Scholarly article on topic 'Advancement and new perspectives of using formulated reactive amine blends for post-combustion carbon dioxide (CO2) capture technologies'

Advancement and new perspectives of using formulated reactive amine blends for post-combustion carbon dioxide (CO2) capture technologies Academic research paper on "Chemical engineering"

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{Post–combustion / Pre–combustion / "Oxy–fuel combustion" / "CO2 capture" / "Blended amines" / "Regeneration energy" / Degradation / "Amine volatility" / Biodegradability / Ecotoxicity / "Amine cost" / "Reclaiming energy"}

Abstract of research paper on Chemical engineering, author of scientific article — Chikezie Nwaoha, Teeradet Supap, Raphael Idem, Chintana Saiwan, Paitoon Tontiwachwuthikul, et al.

Abstract Chemical absorption using amine–based solvents have proven to be the most studied, as well as the most reliable and efficient technology for capturing carbon dioxide (CO2) from exhaust gas streams and synthesis gas in all combustion and industrial processes. The application of single amine–based solvents especially the very reactive monoethanolamine (MEA) is associated with a parasitic energy demand for solvent regeneration. Since regeneration energy accounts for up to three–quarters of the plant operating cost, efforts in its reduction have prompted the idea of using blended amine solvents. This review paper highlights the success achieved in blending amine solvents and the recent and future technologies aimed at increasing the overall volumetric mass transfer coefficient, absorption rate, cyclic capacity and greatly minimizing both degradation and the energy for solvent regeneration. The importance of amine biodegradability (BOD) and low ecotoxicity as well as low amine volatility is also highlighted. Costs and energy penalty indices that influences the capital and operating costs of CO2 capture process was also highlighted. A new experimental method for simultaneously estimating amine cost, degradation rate, regeneration energy and reclaiming energy is also proposed in this review paper.

Academic research paper on topic "Advancement and new perspectives of using formulated reactive amine blends for post-combustion carbon dioxide (CO2) capture technologies"

Petroleum xxx (2016) 1-27

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ADVANCING RESEARCH EVOLVING SCIENCE

Petroleum

journal homepage: www.keaipublishing.com/en/journals/petlm

Advancement and new perspectives of using formulated reactive amine blends for post-combustion carbon dioxide (CO2) capture technologies

Chikezie Nwaoha a' b *, Teeradet Supap a' **, Raphael Idem a, b, ***, Chintana Saiwan a, b, Paitoon Tontiwachwuthikul a, b, c, Mohammed J. AL-Marric, Abdelbaki Benamor c

a Clean Energy Technologies Research Institute (CETRI), Faculty of Engineering and Applied Science, University ofRegina, SK, S4S 0A2, Canada b The Petroleum and Petrochemical College, Chulalongkorn University, Bangkok, 10330, Thailand c Gas Processing Center, Qatar University, Doha, Qatar

ARTICLE INFO

Article history:

Received 27 September 2016 Received in revised form

27 October 2016

Accepted 9 November 2016

Keywords: Post—combustion Pre—combustion Oxy—fuel combustion CO2 capture Blended amines Regeneration energy Degradation Amine volatility Biodegradability Ecotoxicity Amine cost Reclaiming energy

ABSTRACT

Chemical absorption using amine—based solvents have proven to be the most studied, as well as the most reliable and efficient technology for capturing carbon dioxide (CO2) from exhaust gas streams and synthesis gas in all combustion and industrial processes. The application of single amine—based solvents especially the very reactive monoethanolamine (MEA) is associated with a parasitic energy demand for solvent regeneration. Since regeneration energy accounts for up to three—quarters of the plant operating cost, efforts in its reduction have prompted the idea of using blended amine solvents. This review paper highlights the success achieved in blending amine solvents and the recent and future technologies aimed at increasing the overall volumetric mass transfer coefficient, absorption rate, cyclic capacity and greatly minimizing both degradation and the energy for solvent regeneration. The importance of amine biodegradability (BOD) and low ecotoxicity as well as low amine volatility is also highlighted. Costs and energy penalty indices that influences the capital and operating costs of CO2 capture process was also highlighted. A new experimental method for simultaneously estimating amine cost, degradation rate, regeneration energy and reclaiming energy is also proposed in this review paper.

Copyright © 2016, Southwest Petroleum University. Production and hosting by Elsevier B.V. on behalf of KeAi Communications Co., Ltd. This is an open access article under the CC BY-NC-ND

license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

Contents

Introduction................................................................................................................. 00

1.1. Post—combustion CO2 capture.............................................................................................00

1.2. Pre—combustion CO2 capture.............................................................................................00

1.3. Oxy—fuel combustion CO2 capture.........................................................................................00

CO2 capture using blended amine solvents....................................................................................... 00

2.1. Single phase blended amine solution......................................................................................00

* Corresponding author. Clean Energy Technologies Research Institute - CETRI, University of Regina, Canada. ** Corresponding author. Clean Energy Technologies Research Institute - CETRI, University of Regina, Canada. *** Corresponding author. Clean Energy Technologies Research Institute - CETRI, University of Regina, Canada.

E-mail addresses: nwaoha2c@uregina.ca, chikezienwaoha@live.co.uk (C. Nwaoha), Teeradet.Supap@uregina.ca (T. Supap), Raphael.Idem@uregina.ca (R. Idem). Peer review under responsibility of Southwest Petroleum University.

http://dx.doi.org/10.1016/j.petlm.2016.11.002

2405-6561/Copyright © 2016, Southwest Petroleum University. Production and hosting by Elsevier B.V. on behalf of KeAi Communications Co., Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

2 C. Nwaoha et al. / Petroleum xxx (2016) 1—27

2.1.1. Bi—solvent blends ...............................................................................................00

2.1.2. Tri—solvent blends...............................................................................................00

2.1.3. Quad-solvent blends.............................................................................................00

2.2. Phase—split blended aqueous amine solution ...............................................................................00

3. Blended amine solution: performance criteria and optimization.................................................................... 00

3.1. Absorption rate and absorption capacity....................................................................................00

3.2. Desorption rate..........................................................................................................00

3.3. Cyclic loading and cyclic capacity ........................................................................................00

3.4. Mass transfer ...........................................................................................................00

3.5. Absorption heat.........................................................................................................00

3.6. Regeneration energy.....................................................................................................00

3.7. Amine stability..........................................................................................................00

3.8. Amine volatility and emissions...........................................................................................00

3.9. Relative cost of CO2 capture...............................................................................................00

3.9.1. Total equivalent work ............................................................................................00

3.9.2. Amine reclaiming energy.........................................................................................00

3.9.3. Amine cost .....................................................................................................00

3.9.4. Amine make—up cost.............................................................................................00

3.10. Proposed experimental set—Up for amine solvent analysis...................................................................00

3.10.1. Experimental procedure .........................................................................................00

4. Conclusions ................................................................................................................. 00

Acknowledgement............................................................................................................00

References....................................................................................................................00

1. Introduction

The capture of carbon dioxide (CO2) has taken the center stage globally due to the increasing adverse effects of CO2 emissions. These emissions are generated from anthropogenic activities during the utilization of fossil fuels for electric power generation, transportation, as well as for heating/cooling purposes in residential and office buildings. According to the International Energy Agency, based on total global emissions in 2013, coal and crude oil emitted the most CO2 when compared to natural gas (coal > crude oil > natural gas) [1]. Also, through the use of these fossil fuels, the generation of electricity was the sector that generated the most CO2 emissions. Due to the relatively cheap cost and global availability, coal specifically will most likely be the preferred fossil fuel for electricity production in the coming decades [2], thereby constituting the highest source of CO2 emissions. Hence, it is imperative to capture the CO2 from such fossil fuel power generation plants to limit its adverse effects. The process of combusting fossil fuels for electric power generation and removing CO2 afterwards before releasing the exhaust gas can be classified into post—combustion, pre—combustion and oxy—fuel combustion CO2 capture. In terms

of industry and commercially applied and mostly studied, they can be ranked as follows

post—combustion > pre—combustion > oxy—fuel combustion.

1.1. Post—combustion CO2 capture

In the post—combustion CO2 capture, the flue gas (containing CO2) is produced from combusting fossil fuels (coal or natural gas) with air for power generation as seen in Eq. (1) [3]. The flue gas CO2 concentration from this combustion process is usually between 10 and 15% for coal fired power plants and 3—8% for natural gas fired power plants [4—9]. The second step is the capture of CO2 from the flue gas produced. Fig. 1 displays post—combustion CO2 capture process.

CxHy + z(O2 + 3.76N2)/aCO2 + bH2O + cO2 + dN2 (1)

'z' is the stoichiometric coefficient of air. The stoichiometric coefficients of the products (a, b, c, d) will depend on those of the reactants (x, y, z).

The combustion reaction in Eq. (1) produces mainly nitrogen (N2), CO2, water (H2O), and unreacted oxygen (O2). However, due

Liquid Hydrocarbon/ Coal/

Fig. 1. Integrated post—combustion CO2 capture process.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

Fig. 2. Integrated pre—combustion CO2 capture process.

Fig. 3. Oxy—fuel combustion with CO2 separation.

to impurities in the fossil fuel (coal and natural gas), other unwanted gases are produced (SOx, NOx, fly ash, metals etc.). These impurities and O2 often lead to amine solvent degradation [10—15]. Therefore, these impurities must be removed (flue gas conditioning) to very low concentrations before capturing CO2 as shown in Fig. 1. The CO2 capture efficiency is usually targeted at 90% [16—18]. The capture of CO2 is also driven by the advancements in CO2 utilization routes like CO2 to gaseous and liquid fuels, CO2 to chemicals and polymers and CO2 for enhanced oil recovery [19—27].

1.2. Pre—combustion CO2 capture

In this process the CO2 is captured before combusting the fuel. This technology (also known as integrated gasification combined cycle, IGCC) involves the gasification of fossil fuels with air and/ or steam to produce syngas [28—31]. The syngas can contain about 5—15% CO2 depending on the chemical composition of the fuel source [32,33]. This process can produce both gaseous product (hydrogen, H2 and CO2) and liquid products (gas to liquid, methanol, dimethylether etc.). The dotted process lines in Fig. 2 depict the process where the syngas which contains predominantly carbon monoxide (CO) and H2 goes through a catalytic water—gas shift reactor. At this stage most of the CO is converted to CO2 while more H2 is produced. The CO2 concentration after the water—gas shift reactor can be as high as 40—42% [34—36]. The mixed gas (predominantly H2 and CO2) exiting the water—gas shift reactor then goes to a CO2 capture unit where highly pure H2 is produced. This suggests that pre—combustion process with integrated carbon capture can

produce pure H2 and also reduce CO2 emissions [37—40]. The produced H2 can then be used for electricity generation and as vehicle fuel [9,41,42]. The produced CO2 will also have similar market as shown in Fig. 1. The advantage of this process is that its high CO2 concentrations (in the syngas) and high pressure of the syngas will make CO2 capture less expensive when compared with post-combustion CO2 capture where the flue gas is at atmospheric pressure [9,36]. Possible impurities in the produced syngas (NOx, particulate matter) are removed during the syngas conditioning.

In the straight line route of Fig. 2, the conditioned syngas (CO + H2 + CO2) is first sent to a CO2 capture unit to remove all CO2 and other undesired gaseous components. The clean syngas is then routed to the Fischer—Tropsch reactor (F—T reactor) where it is catalytically converted to synthetic liquid fuels [31,43—46]. The integration of a CO2 capture unit upstream of the F—T reactor will help improve the efficiency of the process and also produce cleaner liquid fuels. The challenge with this route is that some of the desired H2 and CO which is the main components for the F—T process could be co—absorbed with CO2 in the CO2 capture unit. Since the conversion and selectivity of the F—T reactor is sensitive to the CO/H2 ratio, this will hence reduce the efficiency of the F—T reactor.

1.3. Oxy—fuel combustion CO2 capture

This process is another promising technology for CO2 capture and it is currently being studied. The idea is to increase the efficiency of the combustion while producing high CO2 concentration that will be easy to separate. This is achieved by

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

Fig. 4. Selection and optimization of amine solvent blend for post-combustion CO2 capture process.

combusting the fuel with near pure oxygen (O2) instead of air (Fig. 3). The CO2 concentration in the flue gas can be as high as 70—95% which will also depend on the type of fuel and process used and also O2 purity [9—36]. The high CO2 concentration and components of the flue gas (CO2 + H2O) means that condensation or liquefaction technology can be used to separate the CO2. An advantage of this technology is that the low flow rate of the flue gas (no N2) will lead to smaller size and reduced capital cost of the CO2 capture unit. It can also be argued that the addition of an expensive air separation unit will increase the capital cost of the entire plant when compared to other technologies. Another important merit of this technology is that NOx content of the flue gas is reduced by 60—70% (due to the use of O2 instead of air) compared to other processes [36]. The amine carryover in the absorber is also expected to reduce drastically due to the reduced flue gas flow rate.

In all combustion processes that require CO2 capture, the separation of CO2 can be achieved by various techniques including absorption, adsorption, membrane and cryogenic processes. However, CO2 absorption using amine—based chemical solvent has attracted the most attention due to its maturity, cost—effectiveness and ability to handle large volumes of flue gas streams [17,47—50].

