Foaming Behavior in CO2 Absorption Process Using Aqueous

Dec 1, 2007 - Surface tension, viscosity, and density of solutions play a major role ... Key Considerations for Solvent Management and Environmental I...
0 downloads 0 Views 238KB Size
Download PDF
216

Ind. Eng. Chem. Res. 2008, 47, 216-225

GENERAL RESEARCH Foaming Behavior in CO2 Absorption Process Using Aqueous Solutions of Single and Blended Alkanolamines Bhurisa Thitakamol and Amornvadee Veawab* Faculty of Engineering, UniVersity of Regina, Saskatchewan, Canada S4S 0A2

This work provides a comprehensive investigation on the effects of process parameters on foaming behavior in the carbon dioxide (CO2) absorption process using aqueous alkanolamine solutions, particularly for the application of postcombustion flue gas treatment. The foaming tendency of this process was experimentally evaluated using the pneumatic method modified from ASTM standard, and reported in terms of foaminess coefficient (Σ). Results reveal ranges of solution volume and gas flow rate leading to constant values of Σ. Σ increases and eventually decreases with alkanolamine concentration and CO2 loading. A higher solution temperature reduces Σ. Most tested degradation products and corrosion inhibitors enhance foaming tendency. Monoethanolamine (MEA), methyldiethanolamine (MDEA), and a blend of MEA + 2-amino-2-methyl-1propanol (AMP; 2:1 mixing ratio) tend to foam, whereas diethanolamine (DEA), AMP, and blends of MEA + MDEA, DEA + MDEA and MEA + AMP (1:1 and 1:2 mixing ratio) do not. Surface tension, viscosity, and density of solutions play a major role in foaming tendency. 1. Introduction Foaming is one of the most severe operational problems in acid gas treating plants that remove carbon dioxide (CO2) and hydrogen sulfide (H2S) from petroleum gas streams by using a principle of gas absorption into aqueous solutions of alkanolamines. On the basis of plant experiences,1-9 foaming occurred during plant startup and operation in both absorber and regenerator. It was caused by high gas velocities, sludge deposits on gas contactors, and process contaminants entering the process with feed gas and makeup water or generated within the process through reactions of alkanolamine degradation. These process contaminants were condensed or dissolved hydrocarbons, suspended solids, organic acids, water-soluble surfactants, degradation products of alkanolamine, additives (e.g., corrosion inhibitors and antifoam agents), grease, and inorganic chemicals in makeup water. Foaming was reported to cause a number of adverse impacts on the integrity of plant operation, reflecting significant extra expenditures in capital investment and operation. Such impacts include excessive loss of absorption solvents, premature flooding, reduction in plant throughput, off-specification of products, and high absorption solvent carryover to downstream plants. To cope with foaming problems, preventive and control measures, including mechanical filtration, carbon adsorption, solution reclamation (distillation), and antifoam addition, have been applied. The antifoam addition is the least preferable among the three measures because it does not physically remove process contaminants from the system and thus does not permanently remedy foaming problems.2,5,6,10 Apart from the above plant experiences, there were several research works systematically carried out to reveal behavior and mechanism of foaming in gas treating plants. In 1989, Pauley and his colleagues10 studied the effects of alkanolamine types, * To whom correspondence should be addressed. Tel.: (306) 5855665. Fax: (306) 585-4855. E-mail: [email protected].

liquid hydrocarbon and degradation products on foaming tendency and foam stability by using air as a dispersing gas under atmospheric pressure. The tested alkanolamines included monoethanolamine (MEA), dhanolamine (DEA), methyldiethanolamine (MDEA), and two formulated MDEA (with nonspecified additives). They found that the foam generated by MEA, DEA, and MDEA was small and unstable. As a result, these alkanolamines had less foaming tendency and foam stability than the two formulated MDEAs. A 5000 ppm amount of liquid hydrocarbon was also added to MEA, MDEA, and two formulated MDEA solutions to study the effect of liquid hydrocarbon. The results showed that the addition of liquid hydrocarbon significantly affected foam stabilities of MDEA and formulated MDEA due to the formation of a gelatinous layer. However, both foaming tendency and foam stability of pure MEA were not greatly changed. The organic acids added to examine the effect of the degradation product were formic acid, acetic acid, propionic acid, butyric acid, pentanoic acid, n-hexanoic acid, octanoic acid, decanoic acid, and dodecanoic acid. The first five organic acids were tested only in MEA and the rest were tested in MEA, DEA, MDEA, and one formulated MDEA. It was found that the degradation products caused an increase in both foaming tendency and foaming stability in pure alkanolamine solutions. In 1996, McCarthy and Trebble11 carried out an experimental investigation using DEA to evaluate the effects of methanol, corrosion inhibitor, antifoam agent, lubrication oil, organic acids, degradation products, and suspended solids at temperatures ranging from 20 to 85 °C and under pressures of 0.1-3 MPa. The solutions contained in a Jerguson high-pressure sight glass was purged by air, nitrogen (N2), CO2, and ethane (C2H6). Results indicated that most tested additives and contaminants did not initiate foams in the clean aqueous DEA solution, but rather acted as foam promoters once foams already existed in

10.1021/ie070366l CCC: $40.75 © 2008 American Chemical Society Published on Web 12/01/2007

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008 217

Figure 1. Foam characterization based on gas and liquid fraction criteria (redrawn from refs 13 and 14).

