e., molecules are arranged into a two-layered sheet with all of their hydrophobic tails pointing toward the center of the sheet and the hydro-philic heads being exposed to surroundings, such as metal surface and solvent) on hydrophilic surfaces of metal surface to give corrosion protection. Bilayer film specifically formed by surfactant inhibitors analyzed in this work could be considered a type of added passive film. Passive film is generally known as a 2–3 nm thick film composed mainly of iron oxides, Fe(OH)

2, Fe

3O

4

and Fe2O

3, which adhere to the metal surface. The film

functions as a barrier inhibiting oxidation reaction on the anodic side, thus minimizing corrosion of metals. Some inhibitors, such as CuCO

3 [77] and VND [72] have

been found to promote formation of a passive film on the anodic side. The bilayer film also passivates metal by protecting it from being corroded. However, bilayer film is formed and arranged on the metal surface in a special manner. The molecules of the surfactant inhibi-tor assemble themselves to a two-layered sheet, where all of the hydrophobic tails point toward the center of the sheet and the hydrophilic heads adhere to the metal sur-face. The adsorption of surfactant inhibitor can protect



the metal surface from contact with oxidizing species in the systems (e.g., H+ and HCO

3+ in MEA–CO

2–H

2O

system), thus corrosion is minimized. Contributions of the constituent parts of the hydro-

phobic hydrocarbon chain lengths and types of hydro-philic head groups (i.e., imidazoline, amide and amine) on the inhibitor structure were discussed. For imidazo-line inhibitors, hydrocarbon chain length was found to affect the minimum effective concentration (MEC), a 2 mpy corrosion rate. A decrease in hydrocarbon chain lengths from C20 to C10 or to C8, for the most part, linearly increased the MEC. Corrosion inhibi-tion was unnoticeable when the chain length reached C8. Therefore, higher chain length imidazolines used smaller concentrations than their lower-chained coun-terparts to achieve maximum corrosion protection or a corrosion free environment (2 mpy), thus making them more effective inhibitors. The study suggested that longer chain length provided a better metal surface adsorption, due to higher cohesive energy and stability of the thicker bilayer as opposed to the small spherical micelle of the shorter chained C8 inhibitors. Inhibitors with amine and amide head groups were found to work more effectively than imidazoline inhibitors of a com-parable hydrocarbon chain length. It was reasoned that amine/amide inhibitors were able to form nonspherical micelles at, or nearer to, the metal surface than their imidazoline counterpart, resulting in the formation of more stable admicelle bilayers, thus creating better corrosion protection. Ramachandran and Jovancicevic used molecular modeling to determine the binding of imidazoline and amide on the iron oxide surface [79]. The conceptual model was based on adsorption and bilayer film formation on a metal surface.

ConclusionMost corrosion studies in amine system have been car-ried out to evaluate effect of amine type and concen-tration, temperature, CO

2 loading and O

2 concentra-

tion in the feed gas. More process parameters used in CO

2 absorption using aqueous amine should also be

determined for their effects on the corrosion, especially effect of other impurities in gas stream such as NO

x and

inorganic fly ash, which can lead to corrosion. Major degradation products other than HSS such as NH

3

and amides are also important species, which should be included in corrosion studies.

Most corrosion failures in amine service are local-ized corrosion. Thus, a focus should be given to local-ized corrosion, since it occurs in specific areas and is often undetected until an unexpected or premature failure occurs. Different forms of localized corrosion, namely pitting, erosion, galvanic, stress corrosion and inter-granular should be identified, as well as proper

prevention techniques (e.g., use of effective inhibitors and control of system’s potential to passive regions).

More corrosion inhibitors must be screened, and their performances and roles in preventing corrosion in amine system should be evaluated. Evaluation of blends of two or more potential chemicals should be done to evaluate possible synergistic effect to enhance corrosion inhi-bition. One should also keep in mind that developed inhibitors should not trigger additional problems in the amine plants, such as solvent degradation and foaming. In addition, long-term exposure test using those inhibi-tors should be carried out to demonstrate their stability and extended inhibiting power.