The most commonly used amine—based solvents are primary monoamines (e.g. monoethanolamine (MEA) and diglycolamine (DGA)), secondary monoamines (diethanolamine (DEA) and diisopropanolamine (DIPA)), and tertiary monoamines (methyl-diethanolamine (MDEA) and triethanolamine (TEA)). Other types of amine used often include primary sterically hindered monoamines (e.g. 2—amino—2—methyl—1—propanol (AMP)) and polyamines like piperazine (PZ), diethylenetriamine (DETA), aminoethylethanolamine (AEEA), methylaminopropylamine (MAPA), diethylenetriamine (DETA), triethylenetetramine (TETA), tetraethylenepentamine (TEPA) [47,51—57]. Besides these common amines, several other amine solvents that are available

Fig. 5. Current and Potential CO2 Capture Technologies using Chemical Absorption Process.

commercially but have not been previously tested for CO2 capture purposes have recently been experimentally studied to evaluate their potentials in CO2 capture application [58—66]. In addition, novel amine solvents have been constantly synthesized to ascertain their capability in CO2 capture [67—71 ].

Specifically, the desired properties of the amine based solvent include fast kinetics and absorption—desorption rate, high mass transfer rate, absorption capacity, high cyclic loading and cyclic capacity, minimal amine losses due to degradation and volatility, less corrosivity, and most importantly low energy penalty for solvent regeneration [57,72—77]. Due to fast reaction rate, high mass transfer and ability to reach 90% CO2 capture efficiency, low chemical cost, and ability to capture CO2 at low pressure (atmospheric pressure) flue gases, MEA is often regarded as the standard amine solvent for CO2 capture [16—18,78,79]. However, there is a major draw-back which limits the potential in using MEA in the capture process. This limitation is the high energy for regeneration of MEA, which could be as high as 3.3—4.4 GJ/ton CO2 [80—83]. It has been reported that the amount of regeneration energy could account for 70—80% of the entire operating cost of CO2 capture plants [84,85].

In recent times, polyamines which have been discovered to have a very good CO2 absorption capacity, high mass transfer and high reaction kinetics (attributed mainly to the presence of multiple amino groups) is being used as a promoter/activator in high absorption capacity solvents (e.g. bicarbonate forming solvents) like tertiary amines or sterically hindered amines to enhance their CO2 capture efficiency [86—96]. Fig. 4 displays a good insight on the optimization strategy when selecting amine solvents for a blended system. Though there is a minor misconception that polyamines are used as rate promoters, it is also important to highlight that the polyamines usually used for enhancing amine—CO2 kinetics are polyamines that contain primary and/or secondary amino groups. This implies that polyamines containing only tertiary amino groups will not be used as rate promoters due to their slow CO2 absorption pathway [97].

This application of bi—solvent blends was first recommended by Chakravarty et al. who proposed possible benefits of blending

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

two amine solvents to maximize the potentials of the individual amine solvents while minimizing their weaknesses [98]. Other researchers [84,87,88,99—103] also confirmed the success of blending primary or secondary amines with tertiary or hindered amines (bi—solvent blends) to range from increased rate of absorption, cyclic capacity and cyclic loading, high amine solution concentration, minimized corrosion, and most importantly reduction in regeneration energy. Fig. 5 displays current and potential CO2 capture technologies using chemical solvents. Freeman et al. also confirmed that significant enhancement in the thermodynamic efficiency of blended amine solvents can be attained by increasing its amine concentration [51]. However, it is also essential to state that a continuous increase of amine solution concentration could become counter—productive and lead to significant increase in viscosity, decreased heat and mass transfer, an increase in pump work, increased degradation and corrosion, and foaming [75,102,104—108]. High concentration of aqueous amine solution can be considered to be between 4 and 5 kmol/m3, and above this can be termed as being highly concentrated.

Sakwattanapong et al. affirmed that the concentration of the individual solvents can also determine the benefits of bi—solvent blend for CO2 capture [100]. Based on this work, the reboiler heat duty (regeneration energy) of MEA decreased when the concentration of both AMP (in MEA—AMP) and MDEA, respectively in MEA—AMP and MEA—MDEA increased in the bi—solvent blends. Similar trend was noticed as both the equilibrium CO2 loading and cyclic loading (mol CO2/mol amine) of 3 kmol/m3 AMP—1.5 kmol/m3 PZ were higher than that of 4 kmol/m3 AMP—1 kmol/m3 PZ [88]. Veawab et al. previously studied the bi—solvent blends between MEA, DEA and MDEA and discovered that their absorption performance and regeneration energies were between that of their parent amines but discovered later by Aroonwilas and Veawab that this relationship was not always linear [109,110]. Therefore, the selection of the individual amines and their concentrations in the aqueous blend should be carefully studied and analysed to enhance the optimal performance of the solvent for CO2 capture (Figs. 4 and 5). The success of bi—solvent blends has been gradually leading to development of tri—solvent and quad—solvent blends as previously and recently investigated [111—116].

This review paper focused on the past success achieved in blending amine solvents and the recent and future technologies aimed at increasing the cyclic capacity, absorption rate, overall volumetric mass transfer coefficient, and greatly reduce both degradation and the energy for solvent regeneration. The importance of amine biodegradability and low ecotoxicity as well as low amine volatility is also highlighted. Cost and energy penalty indices that contribute to the capital and operating costs of CO2 capture process was also extensively discussed and proposed in this paper. New semi—batch experimental method for estimating the reclaiming energy, regeneration energy,

degradation rate and cost of amine solvents is proposed in this review paper.

2. CO2 capture using blended amine solvents

The capture of CO2 from a combustion process using blended amine solvents has been widely studied in laboratory scale and pilot plant tests [84,106,111,117—119]. More recently in Saskatchewan, Canada, the application of CANSOLV based blended amine solvent technology has been used industrially in the commercial scale within the world's first carbon capture plant integrated large scale power plant (110 MW Boundary Dam power plant) [120,121]. High absorption capacity (AC) and bicarbonate (HCO3) forming solvents like tertiary and sterically hindered amines have been promoted using reactive mono-amines (e.g. primary and secondary) and/or polyamines as stated previously. This allows the possibility of achieving high absorption capacity, cyclic loading and cyclic capacity, increased absorption rate, low energy for solvent regeneration, reduced corrosion and degradation, and use of high amine solution concentration without inducing precipitation. From the standpoint of utilizing high amine solution concentration, it is associated to high absorption capacity (mol CO2/L-amine soln.) which is a more reliable parameter than the equilibrium CO2 loading (mol CO2/mol amine). This is because absorption capacity takes into account both the equilibrium CO2 loading and the amine concentration as shown in Eq. (2) [111].

AC = aCO

Fig. 6. Typical process flow diagram of CO2 capture using amine based solvents.

where aCO2rjch is the equilibrium CO2 loading (mol CO2/mol amine) and Camine is the aqueous amine concentration (mol/L of solution).

Previous studies confirmed that increasing amine solution concentration increases absorption capacity in mol CO2/L-amine solution basis [87,101,105,112,113]. As previously mentioned, it is important to note that the continuous increase of the amine solution concentration could lead to decreased heat and mass transfer, increased degradation, significant increase in viscosity, an increase in pump work, and corrosion, and foaming [75,102,104,105,107,108]. Therefore, to avoid such problems for any blended amine systems, the optimal blend ratio and concentration should be ascertained. Blended amine solutions after capturing CO2 can be classified as single phase or phase—split systems. This is in relation to their phase after reaching equilibrium or near equilibrium with CO2.

2.1. Single phase blended amine solution

This refers to blended aqueous amine solutions that form a single phase solution after blending the amines, and also maintain the single phase solution after reaching equilibrium in amine—CO2 reaction. This is the most studied and applied process. Fig. 6 (neglecting the dotted process lines) depicts the conventional process configuration of the CO2 capture plant using chemical absorption with single phase blended aqueous amine solution.

In this process system, the clean flue gas counter—currently comes into contact with the CO2 lean aqueous amine solution which is flowing downwards from the absorber (or contactor) top, hence mass transfer of CO2 from the gas phase into the liquid phase takes place. The absorber internals is equipped with either trays or packing's (structured or random) which helps to increase the interfacial contact and mass transfer between the CO2 lean aqueous amine solution and the flue gas. Aroonwilas and

6 C. Nwaoha et al. / Petroleum xxx (2016) 1—27

Tontiwachwuthikul studied the effect the packing on CO2 absorption efficiency, and they discovered that structured packing showed superior performance compared to random packing [122]. The CO2 lean amine/CO2 rich amine exchanger (L/R exchanger) serves as the heat integration of the plant while the stripper (also known as desorber or regenerator) is where the CO2 rich amine is stripped to CO2 lean amine by the use of external heat.

The dotted process line in Fig. 6 is an alternative route which is meant for a high pressure system like CO2 capture in pre—combustion process. The CO2 rich amine solution under high pressure is first sent to a flash tank prior to passing through the lean/rich heat exchanger. This will help step—down the pressure of the CO2 rich amine solution close to the operating pressure of the stripper.

2.1.1. Bi—solvent blends

Bi—solvent blend first proposed by Chakravarty et al. is aimed at maximizing the potentials of the individual amine solvents and also limiting their individual problems [98]. Generally, bi—solvent blends involve mixing of a high CO2 absorption capacity solvent and a highly reactive amine solvent. In most cases, the high CO2 absorption capacity solvent (having an equilibrium CO2 loading of at least 1 mol CO2/mol amine) is either a tertiary or sterically hindered amines because of their ability to form bicarbonates (HCO3) during amine—CO2 reactions. The reactive amine solvent can either be reactive monoamines (primary and/or secondary amine) or polyamines that contain primary and/or secondary amino groups (Fig. 4) which have the tendency of forming stable carbamates while tertiary amines only involve the direct formation of bicarbonates. Sterically hindered amines also involve an initial formation of an unstable carbamate which quickly hydrolyses to bicarbonate. Reactions for primary and secondary amines, tertiary amines, and sterically hindered amines are shown in Eqs. (3)—(6)—(7), respectively [52,123—126].

2.1.1.1. Primary and secondary amines.

2RNH2 + CO2 4RNHCOO3 + RNHJ (3)

2R2NH + CO2 4 R2NCOO3 + R2NH+ (4)

Fig. 7. Precipitation and non-precipitation of CO2 rich solution of the AMP—PZ bi—solvent blends after they were cooled at 20 °C for 200 h.

2.1.1.2. Tertiary amines.

R3N + H2O + CO2/R3NH+ + HCO3 (5)

2.1.1.3. Sterically hindered amines.

2RNH2 + CO2 4 RNHCOO3 + RNH+ (6)

RNHCOO3 + H2 O 4 RNH2 + HCO3 (7)

In a bi—solvent blend containing different types of amines, a combination of their reactions including those shown in Eq. (3)—(7) will occur during the amine—CO2 interaction.

Idem et al. used two pilot plant (coal and natural gas fired) studies to confirmed that the bi—solvent blend of 4 kmol/m3 MEA—1 kmol/m3 MDEA could offer huge reductions in the energy of regeneration compared to single solvent 5 kmol/m3 MEA [84]. Mangalapally and Hasse studied bi—solvent blend of AMP—PZ (CESAR1) and their pilot plant results showed that the CESAR1 solvent required lower liquid flow rates (45%) and regeneration energy (20%) when compared to single solvent MEA [127]. Other researchers have studied various bi—solvent blends like MDEA—PZ and MDEA—DEA who have all reported improved CO2 capture capabilities compared to that of MEA [128—135]. Bi—solvent blends containing AMP have also shown to be a potential alternative to single solvent MEA [87,91,133,136—138]. Bruder et al. stated that the bi—solvent blend of 3 kmol/m3 AMP—1.5 kmol/m3 PZ showed higher cyclic capacity (120%) than 5 kmol/m3 MEA [88]. However, precaution must be taken with AMP—PZ blend due to precipitation problem potentially triggered by use of high amine concentration and high CO2 loading. Bruder also reported that bi—solvent blends involving high concentration of AMP—PZ could form solid precipitate and experimentally confirmed it when several concentrations of AMP—PZ formed solid precipitates with and without CO2 loading [88,105].