the system. As temperature and pressure were increased, foams were enhanced as a result of the reduced surface tension. Later in 1998, Harruff12 invented a foam testing apparatus to assess foaming tendency of diglycolamine (DGA) at operating conditions of gas treating plants (approximately 93 °C and up to 6.9 MPa) by using N2 gas as a dispersed phase. The foaming tendency of DGA solution was lowered at a higher temperature, but slightly affected by a pressure variation. It is apparent from the above reviews that the knowledge of foaming in gas treating plants for oil and gas operations is limited since it was mostly derived from plant experiences, and only several research works were carried out and published in the literature. The current knowledge is not adequate for the development of cost-effective preventive and control technology for foaming in gas treating applications. The knowledge is even more limited for the CO2 absorption process that is used for capturing CO2 from industrial flue gas for the purpose of greenhouse gas emission reduction. No reports of plant experiences and no research works on foaming are presently available since the CO2 capture from flue gas has not yet been widely implemented but is anticipated to have a widespread use in coming years. Due to such a lack of knowledge, this work was aimed at obtaining comprehensive foaming information from bench-scale experiments under well-simulated environments. The objectives were to reveal the parametric effects which have never been studied in previous works (e.g., CO2 loading, gas flow rate, volume of solution, amine concentration, and certain types of heat-stable salts, blended alkanolamines, and corrosion inhibitors), reinvestigate the parametric effects that show conflicting results in previous works (e.g. temperature), and examine the parametric effects for postcombustion flue gas treatment applications. The obtained knowledge from this work will subsequently be used for the detailed study of foaming impacts on CO2 absorption performance and ultimately for the development of cost-effective means of foaming prevention and control. 2. Foam Theory 2.1. Foam Characteristics. Foam is a colloidal system with agglomeration of closed gas bubbles being dispersed in a liquid. Each bubble is separated by a thin liquid film, called lamella. Foams can be classified into two types, Kugelschaum and Polyederschaum, depending on gas and liquid fraction, as illustrated in Figure 1. Kugelschaum is a sphere-shaped foam with a thickness of the lamella between gas bubbles approximately equal to the diameter of gas bubble. It is located next to liquid surface and contains high liquid fraction.

Figure 2. Three principal forces influencing bubble formation.

Kugelschaum turns to polyhedral-shaped Polyederschaum when the amount of liquid in the lamella is decreased due to drainage. Polyederschaum is thus located between Kugelschaum and gas phase and is subject to foam coalescence and rupture. 2.2. Foam Mechanism. To form a foam, gas is purged into liquid through a diffuser or an orifice. As illustrated in Figure 2, buoyancy, surface and hydrostatic forces are important to foam formation. A bubble from the diffuser is lifted up through bulk liquid by the buoyancy force (Fbuoy), which is a function of density difference between liquid and gas (F), bubble volume (Vbub), and gravitational acceleration (g) as expressed below.

Fbuoy ) FVbubg

(1)

The buoyancy force must overcome the hydrostatic force and the surface force (Fsurf), which is produced by surface tension of liquid solution (γ) and capillary perimeter (l), in order for the bubble to detach from the diffuser.

Fsurf ) γl

(2)

Once foams are formed in the system, they can undergo the thinning process caused by drainage, foam coalescence, and foam rupture as described below. When three bubbles adjoin, a plateau border (PB) is formed by concaving three lamella to bubbles with an angle of 120°, which can be decreased to 109° in case that four bubbles meet at the PB.15 As a result, a polyhedral or honeycomb network of bubbles is formed and allows liquid to flow around the interconnected PB structure. Disproportionation or Ostwald ripening can be observed from the dissolution of smaller bubbles into bigger ones. After the lamella rearrangement, surface tension naturally creates a pressure gradient of the pressure inside (concaved side) and outside (convex side) the bubble. Such a pressure gradient is commonly called capillary pressure (∆Pcap.). An increase in the capillary force causes a liquid to flow from the lamella to the PBs (called a capillary flow or Laplace flow) and thus leads to a thin lamella thickness and foam rupture. The change in the principal radii of curvature due to the bubble deformation accelerates foam drainage since it increases capillary force. This force also indicates an external stress, a product of velocity gradient and viscosity, that must be applied to a bigger bubble for breaking up into smaller ones.16 Besides the capillary force, drainage can be caused by gravitational and hydroequilibrium force.

218

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008

Figure 3. Schematic diagram of foaming experimental setup.

2.3. Foam Stability. By nature, foams are subject to three main instabilities, i.e., thinning, coalescence, and rupture. Such instabilities lead to a decrease in their surface area and consequently surface free energy.14 It is an opposite characteristic to foam stability affected by surface elasticity, Marangoni effect, surface and bulk viscosity, repulsive Coulombic force, and gravitational force. Surface elasticity (E) is an ability of surface to resist a thinning process due to a surface tension gradient. It is essentially a change in surface tension with respect to a change in surface area (A) as expressed below.

E ) 2A(dγ/dA)

(3)

During gas dispersion, a surface tension gradient between a stretched and a nonstretched area of surfactant-adsorbed surfaces is created as the surface is exposed to rapid expansion and shrinkage. At this point, the surface elasticity is responsible for balancing this gradient by using viscous forces to induce the underlying liquid to flow from the stretched area to the nonstretched area as a result of self-contraction of surfaces. Consequently, the stretched area is thickened, and foam stability is enhanced.13,17,18 The phenomenon that the surface tension gradient causes a liquid flow in the lamella is referred to as Marangoni effect. Bulk viscosity and surface viscosity also play an important role in foam stability. The bulk viscosity is the liquid viscosity in a bulk liquid phase, while the surface viscosity is the liquid viscosity at the interface between gas bubble and liquid in the lamella. The surface viscosity is usually higher than the bulk viscosity, and is also increased accordingly to an increase in bulk viscosity. Generally, high bulk viscosity is favorable since it will slow down the drainage due to gravitational force. However, an increase in bulk viscosity can lead to a very high surface viscosity and eventually can destroy surface elasticity. This is because the surface films cannot be easily moved with only a small amount of external stress and becomes a solidlike at a high surface viscosity, which, in turn, decreases foam stability. In addition to the above-mentioned forces, other external forces also have an impact on the foam stability. The repulsive Coulombic forces typically slow down the gravity drainage, while the gravitational force does the opposite.10 3. Experiments 3.1. Experimental Setup. Foaming experiments were carried out using the pneumatic method modified from the standard ASTM D892 for foaming tests of lubricating oils.19 As illustrated in Figure 3, the experimental setup was composed of a 0.001 m3 graduated cylinder cell, a temperature bath with an immersion digital circulator with an accuracy of (0.01 °C in the temperature ranging from 5 °C above ambient temperature to 120 °C, a metal diffuser supplied from Petrolab Corp. (Latham,