Advanced analytical tools have been introduced to assist the electrochemical method to determine corro-sive species in amine–CO

2 systems. These tools, includ-

ing micro-Raman, should be applied to investigate corrosion species and to study corrosion inhibition of different types of corrosion inhibitors at various process parameters. The challenge is to find a way to use cur-rently available instruments to perform in situ ana lysis of corrosion species in the vicinity of the electrodes in an amine–CO

2 aqueous solution.

Future perspectiveAs demand for energy increases, there is a growing reli-ance on coal combustion for power generation. This is leading to ever-increasing CO

2 emissions from large,

stationary sources. Post-combustion CO2 capture using

alkanolamine absorption is considered by many to be one of the major technologies for reducing these emis-sions. MEA will likely continue to be the most effective solvent in use over the next 5–10 years; during this time, new candidate solvents with their characteristic proper-ties for CO

2 absorption have to be developed and com-

mercialized. In this regard, there will be more blending of other solvents with MEA (formulation) to overcome corrosion and other limitations compared with the use of MEA alone. This will complicate the corrosion behavior in amine systems, as every process parameter can also have an influence on corrosion and on the behavior of the various components of the blended amine solution. The effects of impurities such as SO

2 and NO

x in flue gas

on corrosion need also to be included in future research, as there are few studies on SO

2 and none on NO

x. As

seen in this review, a few advanced analytical instruments have been introduced for use in the study of corrosion. There will be more uses developed for state-of-the-art, advanced analytical instruments in order to explicitly uncover the electrochemistry of corrosion in order to identify the chemical species generated and their paths to the corrosion. Eventually methods will emerge that will demonstrate good methods of corrosion prevention and corrosion that can be inhibited in a cost-effective manner.



Financial & competing interests disclosureThe authors would like to acknowledge the research support over recent years to the International Test Centre by the followings orga-nizations: Natural Sciences and Engineering Research Council of Canada, Canada Foundation for Innovation, Saskatchewan Ministry of Energy & Resources, Western Economic Diversification, EnCana Energy Inc., EON Energy, RWE Corp, Saudi Aramco, Doosan Heavy Industries, HTC Purenergy Inc. Saskatchewan Power Corporation, StatOil Hydro (Norway), SaskFerco Inc., Sulzer Chemtech (Switzerland), Fluor Corporation (USA), the Canada Centre for Mineral and Energy Technology, Alberta Energy Research

Institute and the Research Institute of Innovative Technology for the Earth. In addition, the authors would also like to acknowledge the recent research supports from Provincial Government of Hunan, Federal Government of China, as well as Hunan University to the Joint International Center for CO

2 Capture and Storage. The

authors have no other relevant affiliations or financial involvement with any organization or entity with a financial interest in or finan-cial conflict with the subject matter or materials discussed in the manuscript apart from those disclosed.

No writing assistance was utilized in the production of this manuscript.

Executive summary

� Alkanolamine absorption has played a major role in acid-gas removal, both past and present. � There are many activities using amine absorption in capturing CO2 from power plant coal-fired flue gas. � Corrosion is one of the drawbacks of capturing CO2 using amine absorption:

� Blending of existing typical alkanolamines (monoethanolamine, diethanolamine, methyldiethanolamine and 2-amino-2-methyl-1-propanol), as well as new solvents (piperazine and sterically hindered amines), has been studied as a means to increase the efficiency and absorption capacity of absorbents, to decrease energy requirements in the stripping process and to reduce corrosion;

� Corrosion by heat-stable salt is reported in the typical alkanolamines systems. There are few studies of corrosion in new solvents systems;

� Each system parameter, that is, concentrations of amine, CO2, oxygen and impurities, as well as temperature, increases the corrosion rate of carbon-steel equipment under alkanolamine operating conditions.