It is also important to note that the concentration of blended amine solvents is more difficult to control than the single solvents. This is because, in the make—up unit as seen in Fig. 6, adding disproportionate amount of water and/or amine will affect the concentration of the individual amine solvents in the aqueous amine solution, which thereby reduces the CO2 capture efficiency. The 90% CO2 capture efficiency depends on the optimal concentration of the aqueous amine solution [17]. For instance, an in—house experimental study carried out on 3 kmol/ m3 AMP—1.5 kmol/m3 PZ, 3 kmol/m3 AMP—2 kmol/m3 PZ and 3.5 kmol/m3 AMP—1.5 kmol/m3 PZ at 40 °C, atmospheric pressure and 99.99% CO2 confirmed that both aqueous amine solutions did not form any solid precipitate after reaching amine—CO2 equilibrium. However, based on visual inspection alone it is speculated that 3 kmol/m3 AMP—2 kmol/m3 PZ and 3.5 kmol/m3 AMP—1.5 kmol/m3 PZ still looked more viscous (sticky) which implied that precipitation could potentially take place, possibly after further use of the solvent. Upon cooling the three solutions at 20 °C for 200 h, as shown in Fig. 7, a solid precipitate was noticed in both 3 kmol/m3 AMP — 2 kmol/m3 PZ and 3.5 kmol/m3 AMP—1.5 kmol/m3 PZ blends. Their CO2 absorption capacity also followed this trend 3 kmol/m3 AMP—2 kmol/m3 PZ > 3.5 kmol/m3 AMP—1.5 kmol/m3 PZ > 3 kmol/m3 AMP—1.5 kmol/m3 PZ. This indicates that slight increase in the amine concentration can change the amine properties and CO2 capture efficiency of the amine solution which in particular, could lead to precipitation. Amine solution precipitation is very undesirable in a non—precipitating CO2 capture process because

it can plug process lines and equipment as well as increase corrosion.

However, there are studies that have reported precipitating CO2 capture process [139,140]. This involved the application of amino acid based absorbent which claimed to reduce the solvent regeneration energy. However, concerns' regarding modification of the absorber, pumps, regenerator and other equipment's to handle solid or slurry formed due to reaction of the solvent and CO2 still exist which can be a big burden to those who want to switch to the precipitating process. These can impact on the overall operating cost and complexity of the CO2 capture plant. Further studies need to investigate the viability of using precipitating amino acids for CO2 capture.

2.1.2. Tri—solvent blends

It is believed that the success of bi—solvent blends will gradually lead to the application of tri—solvent blends. This invention is aimed at further utilizing the benefits of the individual solvents in tri—solvent blends to enhance CO2 capture efficiency and suppress the individual problems accompanying each solvent.

Tri—solvent blends containing AMP—PZ—DIPA (diisopropa-nolamine) was investigated by Haghtalab et al. at high pressures (1—40 bar) and temperature from 40 to 70 °C [114]. Their result showed that AMP—PZ blend used as a promoter for DIPA increased its CO2 loading. Freeman et al. reported increase in CO2 absorption capacity and absorption rate with new tri—solvent blends containing PZ, N-methylpiperazine (MPZ) and N,N'-dimethylpiperazine (DMPZ) when compared to both PZ and MEA [141 ]. More recently, Liu et al. confirmed that the CO2 desorption time of aqueous solutions of 7 wt% MEA—3 wt.% MDEA reduced by adding 1 wt% AMP (7 wt% MEA—3 wt.% MDEA—1 wt.% AMP) [116].

Nwaoha analysed highly concentrated (6—7 kmol/m3) tri—solvent blend of AMP—PZ—MEA at 93.93 kPa CO2 partial pressure and 40 °C absorption temperature [112,113]. The high CO2 partial pressure was chosen in order to facilitate precipitation which was triggered at high CO2 loadings and high amine concentration. It was confirmed from Fig. 8 that none of the highly concentrated tri—solvent blends formed any solid precipitate when their CO2 rich solutions (40 °C absorption temperature and 93.93 kPa CO2 partial pressure) was cooled at 20 °C for over 400 h. In addition, also shown in Fig. 8, as the concentration of the tri—solvent blend (AMP—PZ—MEA) was further increased to 2.5 kmol/m3 AMP—1.5 kmol/m3 PZ—4.5 kmol/m3

MEA, its CO2 rich solution did not precipitate when cooled at 20 °C for over 400 h. Furthermore, the precipitation possibility experienced with high concentrations of AMP—PZ [88,105] can be eliminated by the development of tri—solvent blends [112].

The main idea is to show that tri—solvent blends can accommodate the use of AMP—PZ in a concentrated amine solution without precipitation, unlike in AMP—PZ bi—solvent blend where none of the amine solvent concentration can be high because of possibilities of precipitation.

Also, the highly concentrated tri—solvent blends have higher absorption capacity than those of single MEA and AMP—PZ bi—solvent blends [111,113]. This proves that tri—solvent blends can potentially offer better a CO2 capture capability compared to conventional single and bi—solvent systems.

Nwaoha reported success with tri—solvent blends containing a bicarbonate forming amine (hindered amine, AMP) and two rate promoters (PZ and MEA), other blend configurations such as two bicarbonate forming amines (hindered and/or tertiary amines) and one rate promoter (polyamine) can be formulated as to have a better insight on the optimal configuration [112]. Based on the recommendation, another tri—solvent blend containing AMP—MDEA—DETA was experimentally analysed in which a reduction in regeneration energy of up to 50% when compared to MEA was observed [97]. Their results also revealed that AMP—MDEA—DETA tri—solvent blend can reduce amine circulation rate, minimize amine waste treatment.

This further confirms the flexibility of tri—solvent blends. Another merit of applying this tri—solvent blend is that though at a high total amine concentration, AMP and PZ can be used at low

Fig. 9. Comparison between MEA, bi—solvent, tri—solvent and quad—solvent blends in terms of aCO2 (mol CO2/mol amine) and absorption capacity (AC, mol CO2/ L-amine soln.) at 99.99% CO2,101.3 kPa and 40 °C.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

to moderate concentrations, thereby limiting chances of precipitation associated with them. Additionally, it is worth noting that the more amine solvents in the blend (bi—solvent to tri—solvent) the more difficult it is to control their concentration, but significant success in their CO2 absorption—desorption capability will likely suppress this expected challenge [111].

• blending three bicarbonate forming solvents (sterically hindered and/or tertiary monoamines) and one rate promoter (polyamines).

Further studies will prove the viability of various solvent blend combinations.

2.1.3. Quad-solvent blends

The potential of tri—solvent blends has indicated quad—solvent blends can also prove to be a viable alternative aqueous amine solution, though their study is still very scarce. This combination can further guarantee a high equilibrium CO2 loading and cyclic loading and cyclic capacity with no precipitation and reduced energy of regeneration. Aqueous quad—solvent blends containing MEA, TETA, 2-amino—2—methyl—1—propanediol (AMPD), and (piperazinyll-1)-2-ethylamine (PZEA) has been studied [115]. Based on the pilot plant studies, they confirmed that their novel quad—solvent blends showed less energy of regeneration (25%) and reduced liquid/gas flow rate ratio (27%) compared to 5 kmol/m3 MEA.

An in—house experimental analysis was carried out on the equilibrium CO2 solubility and absorption capacity (40 °C, atmospheric pressure and 99.99% CO2) of a novel quad—solvent blend consisting of AMP, PZ, MEA and DETA [112]. The concentration of each solvent in this novel quad—solvent blend was varied while the total aqueous solution concentration being kept constantly at 5 kmol/m3. The quad—solvent blend concentration was 2 kmol/m3 AMP—0.5 kmol/m3 PZ—1 kmol/m3 DETA—1.5 kmol/m3 MEA and 1.5 kmol/m3 AMP—0.5 kmol/m3 PZ—1.5 kmol/m3 DETA—1.5 kmol/m3 MEA. It was confirmed that the quad—solvent blends showed much higher equilibrium CO2 loading (39.8—45.7%) and absorption capacity (37—43%) compared to those of 5 kmol/m3 MEA. In addition, no precipitation was observed when the CO2 rich solutions of the quad—solvent blends were cooled at 20 °C for 400 h.

It is clear from Fig. 9 that that the absorption capacity of these quad—solvent blends (AMP—PZ—DETA—MEA) is similar to that the AMP—PZ—MEA tri—solvent blends but higher than single solvent MEA and AMP—PZ bi—solvent blend [112,113].

Based on the results of the quad—solvent experimental study, it can be proposed that the application of quad—solvent blends will out—perform both single solvent MEA and bi—solvent blends but are competitive with tri—solvent blends for CO2 capture application. The studied quad—solvent blend developed by our research group comprised of one bicarbonate forming solvent (AMP) and three rate promoters (i.e. PZ, DETA and MEA). This combination can be further modified to improve the blend performance such as;

• blending two bicarbonate forming solvents (sterically hindered and/or tertiary monoamines) and two rate promoters (primary or secondary amines or polyamines).

Fig. 10. Typical process flow diagram of CO2 capture using phase—split amine based solvents.

2.2. Phase—split blended aqueous amine solution

These are blended aqueous amine solvents that form a single phase solution prior to amine—CO2 reactions, but separate into two immiscible liquid phases during or after reaching equilibrium with amine—CO2 reactions. Phase—split amine solutions are also known as phase—change solvent or bi—phasic solvent. These two phases are usually termed CO2 lean and CO2 rich phases, respectively denoting phases that is lighter and heavier. This peculiar property has prompted further research for such blended amine solutions because only the CO2 rich phase will be sent to the regenerator thus, likely reduces the regeneration energy compared to that of 5 kmol/m3 MEA [117,142—144]. The lower amine circulation rate to the regenerator means less amount of heat input (GJ/hr) is required per liter of amine solution. This therefore, makes the phase—split amine system very promising process for CO2 capture. Fig. 10 depicts an ideal process description of a typical CO2 capture plant with phase—split aqueous amine solution. The process is similar to the conventional configuration of single phase blended aqueous amine solution shown earlier in Fig. 6. However, a liquid—liquid phase separator is installed upstream of the cross exchanger (L/R exchanger) to facilitate the separation of the CO2 lean and rich phases (by differences in density) before sending to the absorber and the regenerator, respectively. This is depicted in Fig. 10 (neglecting the dotted process route). For high pressure CO2 capture process systems (like pre—combustion process and natural gas processing) a flash drum is installed upstream of the liquid—liquid phase separator (Fig. 10). This will both step down the pressure of the CO2 saturated amine solution to the stripper pressure and also remove some of the absorbed CO2.

After regenerating the CO2 rich amine phase, the amine is mixed with the CO2 lean phase before sending them to the absorber. The advantage of this technology is that only a portion of the CO2 rich amine solution is sent to the regenerator (stripper) for desorption, which can lead to reduced regeneration energy.

Hu stated that bi—phasic amine solutions would be made up of at least one activator and another solvent in the mixing ratio of 20% and 80%, respectively [145]. Bruder and Svendsen found out that the bi—solvent blends of 2-(Diethylamino)ethanol (DEEA)/ 3-(Methylamino)propylamine (MAPA) mixed in 5 kmol/m3 and

2 kmol/m3 ratio can form two immiscible liquid phases after CO2 absorption [146]. The solvent also had a higher cyclic loading compared to that of 5 kmol/m3 MEA. They also observed that the viscosity of the CO2 rich phase was very high and affected its pumping to the regenerator. The CO2 rich amine solution viscosity is an essential parameter because its significant increase will limit heat and mass transfer (both in the cross exchanger and regenerator) and pumping difficulties. This can then affect the desired solvent regeneration efficiency.

Zhang et al. studied a bi—phasic amine solution consisting of

3 kmol/m3 DMCA (N,N-dimethylcyclohexylamine), 1 kmol/m3 MCA (N-methylcyclohexylamine), and 1—1.5 kmol/m3 AMP tri—solvent blend [147]. Based on their study, they discovered that the CO2 loading (mol/kg) of their novel tri—solvent blend was 150% higher than the single solvent MEA. It is also important to note that they used continuous stirred tank reactor for the

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

Amine blend ratio

Absorption rate Amine Stability Diffusivity

Desorption rate

Amine C02 rich loading^

Amine Emissions \

Regeneration^ Energy

Amine Biodegradability

and Ecotoxicity ^ ^ Amine circulation rate

^ \ Absorption Heat

^Cyclic capacity

C02 Capture Performance I ^mme

and Optimization

Mass transfer

Amine C02 lean ' loading

^mine Reclaiming Energy

Amine concentration

Fig. 11. Several performance criteria's of an optimized amine solution.

solvent combinations. The aim of this development is to achieve some capabilities but not limited to the following list;

• High absorption rate and capacity

• High cyclic loading and cyclic capacity

• High desorption rate

• High mass transfer

• Low absorption heat

• Reduce energy of solvent regeneration.

• Amine stability

• Amine volatility and emissions

• Minimizing amine degradation and associated energy for reclaiming

• Reduced capital and operating cost

desorption process instead of the conventional process. In addition, they also discovered high viscosity of the CO2 rich phase which in reality is not desirable in large scale operation.

Xu et al. discovered that bi—solvent blends of 1,4-Butanediamine (BDA) and diethylaminoethanol (DEEA) of 2 kmol/m3 and 4 kmol/m3 concentration ratio can form two immiscible liquid phases after amine—CO2 reactions which was attributed to the limited CO2 solubility in DEEA and fast CO2 absorption rate of BDA [148]. They also reported that this BDA—DEEA blend had higher cyclic loading (46%) and cyclic capacity (48%) compared to that of 5 kmol/m3 MEA. More recently, Ye et al. found out another bi—phasic blended amine solution consisting of TETA and DEEA to have a higher CO2 loading (40%), faster reaction rate and lower estimated energy savings (30% lower) compared to MEA [144]. Phasic—split blended aqueous amine solutions (bi—solvent and tri—solvent) have shown superiority in terms of regeneration energy savings, higher cyclic loading and capacity compared to single solvent MEA for post—combustion CO2 capture, even without significant modification in the process configuration. However, high viscosity occasionally noticed in the CO2 rich phase must be addressed to avoid the associated problems.