NY), a polycarbonate drying column, a flowmeter with an accuracy of (2% full scale, and a gas mass flowmeter with an accuracy (1% full scale. The diffuser was made of sintered 5 µm porous stainless steel with a maximum pore diameter not greater than 80 µm. Industrial grade nitrogen (N2) purchased from Praxair (Canada) was utilized as a dispersed gas to bubble the test solution instead of air. This was to prevent the degradation of alkanolamine that may affect the foaming data obtained and also to maintain the CO2 loading of the test solution during experiment. 3.2. Preparation of Test Solutions. This work investigated four single alkanolamines, MEA, DEA, MDEA, and 2-amino2-methyl-1-propanol (AMP), and three blended alkanolamines, MEA + MDEA, DEA + MDEA, and MEA + AMP with mixing mole ratios of 1:2, 1:1, and 2:1. These alkanolamines were purchased from Sigma-Aldrich (Ontario, Canada) as reagent grades. Their aqueous solutions were prepared by diluting the reagent alkanolamines to a desired concentration using deionized water. The solution concentration was determined by titration using a standard solution of 1 N hydrochloric acid (HCl) and methyl orange as an indicator. The prepared solutions were loaded with CO2 by bubbling the industrial grade CO2 purchased from Praxair (Canada) through the fresh solutions of alkanolamines for a certain period of time, depending on the desired CO2 loading in solution. The CO2 loading was determined using the standard method established by the Association of Official Analytical Chemists (AOAC).20 3.3. Experimental Procedures. Prior to each experiment, the test solution was placed at a given volume (0.0004 m3 in most experimental runs) into a test cell without mechanical shaking or stirring and then heated in a temperature bath to a set temperature for approximately 20 min. A metal diffuser was inserted into the heated test cell and left for approximately 5 min to be saturated with the test solution. N2 gas was then introduced to a polycarbonate drying column to remove moisture before entering a flowmeter for an approximate measurement and subsequently a mass flowmeter for a steady reading. The test solution was vigorously bubbled by N2 through the gas diffuser with a blowing time of 25 min ( 5 s. The blowing time was first counted when the first N2 bubble raised from the gas diffuser. The N2 gas was eventually released to the atmosphere from the outlet of the test cell. The concentration of alkanolamine solution as well as its CO2 loading, conductivity, and pH were determined before and after each experiment to ensure no changes in the solution constituents due to the alkanolamine degradation products or the variation in operating condition. During the blowing time, the foam volume above the gas dispersion layer was recorded every minute. It should be noted here that the foam volume was in some cases difficult to measure due to the unclear interface between the gas dispersion and the Kugelschaum, the uneven polyederfoam surface, and the unpredictable foam rupture. As such, average foam volumes at the 25th minute were used instead of the actual foam volume to reduce errors due to data readings as illustrated in Figure 4. It was found that the average foam volume, in most experiments, began to reach a steady state after 10 min of blowing time. This steady value was thus used as the representative foam volume for subsequent data analysis. 3.4. Data Analysis. A foaminess coefficient (Σ) was calculated by using eq 4.21 It is a ratio of foam volume and gas flow rate, representing a residence time of gas traveling upward through the foam, or an average lifetime of foam before

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008 219

toxic ones. Alkanolamine types, both single and blended types, were also included in the test program. In addition to MEA representing primary alkanolamine, DEA, MDEA and AMP were selected to represent secondary, tertiary, and sterically hindered alkanolamines, respectively. Blended MEA + MDEA, DEA + MDEA, and MEA + AMP were chosen because they are gaining a great deal of attention for their energy saving characteristics. They represent mixtures of primary-tertiary, secondary-tertiary, and primary-sterically hindered alkanolamines. Figure 4. Average foam volume profile during blowing time (MEA solution volume ) 4.0 × 10-4 m3; CO2 loading ) 0.40 mol/mol; N2 flow rate ) 2.06 m3/(m2‚h); MEA concentration ) 5.0 kmol/m3; solution temperature ) 40 °C).

rupture.

Σ)

υo G

(4)

where υo is average steady foam volume (m3) and G is gas (N2) flow rate (m3/(m2‚h)). According to Bikerman,21 the foaminess coefficient will not depend on gas flow rate, dimension of test cell, solution volume, and pore size of diffuser if the solution volume is deep enough and the gas flow rate is in a proper range. In this work, such ranges of the solution volume and the gas flow rate are from 4.0 × 10-4 to 7 × 10-4 m3 and from 1.75 to 2.41 m3/(m2‚h), respectively. 3.5. Tested Parameters and Experimental Conditions. This work carried out a parametric study under a wide spectrum of operating conditions. The parameters of interest were solution volume, gas flow rate, alkanolamine concentration, CO2 loading of solution, solution temperature, degradation product of alkanolamine, corrosion inhibitor, and alkanolamine type. A summary of parameters and experimental conditions is given in Table 1. Solution volume and gas flow rate were included as test parameters to identify testing conditions enabling generation of foaming data that are not dependent on solution volume, gas flow rate, pore size of gas disperser, and dimension and volume of the test cell. Due to its popularity in gas treating, MEA was used as a representative solvent in most foaming tests. Its concentration and CO2 loading covered operating ranges in gas treating plants.22 Although the MEA concentration of 7.0 kmol/ m3 is not commonly used in practice due to severe corrosion of process equipment and piping, it was worth testing here since it presents an opportunity for an improved process efficiency and is thus expected to be in service together with a corrosion inhibitor in the near future. Solution temperatures up to 90 °C were tested to simulate the temperatures of various process components, such as absorber, rich-lean heat exchanger, and cooler. With the feature of the test cell, foaming tests at temperatures beyond 90 °C are not applicable since CO2 loading of the solution cannot be maintained under atmospheric pressure. Nevertheless, the obtained data are adequate to reveal the effect of temperature on foaming tendency. Thirteen degradation products were selected from the products reported in published literature, including both regenerable compounds (i.e., bicine)23 and non-regenerable ones (i.e., carboxylic acids, sulfite, sulfate, thiosulfate, thiocyanate, and chloride).24-28 Sodium metavanadate represents a toxic heavymetal corrosion inhibitor commonly used in gas treating plants, while copper(II) carbonate and sodium sulfite represent low