� Generation of corrosion mechanisms is based on information from advanced analysis, using 13C-NMR, inductively coupled plasma–MS, scanning electron microscope and energy-dispersive spectrometers, assisting the electrochemical methods to measure chemical species in identification of corrosion products.

� Corrosion in alkanolamine systems cannot be avoided: mixed anodic and cathodic inhibitors are recommended to change oxidative–reductive reaction behavior of potential corrosive species.

ReferencesPapers of special note have been highlighted as:n of interestnn of considerable interest

1 Fontana MG. Corrosion Engineering (3rd Edition). McGraw-Hill Book Co., NY, USA (1986).

n Useful book providing principles of corrosion engineering and chemistry.

2 Kelly RG, Scully JR, Shoesmith DW, Buchheit RG. Electrochemical Techniques in Corrosion Science and Engineering. Marcel Dekker Inc., NY, USA (2003).

3 Polasek J, Bullin JA. Selecting amines for sweetening units. Presented at: GPA Regional Meeting. Tulsa, OK, USA, September 1994.

4 DuPart MS, Bacon TR, Edwards DJ. Part 1: understanding corrosion in alkanolamine gas treating plants: proper mechanism diagnosis optimizes amine operations. Hydrocarb. Process. Int. Ed. 72, 75–80 (1993).

5 DuPart MS, Bacon TR, Edwards DJ. Part 2: understanding corrosion in alkanolamine gas treating plants: proper mechanism

diagnosis, optimizes amine operations. Hydrocarb. Process. Int. Ed. 72, 89–94 (1993).

6 Kohl AL, Nielsen RB. Gas Purification (Fifth Edition). Gulf Publishing Co., Houston, TX, USA (1997).

7 Rooney PC, Dupart MS. Corrosion in alkanolamine plants: causes and minimization. Presented at: Corrosion 2000: NACE International Annual Conference and Exposition. Orlando, FL, USA, 26–31 March 2000.

8 Versteeg GF, Vanswaaij WP. On the kinetics between CO

2 and alkanolamines both in

aqueous and non-aqueous solutions-II. Tertiary amines. Chem. Eng. Sci. 43(3), 587–591 (1988).

9 Wilson M, Tontiwachwuthikul P, Chakma A et al. Test results from a CO

2 extraction

pilot plant at boundary dam coal-fired power station. Energy 29(9–10), 1259–1267 (2004).

10 Astarita G, Savage D, Bisio A. Gas Treating With Chemical Solvents. J Wiley & Sons, NY, USA (1983).

11 Chakma A, Mehrotra AK, Nielsen B. Comparison of chemical solvents for

mitigating CO2 emissions from coal-fired

power plants. Heat Recov. Syst. CHP 15(2), 231–240 (1995).

12 Xu X, Song C, Wincek R, Andresen JM, Miller BG, Scaroni AW. Separation of CO

2

from power plant flue gas using a novel CO2

‘molecular basket’ adsorbent. Fuel Chem. Div. Preprints 48(1), 162–163 (2003).

13 Supap T, Idem R, Tontiwachwuthikul P, Saiwan C. Kinetics of sulfur dioxide and oxygen induced degradation of aqueous monoethanolamine solution during CO

2

absorption from power plant flue gas streams. Int. J. Greenhouse Gas Control 3(2), 133–142 (2009).

14 Closmann F, Rochelle GT. Degradation of aqueous methyldiethanolamine by temperature and oxygen cycling. Energy Procedia 4, 23–28 (2011).

15 Nielsen RB, Hansen DA, Lewis KR. Corrosion in refinery amine systems. Presented at: Corrosion 1995: NACE International Annual Conference and Exposition. Orlando, FL, USA, 26–31 March 1995.

16 Chakma A, Meisen A. Corrosivity of diethanolamine solutions and their



degradation products. Ind. Eng. Chem. Prod. Res. Dev. 25(4), 627–630 (1986).