3. Blended amine solution: performance criteria and optimization

Fig. 11 displays an almost complete performance metrics of an optimized amine solution.

3.1. Absorption rate and absorption capacity

Absorption rate and absorption capacity are desired properties of an optimized blended aqueous amine solution. Absorption rate determines the amount of absorbed CO2 per liter of amine solution per unit time (mol CO2/l-amine solution/min), while the absorption capacity quantifies the maximum capacity of the amine solution per unit volume (mol CO2/l-amine solution). Nwaoha et al. defined absorption capacity as the equilibrium CO2 (aCO2, mol CO2/mol amine) multiplied by the amine concentration (Camjne, mol/L) as seen in Eq. (8) [111]. This will enable a fair comparison between amine solutions of different concentrations. When amine solutions of same concentration are compared, the equilibrium CO2 loading can be used as a comparison criterion.

AC = aCO2 x Cai

Some researchers have used the term initial absorption rate to quantify how fast amine solutions can absorb CO2 [57,69,111,149]. This involves plotting the CO2 absorption capacity against time. The slope calculated from the plot's initial straight line portion before the amine reaches equilibrium is

Various challenges the amine—based chemical absorption, especially with the very reactive base solvent MEA (5 kmol/m3) have prompted the need to develop and optimize novel amine

•2 O âu

Amine A Amine B

0 10 20 30 40 50 60 70 80 90 100 Time (min)

Fig. 12. Initial absorption rates of Amine A and Amine B.

t<= s ©

.s o â" 1= ö

SS s o

-Amine A -Amine B

20 30 40 50 Time (minutes)

Fig. 13. Desorption capacity vs. time plot for initial desorption rate estimation.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

taken as the initial absorption rate. Typical plots of CO2 absorption capacity and time are shown in Fig. 12. The CO2 absorption capacity can be taken within any short time interval (e.g. 5—20 min) during the experimental run. Therefore, higher slope translates to higher initial absorption rate. Based on the purpose of any study, the initial absorption rate can be the slope of the straight line at a particular time. For instance, from Fig. 12, the initial absorption rate of Amine A can be compared to that of Amine B based on the first 60 min. Alternatively, both amines can be compared based on the slope of their straight lines (absorption capacity vs time plot) before it starts leveling off (equilibrium). This means that for Amine A only the slope of the first 60 min will be considered while that of Amine B will be the slope of the first 80 min. Any method used should be consistent with all the studied amine solutions for fair comparison. It is also important to state that the time interval when taking the absorption capacity should also be consistent with all investigated amine solutions.

20 30 40 50 Cyclic Capacity

Fig. 14. Initial absorption rate vs cyclic capacity plot.

3.2. Desorption rate

Desorption rate provides an indication of how fast a CO2 rich amine solution can release the already absorbed CO2 at moderate or high temperatures (80—120 °C). Some researchers have used the term initial desorption rate to describe this [57,97,111,150]. Nwaoha et al. reported initial desorption rate from a laboratory scale analysis of amine solutions as the slope of the linear portion of desorption capacity (mol CO2/l-amine solution/min) vs time (minutes) graph [111]. The process of extracting the initial desorption rate is similar to that of the initial absorption rate. The only difference is that desorption process is conducted at a higher temperature where CO2 is removed from the CO2 rich amine solution instead of being added. Fig. 13 displays a typical desorption curve. The steeper the straight line (higher slope) the higher the initial desorption rate.

Comparing the hypothetical amine solutions (Amine A and Amine B) their initial desorption rates can be estimated from the slope of the first 10 and first 20 min (straight line portion of the graph) respectively. Alternatively, the initial desorption rates of both amines can be estimated based on the first 10 min alone. The choice of method will depend solely on the objective of the researcher. The reason for choosing the linear portion to determine the initial desorption rate is that as the curve starts levelling off, it reveals that the same amount of heat is supplied but very little amount of CO2 is desorbed.

3.3. Cyclic loading and cyclic capacity

energy [57,73,76,77,111]. Reduction in the amine circulation rate will in turn minimize the diameter of both the absorber and regenerator [72], and can be seen from the correlations in Eqs. (10)—(17) [151].

GG = vGPG

\ \Pl-PG

FP V )

?GG = L f—

G V PL

DPfiood = 0.115Fp'7

where; DPflood is pressure drop at flooding (in. H2O/ft height of packing) while Fp is the packing factor (ft-1), FLG is the flow parameter (dimensionless), pG is the gas density (kg/ft3), pL is the liquid density (kg/ft3), L is the liquid mass flow rate (kg/hr), G is the gas mass flow rate (kg/hr).

The Flg and DPflood are both used to extract the capacity parameter (CPm) from the flooding curve or pressure drop correlation graph [152].

Cyclic loading and cyclic capacity are all integral performance parameters that also contribute to the potentials of an amine blend towards CO2 capture. The cyclic loading (CL, mol CO2/mol amine) is the difference in CO2 loading between the amine solution at equilibrium with CO2 after the absorption process and the CO2 loading of the amine solution after the desorption process, while the cyclic capacity (CC, mol CO2/l-amine soln.) is the cyclic loading multiplied by the amine concentration as shown in Eq. (9) [111].

CC = (aC02_rich - "CO2_iea„^j Camine

where; aCO2_lean, is the CO2 loading at the desorption condition (mol CO2/mol amine).

High cyclic capacity lead to an increased CO2 carrying capacity hence reduced amine circulation rate and regeneration

Gas Bulk

Gas Film

Liquid Film

Liquid Bulk

HCO3" AmineCOO"

---AmineCOO"

Gas - Liquid Interface

Fig. 15. Pathway of CO2 movement from gas bulk to liquid bulk.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

\ i ———

\ \—L-—G

F0.5V0.05 FP V )

GG = VGrG

where; v is the kinematic viscosity of the liquid (cSt), vG is the superficial gas velocity (ft/s), f is the flooding factor and GG is the gas flux at operating condition (kg/m2 s).

Following Eqs. (10)—(15) step wise, the cross-sectional area (A, m2) and diameter (D, m) of the absorber column is determined with Eqs. (16) and (17).

W~g~G{

d = (4A

The desired amine solution is required to possess a high initial absorption rate and high cyclic capacity. In a plot of initial absorption rate vs cyclic capacity, the desired amine solution is expected to be at the top right portion of the graph (Fig. 14).

3.4. Mass transfer

Mass transfer is an integral parameter in determining the suitability of an amine solution for CO2 capture. In CO2 capture application, mass transfer typical entails the movement of the desired solute (CO2) from the flue gas bulk phase to the liquid bulk phase (amine solution) as depicted in Fig. 15. The higher solute (CO2) migration allows the higher mass transfer and this is desired from any potential amine solution (single or blended). In the course of this migration, the desired solute will pass through the gas film, gas—liquid interface and liquid film.

When an amine—CO2 reaction takes place, several species are formed depending on the type of amine. For tertiary amines, only bicarbonate (HCO3) is formed while the dominant specie is carbamate (AmineCOO—) in primary and secondary amines. In the case of hindered amines such as AMP, the dominant species is HCO3 with traces of AmineCOO—, while in blended amine solutions, the species formed depend on the type of amines in the blend. It is important to state that the location where the amine—CO2 reaction takes place also depends on the type of amine, amine concentration and amine blend molar ratio. For spontaneous systems the amine—CO2 reaction takes place at the gas—liquid interface, for fast systems the reaction takes place at the liquid film while for slow systems the amine—CO2 reaction takes place in the liquid bulk phase [153]. For simplicity it is assumed that there is no mass transfer of liquid from the liquid phase to the gas phase. That is why there is no amine component shown in the gas phase (Fig. 15).

The mass transfer of MEA—AMP has been studied and it was found out that the overall mass transfer coefficient (Kcav) increases as temperature, liquid flow rate and amine concentration increases [137]. On the contrary, as CO2 loading increases the overall mass transfer coefficient decreases. This is due to the fact that as amine—CO2 reaction takes place (CO2 loading increases) the free reactive amine in the solution depletes hence reduction in both the CO2 absorption capacity and mass transfer. The subsequent increase in amine solution viscosity due to the presence of HCO3, and/or AmineCOO— species also led to the mass transfer reduction. They also observed that the blend ratio

REGULAR SOLVENTS

IDEAL SOLVENT

Fig. 16. Effect of high (KGav)ave and high cyclic capacity.

affected the overall mass transfer coefficient, because as the MEA/AMP molar ratio decreased from 2 to 0.5 the overall mass transfer coefficient decreased. This trend was also recently stated in bi—solvent blends containing MEA—DMEA (Dimethyletha-nolamine), MEA—AMP and MEA—DEEA [106].

The average volumetric mass transfer coefficient, (KGav)ave can be estimated using the correlation in Eqs. (18) and (19) [50,122,154].

P(ycö2 - yC02 )

YC02i„ - Yc02o,

(yC02 - yC02)lm =

(yC02 - y*C02)in - (yC02 - y*C02)o

(yC02-yC02)in

(yC02-yC02)oui

Usually, yCO2 is assumed to be zero because it is difficult to measure the CO2 concentration at the gas—liquid interface. Naami et al. discovered that the reaction between diethylamino-2-butanol (DEAB) and CO2 is instantaneous since the measured yCO2 was 2.219 x 1038 [154]. Hence, yCO2 can be assumed to be zero without any significant error in the results. In addition, Aroonwilas and Tontiwachwuthikul previously stated that for an instantaneous reaction yCO2 is very low and can be neglected [155].

Where; (Kcav)ave is the average overall volumetric mass transfer coefficient (kmol/m3hrkPa), Gj is the inert gas flux (kmol/m2 hr), P is the total system pressure (kPa), (yCO2 — yCO2*)lm is the log—mean driving force, yCO2 is the mole fraction of CO2 in the gas bulk, yCO2* is the mole fraction of CO2 in the gas—liquid interface, Z is the height of the absorber (m), YcO2,m is the mole ratio of CO2 in the absorber inlet and YCO2out is the CO2 mole ratio in the absorber outlet.

From Eq. (18) it can be seen that a high average overall volumetric mass transfer coefficient will lead to a shorter column. Hence, a high (^KGav)ave and high cyclic capacity will reduce both the height and diameter of the column (Fig. 16), thereby reducing both capital and operating costs.

In addition, Eq. (18) also indicates that the high pressure system and high CO2 concentration of pre—combustion process

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

can lead to shorter column sizes, hence lower capital costs when compared to the post—combustion process (atmospheric pressure).

careful selection of the individual solvents in order to reduce the absorption heat. Further studies need to be conducted to confirm and validate this.

3.5. Absorption heat

Heat of absorption has an influence in the energy of regeneration because it is believed to be equal to the heat of desorption [156]. Therefore, low heat of absorption promotes reduction in energy of regeneration because less heat will be required to break the amine—CO2 species produced during CO2 absorption. Reactive amine solvents usually have high heat of absorption and it is the reason why carbamate forming amines have higher heat of absorption than bicarbonate forming amines [157]. This is also the reason why heat of absorption decreases from primary to tertiary monoamines [158]. MEA and MDEA both possess the highest (80—86 kJ/mol-CO2) and lowest (54.6—60.9 kJ/mol-CO2) heat of absorption respectively [69,79,159,160].

From experimental analysis, integral heat of absorption of amines can be determined using the differential reaction calorimeter (DRC) [70,161,162]. This method gives an accurate absorption heat of amine solutions because it takes into account the effect of heats due to physical dissolution of CO2 into the amine solvent and the amine—CO2 chemical reactions [53]. In the absence of a DRC, the Gibbs—Helmholtz correlation given in Eq. (20) has often been used to predict the differential heat of absorption [53,63,68,88,160]. According to Kim and Svendsen the differential absorption heat is believed to have a huge error (±20—30%) when there is a slight error (±2—3%) in the CO2 solubility results [53]. Another disadvantage of the differential absorption heat is that it does not take into account the effect of temperature because the plots of ln P vs 1/T are considered linear [53].

DHabs_ d(lnPcQ2)

lnPcO2A

where; PCO2 is the CO2 partial pressure (kPa), T is the temperature (K), R is the universal gas constant (8.314 J/mol.K), aCO2 is the CO2 loading (mol CO2/mol amine) and DHabs is the absorption heat (kJ/mol CO2).