4. Results and Discussion This work provides a comprehensive set of foaming data under a wide spectrum of operating conditions in the CO2 absorption process using aqueous solutions of alkanolamines. The obtained foaminess coefficients were reproducible with a standard deviation of 0.15 min, thus reliable for revealing the effects of process parameters on Σ and providing a better understanding of foaming behavior. 4.1. Gas Flow Rate. N2 flow rate was varied from 0.44 to 3.40 m3/(m2‚h) in both 2.0 and 5.0 kmol/m3 MEA solutions under 0.40 mol/mol CO2 loading at 40 °C to investigate the effect of gas flow rate on Σ. The results in Figure 5 show that an increase in N2 flow rate nonlinearly decreases Σ. This is because the increasing turbulence created by the increasing gas flow rate disrupts foam formation and reduces foam stability. As N2 flow rate is further increased to 1.75 m3/(m2‚h) or greater, Σ reaches stabilization. This suggests that the volume of foams proportionally increases with N2 flow rate. Such a gas flow rate region with a constant Σ presents an opportunity for the elimination of gas flow rate effect on Σ in any foaming experiments. This work chose to use a N2 flow rate of 2.06 m3/(m2‚h) in all experimental runs. 4.2. Solution Volume. The effect of solution volume on Σ was investigated by varying the solution volume of a 2.0 kmol/ m3 MEA solution containing 0.40 mol/mol CO2 loading from 2.0 × 10-4 to 7.0 × 10-4 m3 at 40 °C and 2.06 m3/(m2‚h) N2 flow rate. The results shown in Figure 6 indicate that foam formation does not occur when the solution volume is 2.0 × 10-4 m3. This may be due to the insufficient contact time for gas and liquid contact or due to the inadequate hydrostatic force to resist the buoyancy force of a N2 bubble (Figure 2). As a result, the bubble detaches from the diffuser and induces a turbulent flow among bubbles in the test cell. The shearing force caused by this turbulence may destroy the foams. Once the solution volume increases to more than 2.0 × 10-4 3 m , foams are produced and Σ increases with solution volume. This is because the increase in solution volume leads to an increase in hydrostatic force which in turn reduces the turbulence caused by the bubble detachment from the diffuser. As the solution volume is further increased from 4.0 × 10-4 to 7.0 × 10-4 m3, Σ becomes invariant. This is because the increasing hydrostatic force overcomes the turbulence caused by the bubble detachment or makes such turbulence insignificant. Gravity drainage is also retarded because an increase in solution volume thickens a thickness of lamella. This eventually helps reduce foam collapse in the system. The above findings suggest that solution volume should not be chosen arbitrarily for foaming experiments since different values of foam volume and Σ can be obtained under an identical operating condition. To eliminate the effect of solution volume, the solution volume resulting in a steady Σ (i.e., g4.0 × 10-4 m3) should be used. This work thus selected the solution volume of 4.0 × 10-4 m3 for all experimental runs.

220

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008

Table 1. Summary of Tested Parameters and Operating Conditions parameter N2 flow rate: 0.44-3.40

m3/(m2‚h)

solution volume: (2.0-7.0) × 10-4 m3 alkanolamine concentration: 2.0-7.0 kmol/m3 CO2 loading: 0.10-0.55 mol/mol solution temperature: 40-90 °C degradation product of MEA: acetic acid; ammonium thiosulfate; bicine; formic acid; glycolic acid; hydrochloric acid; malonic acid; oxalic acid; sodium chloride; sodium sulfite; sodium thiocyanate; sodium thiosulfate; sulfuric acid corrosion inhibitor: copper carbonate; sodium metavanadate; sodium sulfite alkanolamine type: MEA; DEA; MDEA; AMP; MEA + MDEA; DEA + MDEA; MEA + AMP

Figure 5. Effect of gas flow rate on foaminess coefficient (MEA concentration ) 2.0 and 5.0 kmol/m3; solution volume ) 4.0 × 10-4 m3; CO2 loading ) 0.40 mol/mol; solution temperature ) 40 °C).

Figure 6. Effect of solution volume on foaminess coefficient (MEA concentration ) 2.0 kmol/m3; N2 flow rate ) 2.06 m3/(m2‚h); CO2 loading ) 0.40 mol/mol; solution temperature ) 40 °C).

4.3. Alkanolamine Concentration. Concentration of aqueous MEA solution was varied from 2.0 to 7.0 kmol/m3 under two operating conditions of an absorber, i.e., 0.20 mol/mol CO2 loading and 40 °C representing the condition of absorber top, and 0.40 mol/mol CO2 loading and 60 °C representing the condition of absorber bottom. The results in Figure 7 show that Σ initially increases with MEA concentration and then declines after the MEA concentration reaches 3.0 and 6.0 kmol/m3 in cases of absorber top and bottom, respectively. The increase in Σ with MEA concentration is due to the decrease in surface tension of the solution (Figure 8a). When the surface tension is decreased, the surface force is reduced and can be overcome by the buoyancy force of the foam bubble.

operating condition 2.0 & 5.0 MEA, 4.010-4 m3 solution volume, 0.40 mol/mol CO2 loading and 40 °C 2.0 kmol/m3 MEA, 2.06 m3/m2-hr N2 flow rate, 0.40 mol/ mol CO2 loading and 40 °C MEA, 2.06 m3/m2-hr N2 flow rate, 4.010-4 m3 solution volume, 0.20 & 0.40 mol/mol CO2 loading and 40 °C 5.0 kmol/m3 MEA, 2.06 m3/m2-hr N2 flow rate, 4.010-4 m3 solution volume and 40, 60 and 90 °C 5.0 kmol/m3 MEA, 2.06 m3/m2-hr N2 flow rate, 4.010-4 m3 solution volume and 0.20 & 0.40 mol/mol CO2 loading 10000 ppm of degradation product, 5.0 kmol/m3 MEA, 2.06 m3/ (m2‚h) N2 flow rate, 4.0 × 10-4 m3 solution volume, 0.40 mol/ mol CO2 loading, and 60 °C kmol/m3