17 Davis J, Rochelle GT. Thermal degradation of monoethanolamine at stripper conditions. Energy Procedia 1, 327–333 (2009).

18 Kittel J, Idem RO, Gelowitz D, Tontiwachwuthikul P, Parrain G, Bonneau A. Corrosion in monoethanolamine units for CO

2 capture: pilot plant studies. Energy

Procedia 1, 791–797 (2009).

n Article showing corrosion results in monoethanolamine (MEA) system from actual CO

2 pilot plant.

19 Gao J, Wang S, Zhou S, Zhao B, Chen C. Corrosion and degradation performance of novel absorbent for CO

2 capture in

pilot-scale. Energy Procedia 4, 1534–1541 (2011).

20 Veawab A, Tontiwachwuthikul P, Chakma A. Corrosion behavior of carbon steel in the CO

2 absorption process using aqueous

amine solutions. Ind. Eng. Chem. Res. 38(10), 3917–3924 (1999).

21 Lawal O, Bello A, Idem RO. The role of N-methyldiethanolamine in preventing the oxidative degradation of CO

2 loaded and

concentrated aqueous monoethanolamine blends during CO

2 absorption from f lue

gases. Ind. Eng. Chem. Res. 44(6), 1874–1896 (2005).

22 Eustaquio-Rinco´n R, Rebolledo-Libreros ME, Trejo A, Molnar R. Corrosion in aqueous solution of two alkanolamines with CO

2 and H

2S:

N-methyldiethanolamine + diethanolamine at 393 K. Ind. Eng. Chem. Res. 47(14), 4726–4735 (2008).

23 Bishnoi S. Rochelle GT. Absorption of carbon dioxide into aqueous piperazine: reaction kinetics, mass transfer and solubility. Chem. Eng. Sci. 55(22), 5531–5543 (2000).

24 Rayer AV, Sumon KZ, Henni A, Tontiwachwuthikul P. Kinetics of the reaction of carbon dioxide (CO

2) with

cyclic amines using the stopped-f low technique. Energy Procedia 4, 140–147 (2011).

25 Freeman SA, Dugas R, Van Wagener DH, Nguyen T, Rochelle GT. Carbon dioxide capture with concentrated aqueous piperazine. Int. J. Greenhouse Gas Control 4(2), 119–124 (2010).

26 Yoon Y, Nam S, Jung S, Kim Y. K2CO

3/

hindered cyclic amine blend (SEFY-1) as a solvent for CO

2 capture from various

industries. Energy Procedia 4, 267–272 (2011).

27 Freeman SA. Rochelle GT. Thermal degradation of piperazine and its structural analogs. Energy Procedia 4, 43–50 (2011).

28 Maneeintr K, Idem RO, Tontiwachwuthikul P, Wee AGH. Synthesis, solubilities, and cyclic capacities of amino alcohols for CO

2

capture from flue gas streams. Energy Procedia 1, 1327–1334 (2009).

29 Maneeintr K, Idem RO, Tontiwachwuthikul P, Wee AGH. Comparative mass transfer performance studies of CO2 absorption into aqueous solutions of DEAB and MEA. Ind. Eng. Chem. Res. 49(6), 2857–2863 (2010).

30 Chowdhury FA, Okabe H, Yamada H, Onoda M, Fujioka Y. Synthesis and selection of hindered new amine absorbents for CO

2

capture. Energy Procedia 4, 201–208 (2011).

31 Robinson K, McCluskey A, Attalla M. The effect of molecular structural variations has on the CO

2 absorption characteristics of

heterocyclic amines. Energy Procedia 4, 224–231 (2011).

32 Zhang P, Shi Y, Wei, Zhao W, Qing Y. Regeneration of 2-amino-2-methyl-1-propanol used for carbon dioxide absorption. J. Environ. Sci. 20(1), 39–44 (2008).