Apart from using DRC or the Gibbs—Helmholtz correlation, other researchers have deployed alternative methods of determining the absorption heat of amine solutions [100,163—166]. Abdulkadir and Abu-Zahra analysed the heat of absorption of single solvents (i.e. 5 kmol/m3 MEA, 2 kmol/m3 PZ, 1 kmol/m3 AMP, and 0.9 kmol/m3 MDEA) and bi—solvent blends (i.e. 1 kmol/ m3 AMP—2 kmol/m3 PZ and 0.9 kmol/m3 MDEA—2 kmol/m3 PZ) [167]. The bi—solvent blend of 0.9 kmol/m3 MDEA—2 kmol/m3 PZ was found to have a lower absorption heat that those of 5 kmol/ m3 MEA and 2 kmol/m3 PZ, respectively. The absorption heat of 1 kmol/m3 AMP—2 kmol/m3 PZ however, was higher than 5 kmol/m3 MEA but significantly lower than 2 kmol/m3 PZ. It was also seen that the heat of absorption of the bi—solvent blends were between those of their parent solvents [167,168]. In addition, the bi—solvent blend, particularly the one containing tertiary amine (MDEA) had a lower heat of absorption than that of the one with sterically hindered (AMP). From a preliminary in—house experimental study using Gibbs—Helmholtz correlation, it was also discovered that the absorption heat of the AMP—MDEA—DETA tri—solvent blends decreased with decreasing AMP/MDEA molar concentration ratio.

From these studies, it can be inferred that the flexibility of blended amine solutions (i.e. bi—solvent, tri—solvent) will enable

3.6. Regeneration energy

Regeneration energy is mainly a combination of three parameters as seen in Eq. (21) [156].

Qreg = [Qdes] + [Qsen] + [Qvap]

where; Qj-eg (GJ/tonne CO2) is the energy of regeneration, Qdes (GJ/tonne CO2) is the heat of desorption required to break the CO2 carrying species (i.e. carbamates, bicarbonates, carbonates) formed during the amine—CO2 reactions (believed to have the same value as heat of absorption, DHabs), Qsen (GJ/tonne CO2) is the sensible heat that must be provided to raise the temperature of the CO2 rich amine solution to the regeneration temperature while Qyap (GJ/tonne CO2) is the latent heat of vaporization of the volatile components in the amine solution (usually the vaporization heat of water).

A simple correlation for calculating the sensible heat and heat of vaporization of amine solutions is shown in Eqs. (22)—(24) [169—171].

[(«CO2ric„ - *CO2leJCamine]McO2

C(Tr - Tf) Msol J_ A«CO2 MCO2 Xsol

Qvap = AH,

PH2O 1

vap-H2OPCO2 MCO2

where; C is the specific heat capacity of the CO2 loaded amine solution (kJ/kg. oC), AT is the temperature difference between the absorption and regeneration (°C), MCO2 is the molecular weight of CO2 (44 g/mol), TR is the regeneration temperature (°C), TF is the temperature of the rich aqueous amine solution at stripper inlet (°C), AaCO2 is the cyclic loading of the rich aqueous amine solution (kg CO2/kg amine), Msol is the amine solution molecular weight (g/mol), XH2O is the mole fraction of water in the rich aqueous amine solution and AHvap,H2O is the latent heat of water vaporization, PCO2 and PH2O are the CO2 and water partial pressures at regeneration temperatures.

^ 3.5 O

¡» 2.0 a

1.5 1.0 0.5 0.0

f REGULAR

I SOLVENTS

RECENT

SOLVENTS

IDEAL \

SOLVENT )

Amine Solvents

Fig. 17. Desired regeneration energy of the ideal amine solution.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

M w «

4.5 4 3.5 3 2.5 2 1.5 1 0.5 0

A 5 kmol/m3 MEA

Ideal Amine Solvents

120 150

Regeneration Temperature (oC)

Fig. 18. Desired regeneration temperature and energy of the ideal amine solvent.

Considering that the specific heat capacity of amine solvents does not differ significantly among themselves [158], the sensible heat of any amine solution can be believed to be influenced by their cyclic loading, amine concentration and density as seen in Eqs. (22) and (23).

Heat of vaporization is the final parameter that sums up the regeneration energy. This is the amount of energy required to vaporize the water in the CO2 rich amine solution in order to produce the stripping vapor which largely depends on the amount of water present in the solution [158]. Thus, compared to a less concentrated amine, a highly concentrated aqueous amine solution will benefit from having a smaller water concentration which will only require less latent heat of water vaporization. Therefore, 50 wt% TEA (triethanolamine) will possess lower heat of vaporization compared to 30 wt% MEA [158]. It is also important to highlight that the heat of vaporization will also greatly depend on the regeneration temperature. At same water concentration aqueous amine solutions will consume more vaporization heat at higher temperature (120 °C) than at lower temperature (85 ° C). Usually low temperature here is referring to temperatures below boiling point of water. The contribution of vaporization heat towards the regeneration energy will then depend on the water concentration (related to the amine concentration) and temperature of regeneration process.

The energy required for amine solution regeneration is seen as one of the most important parameter that needs to be addressed in the search of potential solvents for CO2 capture. This is because, it accounts for as high as 70—80% of the plant operational cost [84,85]. In terms of regeneration energy (heat duty) of 5 kmol/m3 MEA, several authors stated that this could be as high as 3.3—4.4 GJ/ton CO2 which is extremely high and very expensive for post—combustion CO2 capture applications [7,8,18,80,83,149,172,173]. For CO2 capture process to be economically practical in a coal-fired power plant, 0.72 GJ/ton CO2 of reboiler heat duty is required which must be achieved from both process configuration and chemical solvent improvements [76]. From solvent optimization alone (e.g. blended amines), Mangalapally and Hasse reported 20% reduction in reboiler heat duty during the pilot plant test run using CESAR1 (AMP—PZ blend) solvent [127]. Another pilot plant run reported 35% reduction in regeneration energy using their new solvent (i.e. CANSOLV DC-201) [82]. Singh et al. studied new solvents in pilot scale operation which were found to reduce the energy of regeneration of 5 kmol/m3 MEA from 4.33 GJ/ton CO2 to 2.26 GJ/ ton CO2 [174]. Fig. 17 shows the current values of the regeneration energy of regular and recent amine solvents. The ideal solvent as well, is shown in the plot to indicate the desired

regeneration energy which will most likely to be achieved by blending amine solvents.

Most often, regeneration energy is only reported based on the amount of energy required to strip an amount of CO2 (GJ/tonne CO2). However, as pointed out by Idem et al. this could be misleading because the temperature at which regeneration was carried out is a big factor and should be reported [175]. For instance from Fig. 18, two hypothetical amine solvents (Amine A and Amine B) can have same regeneration energy but Amine A was regenerated at a lower temperature (e.g. 90 °C) while Amine B was regenerated at higher temperature (120 °C). Such scenario reveals that Amine A is easier to regenerate and will be preferred for CO2 capture applications when compared to Amine B. In addition, Amine A will not require steam for regeneration process which will maintain the efficiency of the power plant. Nwaoha et al. suggested several benefits of low temperature regeneration to include reduced amine degradation, low emissions and possibility of not consuming steam needed for power generation [97].

For performance screening purposes (to compare several amine solutions), regeneration energy can also be determined in a small scale semi—batch process in the laboratory [68,97,111,176]. Nwaoha et al. reported that both highly concentrated AMP—PZ—MEA tri—solvent blends (6 kmol/m3) and AMP—MDEA—DETA blends reduced regeneration energy by half compared to 5 kmol/m3 MEA at 90 °C regeneration temperature [97,111]. For blended amine solution, careful selection of the amine components in the blends will go a long way towards reducing the regeneration energy compared to the single solvent MEA [97,111]. From previous studies as discussed in this paper, blended amine solution should contain a tertiary amine or ste-rically hindered amine solvent due to their formation of HCO3 ions in the solution.

Shi et al. investigated the role and contribution of HCO33 in reducing regeneration energy [176]. It was discovered that HCO3 in the CO2 loaded amine solution will both facilitate the depro-tonation of protonated amine (AmineH+) to release free amine and also act as a proton (H+) acceptor to directly liberate CO2 as shown in Eqs. (25) and (26). Hence, the more HCO33 in the amine solution the faster the reactions are. This deprotonation can also be done by H2O, but H2O being less basic than HCO3 (pH = 8.5) makes its contribution less and slow as seen in Eq. (27). Another big disadvantage of the amine deprotonation by H2O is that it is strongly endothermic. Also, the pathway for amine deprotona-tion by H2O only follows a single route and does not liberate CO2

Table 1

Amine recovery and degradation products removal of different reclaiming technologies [182].

Reclaiming technology Amine HSS Removal Metals/Non—ionic Product Recovery (wt.%) (wt.%) Removal (wt.%)

Thermal 95 100 100

reclaiming

Electrodialysis 97 91.5 0

Ion exchange 99 90 0

Table 2

Normalized capital cost estimates of different reclaiming technologies [182].

Reclaiming technology

US$ per kg/hr

Thermal reclaiming Electrodialysis Ion exchange

76,000 70,000 101,000

Amine A

Amine B

C. Nwaoha et ai. / Petroleum xxx (2016) 1—27

Fig. 19. Effect of amine degradation (amine instability) towards plant operating costs.

directly. This phenomenon has also been used by Nwaoha et al. in explaining the low regeneration energy of tri—solvent blends containing HCO3 forming amine solvents [97,111].

AmineH+ + HCO3 4 Amine + H2CO3 (25)

H2CO34CO2 + H2O (26)

AmineH+ + H2 O4 Amine + H3O+ (27)

Additionally, previous studies have reported regeneration energy reduction due to improvements and modifications in amine solvents and process configuration respectively [119,127,177—180]. In order to greatly reduce this energy a combination of these will go a long way. Recent experimental and bench—scale pilot plant results has shown that employing solid catalysts (HZSM—5 and g—Al2O3) in the regenerator reduces the regeneration energy and also lead to the use of hot water instead of steam as the heating medium [176,181]. They reported that HZSM—5 donates H+ to AmineCOO— (carbamate) which then breaks it down to free amine and CO2 while the g—Al2O3 deprotonates the AmineH+ hence releasing free amine. Both reaction routes by the aid of the catalysts reduce the thermal energy required to perform similar tasks in the regenerator.

This technology has now introduced an additional route towards reducing regeneration energy at lower regeneration temperatures.

3.7. Amine stability

Amine stability is one of the key parameters that signify the potential of an amine solution (single or blended) for CO2 capture application. Stable amine solutions translate to lower degradation. As amine solvents degrade during CO2 capture, a slipstream of the CO2 lean amine solution is sent to the reclaiming unit to recover fresh amine solvents. Slipstream for thermal reclaiming is withdrawn from the CO2 lean amine process line upstream of the lean/rich heat exchanger while that required for ion ex-change/electrodialysis reclaiming is withdrawn from the CO2 lean amine process line entering the absorber [182]. Recent results [182] showed that thermal reclaiming still offer better performance for recovering amine solvent and separating degradation products (Table 1). The removal of metals and non—ionic degradation products (neutral degradation products) also make thermal reclaiming preferable. Thermal reclaiming is also cost competitive (Table 2) [182].

Though researchers [84,85] identify heat of regeneration as the major culprit in high operating cost of CO2 capture process plant, it is important to note that high degradation rates can also be the major problem. This is because high degradation rate ofan amine solution will lead to higher corrosion rate, increased amine make—up (high solvent loss), significant increase in viscosity (increased pumping duty and mass transfer limitation), higher foaming [183—188], emissions of potentially toxic substances in the capture plant off—gas. In addition, high degradation rate also lead to frequent solvent reclaiming and waste disposal and increased energy requirement both in the water wash section of the absorber and in the desorber (regenerator or stripper) overhead condenser (Fig. 19).

It can be seen from Fig. 19 that a combination of the key variables affected by amine degradation can surpass regeneration energy as the major contributor to the operating costs. Therefore, it is very important to understand the chemistry and pathways of amine degradation in order to reduce the accompanying risks, costs, and environmental concerns. Amine degradation (irreversible chemical reactions) can occur due to high temperature in the desorber typically operated between 110 and 130 °C [189—191]. This temperature range will speed up thermal degradation, the undesirable amine break—down process. Chemical degradation is also triggered by oxygen (oxidative degradation) present in the flue gas which could be as high as 11%vol [177]. Other impurities including NOx, SOx and fly ash in the flue gas stream can also significantly contribute to the degradation of amine solvents [12,131,177,183,192—204]. Though there are several degradation products reported in various studies, however, nitrosamines and nitramines seem to be the most concern as they pose more environmental and health risk compared to others [205—209]. Nitrosamine is the major degradation product generated from reaction of NOx in the flue gas and it is mainly produced by secondary amines followed by tertiary amines and then primary amines [209,210]. This is because secondary amines form stable nitrosamines and nitr-amines while the nitrosamines formed by primary amines

Table 3

Structures of some studied ether amines for CO2 capture.

Ether amine Skeletal structure Reference

Bis(2-methoxyethyl) amine ^ nh / [201]

(BMEA) o

3-Methoxypropylamine [201]

(MOPA)

C. Nwaoha et al. / Petroleum xxx (2016) 1—27 15

degrade rapidly to release N2 and a carbocation [211 ]. Smith and Loeppky stated that nitrosation of tertiary amines forms an unstable cationic intermediate that dealkylates to yield a nitro-stable secondary amine [212]. Yu et al. further revealed that tertiary alkanolamines that contain two 2-hydroxyethyl groups showed higher nitrosamine formation potential compared with other tertiary amines with one or three 2-hydroxyethyl groups [210]. Their study also indicated that when tertiary amines contain same number of 2-hydroxyethyl groups, the amine with shorter alkyl chains enhanced formation of nitrosamine.