1000 ppm of corrosion inhibitor, 5.0 kmol/m3 MEA, 2.06 m3/ (m2‚h) N2 flow rate, 4.0 × 10-4 m3 solution volume, 0.40 mol/ mol CO2 loading, and 60 °C 4.0 kmol/m3 alkanolamine; 2.06 m3/ (m2‚h) N2 flow rate; 4.0 × 10-4 m3 solution volume; 0.40 mol/ mol CO2 loading; 60 °C; and mixing mole ratios of blended solution ) 1:2, 1:1, and 2:1

Figure 7. Effect of alkanolamine concentration on foaminess coefficient (N2 flow rate ) 2.06 m3/(m2‚h); solution volume ) 4.0 × 10-4 m3; for absorber top condition, CO2 loading ) 0.20 mol/mol and solution temperature ) 40 °C; for absorber bottom condition, CO2 loading ) 0.40 mol/mol and solution temperature ) 60 °C).

This thus results in a greater foam volume and Σ. In addition to the surface tension, the density and viscosity of MEA solution are also attributable to the increase in Σ. The higher concentration of MEA solution increases the density and the bulk viscosity of the solution (Figure 8b,c). The increased solution density increases the buoyancy force of the foam bubble, while the increased bulk viscosity retards the foam collapse caused by gravity drainage. Both effects lead to a greater Σ. As mentioned previously, Σ not only increases but also decreases with MEA concentration when the MEA concentration is greater than 3.0 and 6.0 kmol/m3 under the conditions of absorber top and bottom, respectively. This is a result of the creaming process16 where bulk viscosity plays a significant role on the rising bubbles through the liquid phase to form a foam layer. According to Stokes’ equation, an increase in bulk viscosity leads to an increase in drag force which can retard or even stop the rising bubbles. This thus decreases foaming formation of the solution. Such decrease in Σ is also caused by a reduction of foam stability due to an increase in surface viscosity of the solution. The increased viscosity can make the foam surface more immobile and weakens the surface elasticity. As a result, the foam surface has less ability to resist foam thinning and collapse. 4.4. CO2 Loading. The effect of CO2 loading of solution on Σ was studied using 5.0 kmol/m3 aqueous MEA solutions under three different temperatures of 40, 60, and 90 °C and CO2

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008 221

Figure 8. (a) Surface tension of CO2-unloaded aqueous MEA solution replotted from experimental data;29 (b) predicted density of CO2-loaded MEA solution from correlation;30 (c) predicted viscosity of CO2-loaded aqueous MEA solutions from correlation30.

Figure 9. Effect of CO2 loading on foaminess coefficient (MEA concentration ) 5.0 kmol/m3; N2 flow rate ) 2.06 m3/(m2‚h); solution volume ) 4.0 × 10-4 m3; solution temperature ) 40, 60, and 90 °C).

loading ranging from 0.10 to 0.55 mol/mol. The results in Figure 9 show that an increase in CO2 loading increases Σ for all temperatures. This can be explained by surface tension and density of the solution. As CO2 loading increases, surface tension decreases (Figure 10a) and solution density increases (Figure

Figure 10. (a) Surface tension of CO2-loaded aqueous MEA solution measured by spinning drop interfacial tensiometer model 510; (b) predicted density of 5.0 kmol/m3 MEA solution from correlation;30 (c) predicted viscosity of 5.0 kmol/m3 MEA solution from correlation.30

10b). This results in a reduced surface force and an increased buoyancy force, thus promoting foam formation and causing a greater Σ. Such an increase in Σ is also due to an enhancement of foam stability caused by an increase in bulk viscosity (Figure 10c) preventing a thinning process and, by an increase in surface tension gradient, promoting Marangoni effect. According to Danckwerts and Tavares da Silva,31 ionic products from chemical reactions between CO2 and MEA increase surface tension. This results in a surface tension gradient of ionic product-concentrated interface and ionic product-diluted interface. As CO2 loading increases, such surface tension gradient becomes larger, which in turn enhances the Marangoni effect. In addition to the above increasing trend of Σ, the results in Figure 9 also show a decreasing trend of Σ after the CO2 loading is increased to a certain value. This is primarily due to the influence of solution viscosity, which becomes more significant than those of surface tension and density. At a higher CO2 loading, solution viscosity is increased (Figure 10c), thus discouraging foam formation. The higher solution viscosity also

222

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008

Figure 11. Effect of solution temperature on foaminess coefficient (MEA concentration ) 5.0 kmol/m3; N2 flow rate ) 2.06 m3/(m2‚h) solution volume ) 4.0 × 10-4 m3; CO2 loading ) 0.20 and 0.40 mol/mol).

reflects a greater surface viscosity, which in turn results in a reduction in foam stability. 4.5. Solution Temperature. Solution temperature was found to have a significant effect on Σ. As seen from Figure 11, as the temperature of 5 kmol/m3 MEA solutions is increased from 40 to 90 °C, Σ decreases considerably. This is true for both systems containing 0.20 and 0.40 mol/mol CO2 loading. Such effect is a result of poor foam stability, which is caused by a reduced bulk viscosity (Figure 12a) and a turbulence flow created by the vigorous movement of molecules at an elevated temperature. The effect of solution temperature on Σ can be quantified as the Arrhenius equation with the constants shown in Table 2.