33 Plaza JM., Rochelle GT. Modeling pilot plant results for CO

2 capture by aqueous

piperazine. Energy Procedia 4, 1593–1600 (2011).

34 Tan C, Chen J. Absorption of carbon dioxide with piperazine and its mixtures in a rotating packed bed. Sep. Purif. Technol. 49(2) 174–180 (2006).

35 Zhang J, Agar X, Zhang DW, Geuzebroek F. CO

2 absorption in biphasic solvents with

enhanced low temperature solvent regeneration. Energy Procedia 4, 67–74 (2011).

36 Hartono A, Hoff KA, Mejdell T, Svendsen HF. Solubility of carbon dioxide in aqueous 2.5 M of diethylenetriamine (DETA) solution. Energy Procedia 4, 179–186 (2011).

37 Bhattacharya S, Aroonwilas A, Veawab A. Kinetics of carbon dioxide absorption into aqueous solutions of monoethanolamine solution of monoethanolamine (MEA)-2-amino-2-methyl-1-propanol (AMP) blends under industrial conditions. Presented at: The 10th International Conference on Greenhouse Gas Technologies. Amsterdam, The Netherlands, 19–23 September 2010.

38 Behr P, Maun A, Deutgen K, Tunnat A, Oeljeklaus G, Görner K. Kinetic study on promoted potassium carbonate solutions for CO

2 capture from flue gas. Energy Procedia

4, 85–92 (2011).

39 Nainar M, Veawab A. Corrosion in CO2

capture process using blended monoethanolamine and piperazine. Ind. Eng. Chem. Res. 48(20), 9299–9306 (2009).

40 Dang H, Rochelle GT. CO2 Absorption rate

and solubility in monoethanolamine/ piperazine/water. Sep. Sci. Technol. 38(2), 337–357 (2003).

41 Zhao B, Sun Y, Yuan Y et al. Study on corrosion in CO

2 chemical absorption

process using amine solution. Energy Procedia 4, 93–100 (2011)

42 Bishnoi S, Rochelle GT. Absorption of carbon dioxide in aqueous PZ/MDEA, AIChE J. 48(12), 2788–2799 (2002).

43 Cullinane JT, Rochelle GT. Carbon dioxide absorption with aqueous K

2CO

3 promoted

by piperazine. Chem. Eng. Sci. 59(17), 3619–3630, (2004).

44 Bello A, Idem RO. Pathways for the formation of products of the oxidative degradation of CO

2-loaded concentrated

aqueous monoethanolamine solutions during CO

2 absorption from flue gases. Ind.

Eng. Chem. Res. 44(4), 945–969 (2005).

45 Verma N, Verma A. Amine system problems arising from heat stable salts and solutions to improve system performance. Fuel Pro. Technol. 90(4), 483–489 (2009).

46 Rooney PC, DuPart MS, Bacon TR. Effect of heat stable salts on solution corrosivity of MDEA-based alkanolamine plants. Presented at: The 48th Annual Laurance Reid Gas Conditioning Conference. Norman, OK, USA, 2–5 March 1997.

47 Bosen SF, Bedell SA. The relevance of bicine in the corrosion of amine gas treating plants. Presented at: Corrosion 2004: NACE International Annual Conference and Exposition. New Orleans, LA, USA, 28 March–1 April 2004.

48 Tanthapanichakoon W, Veawab A, McGarvey B. Electrochemical investigation on the effect of heat-stable salts on corrosion in CO

2 capture plants using aqueous

solution of monoethanolamine. Ind. Eng. Chem. Res. 45(8), 2586–2593 (2006).

nn Reports roles of major heat-stable salts in accelerating corrosion rates

49 Soosaiprakasam IR, Veawab A. Corrosion and polarization behavior of carbon steel in MEA-based CO

2 capture process. Int.