Though amine blends offer huge benefits in lowering regeneration energy they might engage in undesired secondary reactions. These can involve individual amine reaction with degradation products of the other amine (in the blend) and/or the reactions between the degradation products of the individual amines in the blend. Degradation of amine blends (MEA—MDEA, MDEA—PZ, MDEA—DEA, MEA—PZ, MEA—AMP) have been studied [84,131,196,197,213,214]) and it was reported that more degradation products were produced in the blends compared to their individual amines. A study done by Idem et al. on MDEA—MEA degradation in boundary dam pilot plant revealed that MEA degraded faster in the blend (i.e. 2.3 mol %/day) than in single MEA (i.e. 0.5 mol %/day) [85]. Lawal et al. discovered that MEA degraded by O2 at a slower rate when blended with MDEA than in a single MEA solvent [213]. This was because MDEA was preferentially degraded in the blend thereby reducing the degradation of MEA. Experimental results of Wang and Jens showed that PZ oxidatively degraded slower as a single solvent than when it was mixed with AMP [204]. Similar trend was reported in the thermal degradation studies of MDEA—PZ and AMP—PZ blends [215,216]. Based on Li et al. and Closmann et al. studies, oxazolidone degradation product formed in AMP and MDEA mixture could be blamed for such a high degradation of PZ in the mixed solvent [131,217]. Rochelle reported that PZ—AEPD (PZ—2-Amino-2-ethyl-1,3-propanediol) thermally degraded faster than PZ—AMP due to the additional OH group (hydroxyl group) of AEPD, which made it more prone to form oxazolidone than AMP [215]. This has been also confirmed by Du et al. that an additional OH group decreases the thermal stability of the amine making it more likely to form oxazolidone [201]. Namjoshi showed that the rate of thermal degradation of PZ—DMAEE (piperazine—dimethylaminoethoxyethanol) was lower than that of PZ—MDEA, because DMAEE cannot form oxazolidone [218].

Namjoshi et al. further stated that diamines (without OH group)—PZ blends showed higher thermal stability than both tertiary amine—PZ and hindered amine—PZ blends [216]. Rochelle previously stated that ether amines are expected to exhibit higher stability than their corresponding alkanolamines

[215]. This is because ether amines are less likely to degrade by carbamate polymerization like the alkanolamines. Table 3 shows some studied ether amines. Du et al. recently confirmed that ether amines are more stable than their alkanolamines counterparts because ether amines do not easily form oxazolidone like alkanolamines [201]. This was evidenced in their experimental results as PZ—BMEA and PZ—MOPA blends degraded much more slowly compared to most PZ—acyclic alkanolamines blends. This means that the type of functional group and its position in an amine can also affect the stability of the amine when it is blended with other amine solvents.

Previous investigations have now shown that degradation products of an amine solvent (in a blend) can catalyze the degradation of the other amine solvent in the blend. Hence, in order to optimize an amine blend to withstand degradation, proper understanding of the degradation products of the individual amines in the blend, the type of functional group and its position in the amine solvent is very important. It is also true that once adequate understanding of the amine degradation chemistry with respect to functional group type and position (in an amine) is well studied, characterising a novel polyamine with all the desired properties (e.g. type of functional group and position) will offer a lasting and reliable solution. This will lead to the deployment of the desired single amine (not blended amine) which will be a polyamine for CO2 capture application.

From Arrhenius relationship in Eq. (28) a 10 °C increase in temperature doubles reaction rate, and this is also the case for amine degradation rate. Therefore, low temperature regeneration (temperatures below 100 °C) will greatly minimize the rate of amine degradation. Nwaoha et al. also suggested additional benefits of low temperature regeneration which also covers less environmental implication, reduced operating and capital costs, lower amine make—up, minimized waste treatment and disposal [97].

k = Ae^ (28)

where; k is the rate constant, A is the frequency factor, Ea is the activation energy (kJ/mol), R is the universal gas constant (8.314 J/K.mol) while T is the temperature (K).

In addition to the effect of temperature towards amine degradation rate (rdeg, kg/hr), Eq. (28) can be expanded to include concentration effects of O2, SOx, NOx, fly ash (Cash), metals concentration (Cmetals) and water concentration (CH2O). Additionally, when various amine concentration is investigated (single or blended amine solvents), the amine concentration (Camine, kmol/m3) variable should be included. This will lead to

Fig. 20. Several options of reducing amine solvent degradation during CO2 capture.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

the development of a model that is analogous to a power law kinetic model as shown in Eq. (29).

rdeg [CO2 ]a[O2]h[SOx]c lNOx]d[Cash ]e [Petals f [Ch2O]s [Camine\h

where; a, b, c, d, e, f, g and h coefficients are the order of the reaction and can predict the contribution and influence of each component towards amine degradation. These coefficients can be determined by regression. The rdeg parameter in Eq. (29) can also be replaced with either the mass flow rate of the CO2 lean amine solution that is reclaimed (Fm, kg/hr) or its volumetric flow rate (Fv, L/hr). The choice of parameter to use (on the left hand side) will depend on the available data.

If nitric acid (HNO3) and sulphurous acid (H2SO3) were used to represent NOx and SOx respectively during the experiment then NOx and SOx should be replaced with HNO3 and H2SO3 in Eq. (29).

Fig. 20 depicts the summary of possible options for minimizing degradation of amine solvent. The combination of the proposed options will help towards enhancing CO2 capture efficiency, lower regeneration energy and reduce amine degradation rate.

3.8. Amine volatility and emissions

The volatility of an amine solvent is an integral parameter when selecting an amine solvent for CO2 capture. Highly volatile amine solvents will increase both the capital and operating costs because the size of the water wash unit both at the top exit of the absorber and desorber will increase while the energy needed for the water wash system and amine losses (increased amine make—up) will both increase. For very expensive amine solvents, the cost associated with increase in their amine make—up could be very high. Researchers [219,220] have previously studied amine volatility and emissions. Results reported by Nguyen et al. revealed that amine volatility is highest at the absorber top at 40 °C while amine volatility decreased as CO2 loading increased (due to reduced free amine present in the solution) [220]. They also reported amine volatility to follow this trend MDEA ~ PZ < PZ < EDA < MEA < AMP, indicating that blended amine solvents have the potential of reducing amine emissions. According to previous studies [221—223], applying MEA for post—combustion CO2 capture emitted between 0.1 and 0.8 kg MEA/tonne CO2 captured with using a water wash. When a water wash unit was installed the MEA emissions can be as low as 0.01—0.03 kg/tonne of CO2 captured [221,224]. Amine volatility and emission can be experimentally studied using a procedure known as 'iso—kinetic sampling method'. This involves trapping the volatile compounds from the off gas of the absorption unit using a diluted acid placed in series of impingers. This method has been successfully used by many researchers [225—230] to evaluate the volatility and emission of amine solvents.

Emitted amine solvents can further undergo reactions with oxidants in the atmosphere which involve oxidized atmosphere to form nitrosamines, nitramines and amides [231]. From the previous sub-section on amine stability, it was seen that nitro-samine and nitramines are more prevalent with secondary amines. Now, the key issue is if secondary amines are avoided for post—combustion CO2 capture, are the tertiary and primary amines eco—friendly and very biodegradable (BOD)?

This is because in the quest to reduce carbon emissions (which is not toxic) care must be taken to avoid secondary pollution through amine emissions which in most cases are toxic

to health, environment and aquatic life. Several studies that have reported the improved CO2 capture capability of their amine solvent have not reported their volatility, ecotoxicity and biodegradability limits. Eide-Haugmo et al. studied the biode-gradability and ecotoxicity of 43 amine solvents and their results revealed that some of the frequent amine solvents (MDEA, PZ and AMP) commercially applied for CO2 capture has very low biodegradability [232]. Their results also showed that amine solvents with biodegradability below 20% are not acceptable while biodegradability above 60% means that the amine solvent is readily biodegradable. Their study also revealed that toxicity is a problem when the ecotoxicity of an amine is below 10 mg/l [232]. In particular is the volatile trimethylamine with ecotoxicity below 10 mg/l.

Some few questions are yet to be clearly answered;

• Should a volatile amine which is very biodegradable and eco—friendly be acceptable for CO2 capture applications?

• Should a non—volatile amine that is not readily biodegradable and slightly ecotoxic be acceptable at some applicable concentration?

• Can blended amine solutions be a combination of the previous scenarios listed above?

• Should blended amine solvents be chosen in terms of being 60—100% BOD and being eco—friendly? Meaning that a 60% BOD amine solvent can be blended with a 25% BOD amine solvent at blend ratio of 70—30% respectively? And should an amine solvent with ecotoxicity below 10 mg/l be blended with another amine solvent with ecotoxicity above 10 mg/l at 30—70% blend ratio respectively?

Therefore, finding a balance between amine ecotoxicity, biodegradability and volatility will help reduce associated costs and risks. This can be achieved by blending amines. In future studies, efforts should be made to incorporate amine solvents that are eco—friendly and readily biodegradable towards CO2 capture.

3.9. Relative cost of CO2 capture

Cost associated with CO2 capture has drawn considerable attention because this will influence its commerciality in combustion processes. Previous studies have focused basically on reducing the regeneration energy while a few others have looked into reclaiming cost [7,8,84,182]. However, there are other parasitic energies and costs that need to be taken into account before an amine solution is deemed potential for CO2 capture.

3.9.1. Total equivalent work

As mentioned previously, most studies have focused on reducing the regeneration energy as they stated that its reduction would greatly reduce the CO2 capture plant operating cost [18,76,82,84,100,172]. The typical correlation for determining regeneration energy is shown in Eq. (30).

input _ msteamCpsteamDT

rCO2_ prod

rCO2_ prod

where; Hinput is the heat input from the reboiler (GJ/hr), msteam is the mass flow rate of the steam (kg/hr), Cpsteam is the specific heat capacity of the steam (kJ/kg.°C), while AT is the temperature difference between the steam inlet and condensate outlet (°C). The heating medium can either be steam or hot oil as the case may be.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

However, other studies suggested that incorporating the energy spent on pumping and compression shown as total equivalent work in Eq. (31) would provide a better idea on the overall energy savings or penalties of the CO2 capture plant [233—236]. In Eq. (31), it is assumed that the temperature of the steam in the boiler is 10 K higher than the reboiler temperature.

Weq = nQreg

(Treb + 10K) - 313K

(Treb + 10K )

+ Wcomp + W

where; Weq is the total equivalent work (GJ/tonne CO2), Treb is the steam temperature in the reboiler (K), Wcomp is the compressor work of the produced CO2 (GJ/tonne CO2), Wpump is the pump work (GJ/tonne CO2), and n is the turbine efficiency to produce electricity from steam (0.75).

In addition to the total equivalent work which includes the regeneration energy, pump work and compression work, it is important to add fourth and fifth energy terms namely the energy required for condenser energy (Qcond) and reclaiming amine (Qrec). Therefore, Eq. (31) is modified to Eq. (32);

Weq = Qreg + Wcomp + Wpump + Qcond + Qrec

where; Qrec is the amine reclaiming energy (GJ/tonne CO2) with respect to the amount of produced CO2 while Qcona is the energy required to condense the vapor phase leaving the top of the regenerator (GJ/tonne CO2).

The energy required for the condenser and reclaimer is detailed in Eq. (33).

( mcoolCpcoolAT\ \ rCO2_ prod J

where; Qcond is the energy required to condense all condensable species from the regenerator top outlet (GJ/tonne CO2), mcool is the mass flow rate of the cooling medium that will aid in achieving produced CO2 purity of 99% (kg/hr), Cpcool is the specific heat capacity of the cooling medium (kJ/kg.°C), while AT is the temperature difference between the cooling medium inlet and outlet (°C).

The condenser energy can also be said to equal to the heat of vaporization, because the energy used for vaporization in the reboiler is also needed to condense the vaporized water and amine in the condenser (refluxed back to the regenerator). This implies that an amine solution that has high heat of vaporization will require the same heat for condensation in the condenser which is a higher 'double energy penalty'. This also highlights the merits of 'low temperature regeneration' process because of the hugely reduced vaporization heat. Therefore breaking down the contribution of absorption heat, sensible heat and heat of vaporization towards regeneration energy is very important.

3.9.2. Amine reclaiming energy

This energy has not been extensively studied in laboratory scale which is currently a set back because some amine solvents with low regeneration energy might have a high parasitic reclaiming energy (and vice versa).

During CO2 capture process, a slip stream of the CO2 lean amine solution from the regenerator is taken to the reclaiming unit to remove amine degradation products and recover fresh amine solvent, thereby maintaining the CO2 capture performance of the amine solvent. However, reclaiming comes with an additional energy penalty, most especially if thermal reclaiming technology is used [182]. Also, the amine waste generated is occasionally disposed of to avoid accumulation in the reclaiming

unit. Results revealed that the reclaiming energy penalty will depend both on the type of reclaiming technology and type of amine used [182].