Σ)

1 Ae

-Ea/RT

(5)

where A, Ea, R, and T represent frequency factor, activation energy, gas constant, and temperature, respectively. The difference in Σ for 0.20 and 0.40 mol/mol CO2 loading is due to the difference in activation energy. Note that surface tension and density of the solution play a minor role in such decreasing trend of Σ. As seen from Figure 12b,c, surface tension and density decrease with an increasing temperature. This implies a lower surface force (reflecting an enhancement of foam formation) and a lower buoyancy force (reflecting a retardation of foam formation). The resulting force may be small or insignificant compared to the influence of solution viscosity described above. 4.6. Degradation Products of MEA. The effect of 13 degradation products on Σ was investigated by using a 5.0 kmol/ m3 aqueous MEA solution containing 0.40 mol/mol CO2 loading at 60 °C. The results in Table 3 indicate that the solutions containing degradation products (except sulfuric acid) provide greater Σ values than those without degradation products. Ammonium thiosulfate induces the highest foam volume and Σ, followed by glycolic acid, sodium sulfite, malonic acid, oxalic acid, sodium thiocyanate, sodium chloride, sodium thiosulfate, bicine, hydrochloric acid, formic acid, acetic acid, and sulfuric acid. The increase in Σ is due to the formation of anionic surfactants in the presence of sulfate (OSO3-), sulfonate (SO3-), and carboxylate (COO-) functioning as a hydrophilic group. The anionic surfactants reduce surface tension of the solution, thus encouraging foam formation. Such surfactants also enhance foam stability by improving surface elasticity due to the Marangoni effect. The results also show that the presence of chloride ion increases Σ. This is probably because the chloride ion reduces surface tension by neutralizing the ionic products

Figure 12. (a) Predicted viscosity of 5.0 kmol/m3 MEA solution from correlation;30 (b) surface tension of 5.0 kmol/m3 unloaded-CO2 MEA solution replotted from experimental data;29 (c) predicted density of 5.0 kmol/m3 MEA solution from correlation.30 Table 2. Arrhenius Parameter for the Effect of Solution Temperature on Σ (MEA Concentration ) 5.0 kmol/m3, N2 Flow Rate ) 2.06 m3/(m2‚h), Solution Volume ) 4.0 × 10-4 m3, and CO2 Loading ) 0.20 and 0.40 mol/mol) CO2 loading (mol/mol)

A

Ea (J/mol)

R2

0.20 0.40

270 511 270 511

32 274 33 780

0.87 0.98

resulting from the reaction between CO2 and MEA, which in turn enhances foam formation. 4.7. Corrosion Inhibitor. The effect of corrosion inhibitors on Σ was studied by adding three corrosion inhibitors (i.e., sodium metavanadate, copper carbonate, and sodium sulfite) with a concentration of 1000 ppm into a 5.0 kmol/m3 aqueous MEA solution containing 0.40 mol/mol CO2 loading. The results in Figure 13 clearly illustrate that sodium metavanadate and copper carbonate increase foam volume or Σ, and of which sodium metavanadate induces a greater effect, whereas sodium sulfite has no apparent effect. This can be explained by considering the surface tension of MEA solutions. As shown in Table 4, the surface tension values of MEA solution are reduced when sodium metavanadate and copper carbonate are added. However, a similar trend is not found for sodium sulfite. 4.8. Alkanolamine Type. Both single and blended alkanolamine solutions were tested for foaming tendency using a 4.0

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008 223 Table 3. Effect of Degradation Products on Foaminess Coefficient (10 000 ppm of Degradation Product, 5.0 kmol/m3 MEA, 2.06 m3/(m2‚h) N2 Flow Rate, 4.0 × 10-4 m3 Solution Volume, 0.40 mol/mol CO2 Loading, and 60 °C) degradation product None amomonium thiosulfate glycolic acid sodium sulfite malonic acid oxalic acid sodium thiocyanate sodium chloride sodium thiosulfate bicine hydrochloric acid formic acid acetic acid sulfuric acid

av foaminess coefficienta (min) 0.79 0.97 0.94 0.92 0.92 0.90 0.90 0.90 0.85 0.85 0.83 0.83 0.82 0.77

a The maximum standard deviation of the foaminess coefficients is (0.05 min.

Table 5. Effect of Alkanolamine Type on Foaminess Coefficient (Total Alkanolamine Concentration ) 4.0 kmol/m3, N2 Flow Rate ) 2.06 m3/(m2‚h), Solution Volume ) 4.0 × 10-4 m3, CO2 Loading ) 0.40 mol/mol, Solution Temperature ) 60 °C, and Mixing Mole Ratios of Blended Solution ) 1:2, 1:1, and 2:1) type of alkanolamine

av foaminess coefficienta (min)

MEA DEA MDEA AMP MEA + MDEA (1:2) MEA + MDEA (1:1) MEA + MDEA (2:1) DEA + MDEA (1:2) DEA + MDEA (1:1) DEA + MDEA (2:1) MEA + AMP (1:2) MEA + AMP (1:1) MEA + AMP (2:1)

0.85 no foam 0.32 no foam no foam no foam no foam no foam no foam no foam no foam no foam 0.13

a The maximum standard deviation of the foaminess coefficients is (0.02 min.

Figure 13. Effect of corrosion inhibitors on foaminess coefficient (corrosion inhibitor ) sodium metavanadate (NaVO3), copper carbonate (CuCO3), and sodium sulfite (Na2SO3); corrosion inhibitor concentration ) 1000 ppm; MEA concentration ) 5.0 kmol/m3; N2 flow rate ) 2.06 m3/(m2‚h); solution volume ) 4.0 × 10-4 m3; CO2 loading ) 0.40 mol/mol; solution temperature ) 60 °C). Table 4. Surface Tension of 5.0 kmol/m3 MEA Solutions Containing No CO2 Loading at 25 °C with/without 1000 ppm Corrosion Inhibitor (measured by Kru1 ss Tensiometer K100 Using the Wihelmy Plate’s Principle) system MEA without corrosion inhibitors MEA + sodium metavanadate MEA + copper carbonate MEA + sodium sulfite

surface tension (mN/m) 61.102 ( 0.022 56.462 ( 0.034 57.669 ( 0.055 58.633 ( 0.015 60.246 ( 0.014 62.510 ( 0.011 62.505 ( 0.007

kmol/m3 total alkanolamine concentration containing 0.40 mol/ mol CO2 loading at 60 °C. The results for single alkanolamine solutions show that foam formation occurs in MEA and MDEA but not in DEA and AMP solutions (Table 5). This implies that the surface force (represented by surface tension in Figure 14a) is overcome by the buoyancy force (represented by density in Figure 14b), and consequently bubbles are produced at the diffuser in the MEA and MDEA systems. Σ of MEA solution is approximately 2.5 times that of MDEA solution since the rising bubbles in MEA solution are easier to cream and form a layer of foam than those in MDEA solutions due to the lower solution viscosity of MEA solution than that of MDEA solution (Figure 14c). From the observation, DEA and AMP solutions do not foam. It can be possibly explained by a high bulk