J. Greenhouse Gas Control 2(4), 553–562 (2008).

50 Kladkaew N, Idem RO, Tontiwachwuthikul P, Saiwan C. Corrosion behavior of carbon steel in the monoethanolamine-H

2O-CO

2-

O2-SO

2 system: products, reaction



pathways, and kinetics. Ind. Eng. Chem. Res. 48(23), 10169–10179 (2009).

n Useful article showing effect of SO2 on

corrosion in MEA systems.

51 Kladkaew N, Idem RO, Tontiwachwuthikul P, Saiwan C. Corrosion behavior of carbon steel in the monoethanolamine-H

2O-CO

2-

O2-SO

2 system. Ind. Eng. Chem. Res. 48(19),

8913–8919 (2009).

n Useful article showing effect of SO2 on

corrosion in MEA systems.

52 Delfort B, Carrette PL, Bonnard L. MEA 40% with improved oxidative stability for CO

2 capture in post-combustion. Energy

Procedia 4, 9–14 (2011).

53 Veawab A, Tontiwachwuthikul P, Chakma A. Influence of process parameters on corrosion behavior in a sterically hindered amine-CO

2 system. Ind. Eng. Chem. Res.

38(1), 310–315 (1999).

54 Bonenfant D, Mimeault M, Hausler R. Estimation of the CO

2 absorption capacities

in aqueous 2-(2-Aminoethylamino) ethanol and its blends with MDEA and TEA in the presence of SO

2. Ind. Eng. Chem. Res.

46(26), 8968–8971 (2007).

55 Rao AB, Rubin ES. A technical, economic, and environmental assessment of amine-based CO

2 capture technology for power

plant greenhouse gas control. Environ. Sci. Technol. 36(20), 4467–4475 (2002).

56 Chávez RH, Guadarrama J de J, Klapp J. CO

2 capture for atmosphere pollution

reduction. In: Towards a Cleaner Planet: Energy for the Future. Chávez RH, Guadarrama JJ, Klapp J (Eds). Springer, Berlin, Germany (2007).

57 Uyanga IJ, Idem RO. Studies of SO2- and

O2-induced degradation of aqueous

monoethanolamine during CO2 capture

from power plant flue gas streams. Ind. Eng. Chem. Res. 46(8), 2558–2566 (2007).

58 Danckwerts PV, McNeil KM. The absorption of carbon dioxide into aqueous amine solutions and the effect of catalysis. Trans. Inst. Chem. Eng. 45, T32 (1967).

59 Chakraborty AK, Astarita, G, Bischoff KB. CO

2 absorption in aqueous solutions of

hindered amines. Chem. Eng. Sci. 41(4), 997–1003 (1986).

60 Ciftja AF, Hartono A, Da Silva EF, Svendsen HF. Study on carbamate stability in the AMP/CO

2/H

2O system from

13C-NMR spectroscopy. Energy Procedia 4, 614–620 (2011).

61 Yamada H. Matsuzaki Y, Okabe H, Shimizu S, Fujioka Y. Quantum chemical ana lysis of

carbon dioxide absorption into aqueous solutions of moderately hindered amines. Energy Procedia 4, 133–139 (2011).

62 Veawab A, Aroonwilas A. Identification of oxidizing agents in aqueous amine–CO

2

systems using a mechanistic corrosion model. Corros. Sci. 44(5), 967–987 (2002).

nn One of a few articles identifying oxidizing species that cause corrosion in amine system.

63 Cummings AL, Waite SW, Nelsen DK. Corrosion and corrosion enhancers in amine systems. Presented at: The Brimstone Sulfur Conference. Banff, AB, Canada, April 2005.

64 Heuer JK, Stubbins JF. An XPS characterization of FeCO

3 films from CO

2

corrosion. Corros. Sci. 41(7), 1231–1243 (1999).

65 Singh P, Da Silva EF, Brilman DWF. Determination of structural effects on carbamate stability for various amine based solvents by using ab initio method. Presented at: The 10th International Conference on Greenhouse Gas Technologies. Amsterdam, The Netherlands, 19–23 September 2010.