It is believed that there could be cases where the reclaiming energy will be higher than the regeneration energy. Hence, it is important to quantify or estimate the energy required for reclaiming an amine solution in order to ascertain the main source of energy penalty. This review paper is proposing a new correlation for estimating amine reclaiming energy (especially for thermal reclaiming) which considers the specific heat capacity (Cp, kJ/kg°C) of the CO2 lean amine solution and atmospheric boiling point (Tbp, °C) of the amine solvent(s) in the amine solution as well as the amine reclamation rate as represented in Eq. (34).

(Cpamine)[Tbp) (Fm) rCO2_prod

where; Qrec is also in GJ/tonne CO2 while Fm is the mass flow rate of the CO2 lean amine solution that is reclaimed (kg/min).

The boiling point of the CO2 lean amine solution can be estimated using Eq. (35). Alternatively, any appropriate thermal analytical instrument can be used to determine the boiling point.

Tbp = ^2 fZTbp-i i=1 T

where; Tbp is the atmospheric boiling point of the amine sol-vent(s) in the amine solution (°C), Q is the concentration of the ith amine in the blended amine solution (wt.%), CT is the total concentration of all components (amine and H2O) in the aqueous amine solution (wt.%), while Tbpj is the atmospheric boiling point of the ith amine solvent(s) in the amine solution (°C).

When the specific heat capacity is not directly measured or available, Eq. (34) can then be rewritten as shown in Eq. (36).

1 (Tbp

rCO2_prod

where; l is thermal conductivity (mW/m. oC or mJ/s.m.°C), a is the thermal diffusivity (1E8m2/s) and p is the density (kg/m3) of the CO2 lean amine solution.

From Eq. (34) it can be deduced that the rate of amine reclamation, the atmospheric boiling point of the amine sol-vent(s) in the amine solution and the specific heat capacity of the CO2 lean amine solution are all proportional to the energy penalty for amine reclaiming. Though it has been documented that specific heat capacity of amine solutions do not vary much [158], therefore the energy penalty for reclaiming will depend more on both the atmospheric boiling point of the amine solvent(s) in the amine solution and reclaiming rate of the CO2 lean amine solution.

When CO2 lean amine volumetric flow rate is used, then Eq. (36) can be rewritten as shown in Eq. (37).

Tbp (Fv)

rCO2_ prod

where; Fv is the volumetric flow rate of the CO2 lean amine solution that is reclaimed (m3/min).

For simplicity, all thermophysical parameters of the CO2 lean amine solution as shown in Eqs. (34), (36) and (37) can also be estimated using commercial process simulators like Aspen Plus,

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

Amine A Amine B A Amine C Ideal Amine Solvents

220 200 180 160 140 120 100

Fm 0r Fv 0r ramine_dis

(kg/min or L/min or kg/hr)

Fig. 21. Various scenarios of amine reclaiming rate vs amine solution boiling point (at similar CO2 production rate).

Aspen HYSYS both licensed by Aspen Technology, Inc., USA; ProMax (licensed by Bryan Research & Engineering, Inc., USA) and ProTreat® (licensed by Optimized Gas Treating Inc. USA) [237—240] etc.

Additionally, looking at Eqs. (34), (36) and (37) the flow rate of the CO2 lean amine solution to be reclaimed was used. However, this parameter might not be available in many pilot plant and bench—scale plant studies as well as in semi—batch experimental set—up. This parameter can be replaced with the disappearance rate of free amine in the amine solution (ramine dis, kg of amine/hr) as shown in Eqs. (38) and (39). This is valid because the faster the free amine disappearance the faster the amine degradation. Since free amine are also lost through emissions, this should be taken into account (subtracted) so that the amine losses used for Eqs. (38) and (39) will be amine lost due to degradation.

(Cp amine )( Tbp) ( ramine_dis

rCO2_prod

n _ ramine-dis ¡rn \(t

^rec — --(Cpamine)( 'bp

rCO2_ prod v

It is important to note that though thermal reclaiming is conducted under vacuum (most amine solvents with very high atmospheric boiling point) the actual atmospheric boiling point of the amine solvent(s) in the amine solution is used in Eqs. (34)—(39) for simplicity. This can give the true trend of reclaiming energy because amine solvent(s) with higher atmospheric boiling point will require more vacuum energy than amine solvent(s) with lower boiling point. Vacuum condition is required so that the actual temperature for reclaiming will be reduced (below 100 °C), hence minimize any further thermal degradation of the amine solvents.

Additionally, when a semi—batch experimental set—up is used for analysis where the absorption and desorption experiments were conducted separately, then Eqs. (38) and (39) still holds but the rCO2_prod and ramine_dis can be determined using correlations shown in Eqs. (40) and (41).

rC02_ „:

[(aC02riCh - aC02iean)Camine\MC02

timede:

ramine_dis —

timeabs-des

Ê I 4

Amine A •Amine B

AIdeal Amine Solvents

0 10 20 30 40 50 60 70 80 90 100

Costamine (US$/kg amine)

Fig. 22. Relationship of cost of amine and amine—CO2 ratio towards amine cost.

where; ramine_dis, is the rate of free amine disappearance (kg of amine/hr or tonne of amine/hr), rCO2_prod is the CO2 produced (kg of amine/hr or tonne of amine/hr), timedes is the desorption time during the experiment (hr), timeabs-des is the total time of both the absorption and desorption experiment (hr), Mamine is the molecular weight of the amine solvent (g/mol or kg/mol), Cami-ne_ini is the initial amine concentration at the start of the experiment (moles) while Camine_rem is the remaining free amine concentration at the end of the experiment (moles).

From Eqs. (34)—(41) and Fig. 21, some assumptions can be made:

• At similar CO2 production rate, an amine solvent with higher reclaiming rate and boiling point with have the higher energy penalty for reclaiming.

• At similar CO2 production rate and reclaiming rate, an amine with lower boiling point will require less reclaiming energy.

• At similar CO2 production rate and boiling point, an amine with higher reclaiming rate will require more reclaiming energy.

• It is most desired to have an amine solution with lower reclaiming rate and low boiling point (at similar CO2 production rate).

Low boiling point in this case refers to amines with boiling point slightly above that of water (105—140 °C). Most commercial amine solvents have boiling points between (145—248 °C), which means that they are likely to consume high energy for reclaiming (if they degrade fast). Also at constant vacuum pressure (in the reclaimer), amine solvents with low atmospheric boiling point will have much lower boiling point (than those with high atmospheric boiling point) leading to the use of hot water as the heating medium for reclaiming.

Since the boiling points of some nitrosamines, heat stable salts and non—ionic products like N- nitrosodiethylamine (NDEA, 171 °C), N-nitrosodimethylamine (NDMA, 151 °C), N-Nitrosodi-n-propylamine (NDPA, 206 °C), succinic acid (235 °C) and 2-Oxazolidone (220 °C) are high, they are less likely to be produced alongside with the recovered amine solvent during thermal reclaiming process for a low boiling point amine solvent.

It is important to note that low boiling point amine solvents might not necessarily lead to higher emissions because volatility is related more to the vapor pressure than boiling point. However, more research need to be conducted on low boiling point amine solvents to ascertain their overall benefits.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

3.9.3. Amine cost

The cost of using an amine solvent for 90% CO2 capture is another challenge for CO2 capture plants because they impact additional cost for CO2 capture. Rubin and Rao [241] stated that the cost of amine solution (MEA) can account for about 10% of the CO2 capture cost.

Nwaoha et al. proposed a parameter known as amine—CO2 ratio shown in Eq. (42) which compared amine solvents in terms of the amount of amine required to capture CO2 [97]. This parameter can be used to compare amine solvents at similar CO2 capture efficiency (e.g. 90% CO2 capture) and/or at similar amount of CO2 produced/desorbed. Hence, the actual cost of the amine solvent can be accurately estimated which is also related to parameters such as emissions, amine make—up and regeneration energy. For instance, an amine can be more expensive than MEA but during 90% CO2 capture it requires less amine circulation than MEA. This means that the overall cost of the amine solution for CO2 capture might be less when compared to MEA. This could also translate to reduced emissions and amine make—up, less pumping and regeneration energy (if the amine does not degrade faster than MEA). Such scenario has been reported in a tri—solvent blend containing specifically AMP—M-DEA—DETA which was more expensive than MEA but required lower amine circulation rate as estimated, but higher CO2 production leading to cheaper overall amine cost [97].

Amine - CO2Ratio

' amine-soivent rCO2_ prod

where; Amine—CO2 Ratio is the ratio of the amine solvent circulation rate to the average CO2 desorbed or produced (l—amine solvent/tonne CO2 or kg—amine solvent/tonne CO2), rCO2prod is the rate of CO2 desorbed or produced (tonne CO2/hr or kg CO2/hr) while Famine_soivent is the amine solvent circulation rate without considering the water in the solution (l—amine solvent/hr or kg—amine solvent/hr). This is the actual amine content in the aqueous solution.

In order to estimate the cost of the amine solvent for CO2 capture Eq. (42) is modified to Eq. (43).

Aminecost

1 amine-soivent rCO2_ prod

(Costamine)

where; Aminecost is the cost of the amine solvent for CO2 capture (US$ amine/tonne CO2), Costam;ne is the actual cost of the amine solvent(s) in the aqueous amine solution (US$/kg amine). The Costamine can be retrieved from the quotation of the amine supplier which is often available online.

From Fig. 22 it can be seen that lower amine—CO2 ratio might not necessarily translate to a lower amine cost (US$ amine/tonne CO2) because the cost of the amine solvent (US$/kg amine) plays an important role. Looking at the two hypothetical amine solvents, Amine A has higher amine—CO2 ratio but lower cost of amine when compared to Amine B which led to the aminecost to follow the trend Amine A (US$ 280/kg CO2) < Amine B (US$ 315/ kg CO2). Similar trend was reported by Nwaoha et al. when AMP—MDEA—DETA blends were compared to single solvent MEA. Fig. 22 also depicts the region for the ideal amine solvent for CO2 capture which should possess low amine—CO2 ratio and low cost.

Eqs. (42) and (43) can be easily applied when pilot plants and/ or bench scale pilot plants are used for studying amine solvents because amine flow rates are available. However, when semi—batch experimental set—up is used for amine investigation the amine solvent flow rate can be estimated [97].

3.9.4. Amine make—up cost

Amine make—up cost is another parasitic cost for CO2 capture using amine solvents. When amine is lost due to either or both degradation and vaporization the rate of amine make—up will increase hence increased amine make—up cost. Amine degradation and vaporization losses can be easily analysed from both pilot plant studies and semi—batch laboratory experimental set—up [118,196,199—202,216,218,220—224,229]. Results from these studies should also be translated to cost of amine make—up which has not been done. It is practical to believe that amine losses during CO2 capture is proportional to amine make—up because more amine losses will lead to increased amine make—up in order to maintain the desired amine concentration.

This review paper is also proposing a new parameter that will account for amine losses due to emissions induced by amine volatility and degradation per amount of CO2 produced and/or CO2 capture efficiency as shown in Eq. (44).

Amineloss — ramine-deg + Tamine-vap

rCO2_ prod rCO2_ prod

where; Amineioss is the total amount of amine loss during CO2 capture with respect to the amount of CO2 produced (l—amine solvent/tonne CO2 or kg—amine solvent/tonne CO2), ramine_deg is the rate of amine degradation (l—amine solvent/hr or kg—amine solvent/hr), while ramine_vap is the rate of amine losses through emissions or vaporization (l—amine solvent/hr or kg—amine solvent/hr).

For blended amine solvents, it is also suggested that aminedeg and amineemit should be quantified based on the individual amines in the blend. Eq. (44) can also be used for economic and environmental analysis of amine solvents as well as for design purposes during scaling up.

For simplicity amine loss can be quantified as amine disappearance per amount of CO2 produced/desorbed as shown in Eq. (45). This is applicable both in pilot plant studies and in semi—batch laboratory analysis. Eq. (46) can then be used to quantify the actual cost associated with amine make—up.

Aminei

loss —

ramine_dis rCO2_prod

make-up-cost

ramine-dis rCO2_ prod

(Costamine)

where; Aminemake-up_cost is the cost required for amine make—up (US$/tonne CO2).

Amine A •Amine B ♦Amine C

Aldeal Amine Solvents

(kg CO2/hr)

Fig. 23. Effect of rate of CO2 produced to rate of degradation of hypothetical amine solvents.

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

Cooling medium

Off Gas

Simulated Flue Gas

Off Gas

Absorption

Desorption

Fig. 24. Schematic of experimental set — up proposed for the study of amine degradation rate, regeneration energy and reclaiming energy analysis.

It is important to state that the rate (amine loss) should be divided by the shown in Eq. (45). This parameter will loss per CO2 produced which is a true loss or amine disappearance.

In order to quantify the contribution degradation and vaporization, Eq. (44) Eqs. (47) and (48).

of amine disappearance rate of CO2 produced as depict the actual amine representation of amine

of amine losses through can be broken down to

Amine,

deg-cost

rC02_ p,

Amine,

■vap^cost

I ramine_vap \ \ rC02.prod J

amine_ vap rC02-prod j

Costa,

where; Aminedeg_cost is the cost associated with amine degradation (US$/tonne CO2) while Aminevap_cost is the cost penalty due to amine losses through vaporization/emissions (US$/tonne CO2).