Figure 14. (a) Surface tension of CO2-unloaded aqueous alkanolamine solution at 40 °C replotted from experimental data;29,32,33 (b) density of CO2-unloaded aqueous alkanolamine solution at 60 °C replotted from experimental data;34-36 (c) viscosity of CO2-unloaded aqueous alkanolamine solution at 60 °C replotted from experimental data.36-38

viscosity that could stop the bubbles from rising. Note that, in spite of its high viscosity, the MDEA solution may have foamed due to CO2 stripping as observed from the decrease in CO2

224

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008

• Physical properties, particularly surface tension, density, and viscosity of solution, play a significant role in foaming tendency through foam formation and foam stability. These properties should be used for development of strategy for foaming control. Acknowledgment The Natural Sciences and Engineering Research Council of Canada (NSERC) is gratefully acknowledged for generous financial support. Literature Cited

Figure 15. (a) Surface tension of CO2-unloaded aqueous blended alkanolamine solutions at 60 °C replotted from experimental data: MEA + MDEA,33 DEA + MDEA,33 and MEA + AMP;29 (b) predicted viscosity of CO2-unloaded aqueous blended alkanolamine solution with 4.0 kmol/ m3 total concentration at 60 °C from Grunberg and Nissan’s equation.39

loading of MDEA solution from 0.40 to 0.27 mol/mol during the experiment. For the blended alkanolamine solutions, only the MEA + AMP solution at a mixing mole ratio of 2:1 has a potential to create foam, whereas MEA + MDEA and DEA + MDEA solutions produce virtually no foam or only trace amounts at any mixing ratio. This is because the surface tension of MEA + AMP is lower than that of MEA + MDEA and DEA + MDEA at any mixing ratio (Figure 15a), and also because MEA + AMP (Figure 15b) has the lowest bulk viscosity compared to the other blended solutions. 5. Conclusions Foaming behavior in an alkanolamine-based CO2 absorption process is influenced by process parameters as summarized below. • Solution volume affects foam tendency when it is small. Increasing the solution volume to a certain quantity results in a constant foaminess coefficient. • An increase in gas flow rate decreases foaminess coefficient. The gas flow rate can lead to a constant foaminess coefficient when increased to a certain value. • Variations in MEA concentration, CO2 loading, and solution temperature affect foaming tendency. Solution temperature is the most influential. An increase in temperature decreases foaminess coefficient. The foaminess coefficient increases and then declines with increasing MEA concentration and CO2 loading. • MEA, MDEA, and MEA + AMP (2:1 mixing mole ratio) generate apparent foams, while DEA, AMP, MEA + MDEA, DEA + MDEA and MEA + AMP (1:1 and 1:2) do not. • Most degradation products and corrosion inhibitors in aqueous MEA solutions enhance foaminess coefficient, except sulfuric acid.

(1) Ballard, D. How to Operate an Amine Plant. Hydrocarbon Process. 1966, 45 (4), 137-144. (2) Ballard, D. Techniques to Cut Energy/Corrosion/Chemical Costs in Amine Units. Proceedings of Laurance Reid Gas Conditioning Conference, 36th Annual; University of Oklahoma: Norman, OK, 1986; pp A1-A38. (3) Smith, R. F. Curing Foam Problems in Gas Processing Solutions. Oil Gas J. 1979 77 (31), 186-192. (4) Liebermann, N. P. Amine Appearance Signals Condition of System. Oil Gas J. 1980 78 (19), 115-120. (5) Keaton, M. M.; Bourke, M. J. Activated Carbon System Cuts Foaming and Amine Losses. Hydrocarbon Process. 1983, 62 (8), 71-73. (6) Thomason, J. Reclaim Gas Treating Solvent. Hydrocarbon Process. 1985, 64 (4), 75-78. (7) Pauley, C. R. Face the Facts about Amine Foaming. Chem. Eng. Prog. 1991, 87 (7), 33-38. (8) Stewart, E. J.; Lanning, R. A. Reduce Amine Plant Solvent Losses Part 1. Hydrocarbon Process. 1994, 73 (5), 67-81. (9) Abdi, M A; Golkar, M. M.; Meisen, A. Improve Contaminant Control in Amine Systems. Hydrocarbon Process. 2001, 80 (10), 102C-102I. (10) Pauley, C. R.; Hashemi, R.; Caothien, S. Ways to Control Amine Unit Foaming Offered. Oil Gas J. 1989, 87 (50), 67-75. (11) McCarthy, J.; Trebble, M. A. An Experimental Investigation into the Foaming Tendency of Diethanolamine Gas Sweetening Solutions. Chem. Eng. Commun. 1996, 144, 159-171. (12) Harruff, L. G. Saudi Arabian Experience with DGA Units and Related Sulfur Plants. Proceedings of Laurance Reid Gas Conditioning Conference, 48th Annual; University of Oklahoma: Norman, OK, 1998; pp 76-98. (13) Schramm, L. L. Foams: Fundamentals and Applications in the Petroleum Industry; American Chemical Society: Washington, D.C., 1994. (14) Thiele, R.; Brettschneider, O.; Repke, J.-U.; Thielert, H.; Wozny, G. Experimental Investigations of Foaming in a Packed Tower for Sour Water Stripping. Ind. Eng. Chem. Res. 2003, 42, 1426-1432. (15) Hartland, S. Surface and Interfacial Tension: Measurement, Theory, and Applications; Marcel Dekker, Inc.: New York, 2004. (16) Wilson, A. Foams: Physics, Chemistry and Structure; SpringerVerlag: London, Great Britain, 1989. (17) Rosen, M. J Surfactants and Interfacial Phenomena; John Wiley & Sons: New York, 1989. (18) Morrison, I. D.; Ross, S. Colloidal Dispersions: Suspensions, Emulsions, and Foams; John Wiley & Sons: New York, 2002. (19) American Society for Testing and Materials (ASTM). ASTM D892Standard Test Method for Foaming Characteristics of Lubricating Oil; ASTM: West Conshohocken, PA, 1999. (20) Horowitz, W. Association of Official Analytical Chemists (AOAC) Methods; George Banta: Washington, D.C., 1975. (21) Bikerman, J. J. Foams; Springer-Verlag: New York, 1973. (22) Kohl, A. L.; Nielsen, R. B. Gas Purification, 5th ed.; Gulf Publishing Co.: Houston, TX, 1997. (23) Rooney, P. C.; DuPart, M. S. Corrosion in Alkanolamine Plants: Causes and Minimization. Proceedings of Corrosion 2000; NACE International: Houston, TX, 2000; Paper No. 494. (24) Liu, H. J.; Dean, J. W.; Bosen, S. F. Neutralization Technology to Reduce Corrosion from Heat-Stable Amine Salts. Proceedings of Corrosion 95; NACE International: Orlando, FL, 1995; Paper No. 572. (25) Craig, L. H., Jr.; McLaughlin, B. D. Corrosive Amine Characterization. Proceedings of Corrosion 96; NACE International: Houston, TX, 1996; Paper No. 394. (26) Litchewski, M. J. More Experiences with Corrosion and Fouling in Refinery Amine Systems. Proceedings of Corrosion 96; NACE International: Houston, TX, 1996; Paper No. 391. (27) Rooney, P. C.; Bacon, T. R.; DuPart, M. S. Effect of Heat Stable Salts on Solution Corrosivity of MDEA-Based Alkanolamine Plants. Part