66 Da Silva EF, Svendsen HF. Study of the carbamate stability of amines using Ab Initio methods and free-energy perturbations. Ind. Eng. Chem. Re. 45(8), 2497–2504 (2006).

67 CRC Press. Handbook of Chemistry and Physics (65th Edition). Weast RC (Ed.). CRC Press, FL, USA (1984).

68 Beutler D, Renon H. Representation of NH

3-H

2S-H

2O, NH

3-CO

2- H

2O, and

NH3-SO

2-H

2O vapor-liquid equilibria. Ind.

Eng. Chem. Process Des. Dev. 17(3), 220–230 (1978).

69 Sastri VS. Corrosion Inhibitors. John Wiley & Sons, Chichester, UK (2001).

70 Liu HJ, Dean JW. Neutralization technology to reduce corrosion from heat-stable amine salts. Presented at: Corrosion 1995: NACE International Annual Conference and Exposition. Orlando, FL, USA, 26–31 March 1995.

71 Thitakamol B, Veawab A. Foaming behavior in CO

2 absorption process using aqueous

solutions of single and blended alkanolamines. Ind. Eng. Chem. Res. 4(21), 216–225 (2008).

n Article showing foaming side effects of some effective corrosion inhibitors.

72 Veawab A, Tontiwachwuthikul P, Chakma A. Investigation of low-toxic organic corrosion inhibitors for CO

2 separation process using

aqueous monoethanolamine solvent. Ind. Eng. Chem. Res. 40(22), 4771–4777 (2001).

nn Useful article evaluating effect of various corrosion inhibitors in MEA system.

73 Bello A, Idem RO. Comprehensive study of the kinetics of the oxidative degradation of CO

2 loaded and concentrated aqueous

monoethanolamine (MEA) with and without sodium metavanadate during CO

2 absorption

from flue gases. Ind. Eng. Chem. Res. 45(8), 2569–2579 (2006).

n Article showing degradation side effects of some effective corrosion inhibitors.

74 Eldin AMS, Wang LF. Mechanism of corrosion inhibition by sodium molybdate. Desalination 107(1), 29–43 (1996).

75 Haddad F, Benchettara A, Amara SE, Kesri R. Cobalt and molybdate ions effects on the passivation of iron based FeCoC ternary alloys, in non deaerated solution of 10–13 M NaHCO3 + 10–13 M Na2SO4, at 25°C. Portugaliae Electrochimica Acta 26, 181–198 (2008).

76 Veawab A, Tontiwachwuthikul P, Bhole SD. Studies of corrosion and corrosion control in a CO

2–2-amino-2-methyl-1-propanol (AMP)

environment. Ind. Eng. Chem. Res. 36(1), 264–269 (1997).

77 Soosaiprakasam, I, Veawab, A. Inhibition performance of copper carbonate in CO

2

absorption process using aqueous MEA. Presented at: Corrosion 2007: NACE International Annual Conference and Exposition. Nashville, TN, USA, 11–15 March 2007.

78 Jovancicevic V, Ramachandran S, Prince P, Petrolite B. Inhibition of CO

2 corrosion in

mild steel by imidazolines and their precursors. Presented at: Corrosion 1998: NACE International Annual Conference and Exposition. San Diego, CA, USA, 22–27 March 1998.

nn Offers different concept of corrosion inhibition derived from structures of the inhibitors.

79 Ramachandran S, Jovancicevic V, Petrolite B. Molecular modeling of the inhibition of mild steel carbon dioxide corrosion by imidazolines. Presented at: Corrosion 1998: NACE International Annual Conference and Exposition. San Diego, CA, USA, 22–27 March 1998.

nn Offers different concept of corrosion inhibition derived from structures of the inhibitors.

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203 ScienceLab.com. Chemical and laboratory equipment. www.sciencelab.com/msds.php?msdsId=9923591

future science group oxidation reaction

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