Fig. 23 displays the effect of amine loss and rate of CO2 produced for hypothetical amine solvents. From Fig. 23 it can be seen that at same amine loss (Amine A and Amine B) the amine with higher CO2 produced (Amine B) will be more beneficial, though the ideal amine is desired to have very low amine loss and a very high CO2 production rate. However, if only the amine loss is considered then hypothetical Amine C will be said to not be a good amine solvent, but if the rate of CO2 produced is taken into account Amine C will be preferred when compared to both Amine A and Amine B. This is because the degradation rate with respect to CO2 production rate of the hypothetical amines followed the trend Amine C (0.7 kg amine/kg CO2) < Amine B

(0.8 kg amine/kg CO2) < Amine A (1.3 kg amine/kg CO2). This trend is also applicable when amine loss due to either degradation or vaporization is considered.

All the cost and energy indices described and suggested above will be a good guide towards comparing the efficiency and acceptability of an amine solvent for CO2 capture when compared based on the same CO2 capture efficiency (90% CO2 capture) or/and based on the same amount of CO2 produced. These indices can also be used for scaling up design purposes.

3.10. Proposed experimental set—Up for amine solvent analysis

An experimental set—up for simultaneously investigating amine degradation rate, amine cost, regeneration energy and reclaiming energy is being proposed in this review paper (Fig. 24).

3.10.1. Experimental procedure

a) A determined volume of aqueous amine solution at the desired concentration is loaded into the glass reactor and then immersed into the well-insulated heating bath. The heating oil in the bath provides the heat for the experiment at the desired temperature (usually 40 °C for CO2 absorption). The level of the oil in the bath should cover at least three—quarters of the glass reactor (if the level of the sample in the reactor is at the half—way mark).

b) After the amine solution in the reactor has reached thermal equilibrium for absorption (40 °C) process, the simulated flue gas (CO2, N2, O2, H2O, SOx, NOx, fly ash) is injected into the reactor at a determined flow rate. The CO2 composition and the compositions of other

amine dis

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

impurities are also predetermined and should be constant throughout the experimental run. However, if impurities like SOx, NOx and fly ash are not available to be mixed with the simulated flue gas, they can be dissolved at the right concentration into the aqueous amine solution before the start of the experiment. Fly ash can be directly added to the amine solution while nitric acid (HNO3), sulphurous acid (H2SO3) can also be added to the amine solution to represent NOx and SOx respectively. In this case, the simulated flue gas will only contain (CO2, N2, O2 and H2O). Aqueous solutions of metals like Cop-per(ll) chloride (CuCl2), Iron(lll) chloride (FeCl3), Calcium Oxide (CaO), Aluminium Oxide (Al2O3) can be added (at the desired ppm concentration) to the amine solution to represent the metal content of the flue gas [242]. lron content can also be due to corrosion in the CO2 capture plant. These impurities should be well mixed with the aqueous amine solution prior to starting the absorption experiment. Other impurities can also be added to the amine solution to represent flue gas components.

c) A condenser is connected at the top exit of the reactor to limit amine losses through vaporization, which is achieved by using a cooling liquid set maximum at 7 °C.

d) Once the simulated flue gas is flowing through the amine solution, time is allowed for the solution to reach equilibrium with CO2. Equilibrium is attained when the dry CO2 composition exiting the condenser remains constant for at least 10 min.

e) Downstream of the condenser is a desiccant to dry any moisture content in the exiting vapor stream while the CO2 analyzer or gas chromatography with thermal conductivity detector (GC—TCD) measures the amount of CO2 in the dry vapor phase. Any of these instruments us used to confirm equilibrium.

f) The dry gas stream can also be connected to Fourier transform infrared spectrometer (FTlR) for online quantification of vaporized amine solvent etc.

g) Digital thermocouple (±0.1 °C accuracy) is used to measure the temperature of the amine solution and also the temperature of the wall of the reactor. A magnetic bar in the reactor provides the stirring during the experiment to ensure adequate mixing of the reacting components. The stirring speed (rpm) should be constant during all experiments and should not induce splashing on the inner wall of the reactor.

h) During the absorption experiment the second oil bath should be heated to the desired temperature for desorption which should be representative of the actual regeneration temperature (110—120 °C). Slightly lower temperatures (95—105 °C) can also be used depending on the purpose of the experimental study, most especially for low temperature desorption investigation.

i) At the end of the absorption experiment (equilibrium is attained) amine sample is taken for further analysis. The amine sample once taken is cooled in a refrigerator (about 10 °C) to stop any further reaction. Alternatively, the sample bottle containing the amine sample can be quenched in running cold water to bring down the temperature of the sample quickly for analysis. The analysis will cover CO2 loading, free amine concentration and possible degradation products (NH3, nitrosamine etc.). Then the reactor is transferred into the bath which is already at 95—120 °C for desorption process. For CO2 loading, the amine sample must be analyzed right away to avoid further error.

• Amine A ©Amine B

A Amine A A Amine B

0 20 40 60 SO 100

(% amine/hr)

Fig. 25. Degradation rate and desorption temperature of two hypothetical amine solvents.

j) Desorption can be allowed to run for at least same time duration as the absorption experiment to allow for a significant change in free amine concentration (degradation and amine vaporization) to occur and be easily quantified. At the end of the desorption experiment the reactor containing the amine solution is sent to a refrigerator (about 10 °C) to cool the amine solution and stop further degradation reaction. The sample temperature can also be quenched in running cold water as described previously. After then amine samples can be taken to analyse for CO2 loading, free amine concentration and possible degradation products (NH3, nitrosamine etc.). k) lsokinetic sampling method can be used to trap all carryover species (like free amine, NH3 and other degradation products) in the vapor phase [225—230]. This method can also be used to quantify amine losses through vaporization. Considering the initial amine concentration at the start of the experiment, amine losses through vaporization can then be applied towards determining amine losses through degradation. When amine losses through vaporization or degradation products are to be analyzed and quantified in the off gas, the isokinetic set—up should be installed upstream of the dryer (absorption section) to avoid trapping the major products in the vaporized amine solvent. A dryer is not required during the desorption experiment. Also in this case, the temperature of the cooling liquid can be increased to 10—20 °C. l) On the other hand, due to the very low temperature and high flow rate of the cooling liquid flowing through the condenser, vaporization losses (amine and H2O) can be assumed to be negligible (for simplicity). m) When salts of representative metals are added to the amine solution before CO2 absorption, then their disappearance in the liquid phase can also signify degradation.

Since the experimental set—up is a semi—batch process Eq. (49) which based on Fourier's law (heat transfer by conduction) can be used to determine the heat input during the desorption process which can be further used to quantify the heat of regeneration (heat duty) when divided by the amount of produced CO2 as shown in Eq. (30). Any correlation for determining heat input can also be used.

kA(dT)

where; Hin is the heat transferred to the amine solution (J/s), k is the thermal conductivity of the reactor (W/m oC or J/s.m. oC), A is

C. Nwaoha et al. / Petroleum xxx (2016) 1—27

the area of heat transfer (m2), dT is the temperature difference between the outer surface of the reactor and the amine solution in the reactor (°C) while d is the thickness of the reactor (m).

This proposed experimental procedure and analysis should be carried out at the maximum desorption/regeneration temperature (120 °C), thereby highlighting the actual condition of amine regeneration. Most studies [75,196,199—202,216,218] investigated amine degradation at desorption temperatures (up to 170 °C) higher than the actual temperature used in the industry (120 °C). Results from such experimental condition can misrepresent the degradation rate of an amine solution.

Fig. 25 depicts degradation rates of two hypothetical amine solvents at various temperatures. It shows that at desorption temperature of 120 °C the degradation rates of Amine A and Amine B was 20% and 30% respectively while at 170 °C the degradation rates of Amine A and Amine B became 60% and 90% respectively. If the results at 170 °C are to be considered then Amine B will be seen as not applicable for CO2 capture whereas results at 120 °C show that Amine B is competitive to Amine A.

4. Conclusions

The progress and prospects of blended amine solvents for CO2 capture from combustion processes has been extensively reviewed in this paper. Several studies (laboratory scale and pilot plant scale) has shown the potentials of blending amine solvents towards optimizing their CO2 absorption efficiency and decreasing their regeneration energy. Improvements are required in the degradation of blended amine solvents as well as emissions.

• Several new amine bi—solvent blends are currently being studied with the intention of out-performing the already existing single amines and bi—solvent blends. Considerable success is being achieved in this area and further studies are indeed needed.

• Amine bi—solvent blends though industrially applied have led to the study of tri—solvent and quad—solvent blends. It is believed that increasing the amine components in the blend can further improve its CO2 absorption—desorption capabilities. This has also been proven both in the laboratory and pilot plant scale where amine circulation rate has been reduced, increase in both CO2 absorption capacity and absorption rate, and regeneration energy reduced as much as 50%.

• Phase—split (phase—change or bi—phasic) solvent blends have also gained wide attention. More than a few researches have been done in this area and have reported increased cyclic capacity (bi—solvent blend) and reduction in the regeneration energy by 50% (tri—solvent). Studies are yet to be carried out in terms of their degradation rate and emissions.

• Amine volatility and emissions is integral in selecting the appropriate amine solvent for CO2 capture because most amine solvents are ecotoxic and not readily biodegradable. Amine solvents that are eco—friendly and biodegradable will go a long way towards protecting public health, environment and aquatic life from potential toxic risks. A previous study has given an indication that blending amine solvents can reduce the volatility of the amine solution. This paper also proposed that emerging amine blend formulations should be chosen in terms of their BOD and being eco—friendly. For example, a 60% BOD amine solvent can be blended with a 25% BOD amine solvent at blend ratio of 70—30% respectively, and/or an amine solvent with ecotoxicity below 10 mg/l should be blended with another amine solvent with ecotox-icity above 10 mg/l at 30—70% blend ratio respectively.

• Low boiling point amines could provide an alternative route towards reducing the energy of regeneration and also enhance amine reclaiming. A new term to be known as "simultaneous regeneration and reclaiming in the regenerator, S3R" might offer substantial benefits. Research should be carried out to specifically on this to specifically outline possible advantages and commerciality.

• Cost energy penalty indices explained and proposed in this paper will guide towards understanding the actual energy penalty and savings and cost of an amine solution for CO2 capture. When using the cost energy penalty indices, amine solvents should be compared based on a similar CO2 capture efficiency and/or same CO2 produced. The cost indices will also be very instrumental when scaling up from laboratory sized experimental set—up (e.g. semi—batch) to bench—scale pilot plants, large pilot plants and commercial CO2 capture plants.

• This review paper also proposed a new method and equations for estimating the reclaiming energy even when semi—batch experimental set—up are being used for analysis. This energy should also be compared to regeneration energy of amine solvents as this will provide vital evidence on the major contributor to the energy penalty. Future research should focus on determining this energy at small scale laboratory set up.

• A new experimental analysis is also proposed for investigating regeneration energy, reclaiming energy, amine cost and degradation rates of amine solvents towards CO2 capture. Taking into account these energy and cost penalties will be beneficial in selecting the appropriate amine solvent for CO2 capture.

• Studies conducted so far (on amine solvents) in all the CO2 capture performance metrics have given an indication that it might be ideal to synthesize a novel amine solvent that will contain all the desired structural properties (e.g. type of functional group and position). This technology can lead to the deployment of a single amine (polyamine) that can effectively compete with blended amine solution.

To enable easy transition from the already existing and industrially applied single and amine blends to newly developed blends, they must prove to be competitive (compared to 5 kmol/ m3 MEA) in their average overall mass transfer coefficient, kinetics (absorption rate), cyclic capacity (CO2 production), regeneration energy, degradation, reclaiming energy and total equivalent work (as described in this paper). The success of newly developed blends for post—combustion CO2 capture will aid towards developing the ideal solvent blends for CO2 capture from natural gas processing, and pre—combustion (gas to liquids, hydrogen production etc.) and oxy—fuel processes.

The breakthrough achieved so far portends a bright future towards developing the ideal solvent blend for CO2 capture from post—combustion and pre—combustion process systems and natural gas processing.

Acknowledgement

The financial supports from the Natural Sciences and Engineering Research Council of Canada (NSERC) to our CO2 Capture Research programs at the University of Regina, are gratefully acknowledged. In addition, this publication was made possible, in parts, by NPRP grant# 7 - 1154 - 2 - 433 from the Qatar National Research Fund (a member of Qatar Foundation). The statements made herein are solely the responsibility of the authors. The authors also gratefully thank Clean Energy

C. Nwaoha et al. / Petroleum xxx (2016) 1-27 23

Technologies Research lnstitute (CETRl) of University of Regina — [24 CANADA, Gas Processing Centre of Qatar University — QATAR, as well as the Petroleum and Petrochemical College of Chula- [25 longkorn University — THAlLAND, for their research facility supports.

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