Ind. Eng. Chem. Res., Vol. 47, No. 1, 2008 225 III. Proceedings of Laurance Reid Gas Conditioning Conference, 47th Annual; University of Oklahoma: Norman, OK, 1997; pp 12-30. (28) Fan, D.; Kolp, L.; Huett, D. S.; Sargent, M. A. Role of Impurities and H2S in Refinery Lean DEA System Corrosion. Proceedings of Corrosion 2000; NACE International: Houston, TX, 2000; Paper No. 495. (29) Va´zquez, G.; Alvarez, E.; Navaza, J. M.; Rendo, R.; Romero, E. Surface Tension of Binary Mixtures of Water + Monoethanolamine and Water + 2-Amino-2-methyl-1-propanol and Tertiary Mixtures of These Amines with Water from 25 °C to 50 °C. J. Chem. Eng. Data 1997, 42, 57-59. (30) Weiland, R. H.; Dingman, J. C.; Cronin, D. B.; Browning, G. J. Density and Viscosity of Some Partially Carbonated Aqueous Alkanolamine Solutions and Their Blends. J. Chem. Eng. Data 1998, 403, 378-382. (31) Danckwerts, P. V.; Tavares da Silva, A. Surface Instability During the Absorption of Carbon Dioxide by Monoethanolamine Solutions. Chem. Eng. Sci. 1967, 22 (11), 1513-1514. (32) Va´zquez, G.; Alvarez, E.; Rendo, R.; Romero, E.; Navaza, J. M. Surface Tension of Aqueous Solutions of Diethanolamine and Triethanolamine from 25 °C to 50 °C. J. Chem. Eng. Data 1996, 41, 806-808. (33) Alvaraz, E.; Rendo, R.; Sanjurjo, B.; Sa´nchez-Vilas, M.; Navaza, J. M. Surface Tension of Binary Mixtures of Water + N-Methyldiethanolamine and Tertiary Mixtures of This Amine and Water with Monoethanolamine, Diethanolamine, and 2-Amino-2-methyl-1-propanol from 25 to 50 °C. J. Chem. Eng. Data 1998, 43, 1027-1029. (34) Maham, Y.; Teng, T. T.; Hepler, L. G.; Mather, A. E. Densities, Excess Molar Volumes, and Partial Molar Volumes for Binary Mixtures

of Water with Monoethanolamine, Diethanolamine, and Triethanolamine from 25 to 80 °C. J. Solution Chem. 1994, 23 (2), 195-205. (35) Maham, Y.; Teng, T. T.; Mather, A. E.; Hepler, L. G. Volumetric Properties of (Water + Diethanolamine) Systems. Can. J. Chem. 1995, 73 (9), 1514-1519. (36) Henni, A.; Hromek, J. J.; Tontiwachwuthikul, P.; Chakma, A. Volumetric Properties and Viscosities for Aqueous AMP Solutions from 25 °C to 70 °C. J. Chem. Eng. Data 2003, 48, 551-556. (37) Maham, Y.; Liew, C.-N.; Mather, A. E. Viscosities and Excess Properties of Aqueous Solutions of Ethanolamines from 25 to 80 °C. J. Solution Chem. 2002, 31 (9), 743-756. (38) Teng, T. T.; Maham, Y.; Hepler, L. G.; Mather, A. E. Viscosity of Aqueous Solutions of N-Methyldiethanolamine and of Diethanolamine. J. Chem. Eng. Data 1994, 39, 290-293. (39) Mandal, B. P.; Kundu, M.; Bandyopadhyay, S. S. Density and Viscosity of Aqueous Solutions of (N-Methyldiethanolamine + Monoethanolamine), (N-Methyldiethanolamine + Diethanolamine), (2-Amino2-methyl-1-propanol + Monoethanolamine), and (2-Amino-2-methyl1-propanol + Diethanolamine). J. Chem. Eng. Data 2003, 48, 703707.

ReceiVed for reView March 11, 2007 ReVised manuscript receiVed September 19, 2007 Accepted October 3, 2007 IE070366L