Enhancement of CO2 Absorption in Water through pH Control and

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Cite This: Ind. Eng. Chem. Res. 2019, 58, 14275−14283

Enhancement of CO2 Absorption in Water through pH Control and Carbonic Anhydrase−A Technical Assessment Johanna Beiron,*,† Fredrik Normann,† Lars Kristoferson,‡ Lars Strömberg,† Stefanìa Ò sk Gardarsdot̀ tir,† and Filip Johnsson† †

Department of Space, Earth and Environment, Chalmers University of Technology, Göteborg S-412 96, Sweden ClimaCarb AB, Mosstorpsvägen 51, S-18156 Lidingö, Sweden

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‡

ABSTRACT: This paper provides an industrial-scale technical assessment of absorption of CO2 in water to react into bicarbonate (HCO3−), with the goal of storing HCO3− in the oceans as a carbon sequestration technology. A potential advantage of the process is that it will not require a CO2 transport and storage infrastructure that will be expensive for small-scale and remote emission sources. Process simulations are utilized to estimate absorber column length and for mass flow estimations of water and base required for a target capture rate of 90%. The results indicate that the process is technically feasible under specific conditions, with pH regulation being highly important, although the demand for base represents a limiting factor. Yet, a potential niche for the process is CO2 capture at smaller plants emitting small amounts of CO2.

1. INTRODUCTION Carbon capture and storage (CCS) is expected to play a significant role in mitigation efforts to meet the Paris Agreement of limiting global warming to well below 2 °C; the importance of CCS has been pointed out by IPCC.1 The need for CCS also follows from the fact that countries with large domestic reserves of fossil fuels tend to continue to use these, either to maintain energy security or for export, and this in spite of the fact that the cost of energy from renewables has fallen. As pointed out by Johnsson et al.,2 there are only two options for fossil fuels if complying with the warming targets: to leave these fuels in the ground or to apply CCS (and a combination of these two options). Because there are no or few signs that fossil fuels will be left in the ground, this puts a strong pressure on developing CCS technologies and assessing all CCS options, especially when it comes to the capture part, which is typically considered to represent the largest share of the overall CCS cost. There are several methods available for CO2 capture, of which absorption with amine solvents is a commercially available technology and absorption with pure monoethanolamine (MEA) is commonly regarded as a benchmark process, as reviewed by Wang et al.3 However, investment costs for MEA-based CO2 capture are strongly related to the amount of CO2 captured at the source; with plants that would capture more than 1000 kton/a having 2−4 times lower specific investment costs than plants with a potential capture of less than 100 kton/a.4 Furthermore, the associated costs for transport and storage of CO2 are not negligible; in a study by Gardarsdòttir et al.,4 these accounted for around 35% of the © 2019 American Chemical Society

total cost for CCS. For small- to medium-sized plants, it might therefore not be economically viable to invest in conventional MEA-based CCS. There is thus a need to develop alternative CO2 capture methods suitable for small-scale application if a zero-emission target is to be reached. Sweden is a present-day example of a highly industrialized region, having an energy system with close to zero CO2 emissions from power generation and a developed forest industry and infrastructure for biomass. Yet, Sweden struggles to identify a path toward a carbon neutral system. Figure 1 shows the total fossil CO2 emissions from Swedish plants in the industrial and heat- and power-generating sectors for 2016, with the plants ordered by the amount of CO2 emitted.5,6 The large point sources, including industries like iron and steel, refineries, and cement manufacturing, are important emitters and efforts are made to address these emissions. However, around 22% of the fossil Swedish CO2 emissions in 2016a significant shareoriginated from plants emitting less than 100 kton/a each, representing 203 out of 237 plants in totals. As the energy system develops toward carbon neutrality, the heat and power generation will be more diversified and the contribution from smaller emission sources will be more important. The specific cost for capturing CO2 (€/ton CO2) increases with decreased size of the emission source−although cost also depends on CO2 concentration in the stack on which Received: Revised: Accepted: Published: 14275

May 16, 2019 July 5, 2019 July 9, 2019 July 9, 2019 DOI: 10.1021/acs.iecr.9b02688 Ind. Eng. Chem. Res. 2019, 58, 14275−14283

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Industrial & Engineering Chemistry Research

Although a precondition for absorbing CO2 in water is that storage of HCO3− in oceans is a viable option, the potential consequences for marine ecosystems and the oceanic carbon cycle associated with increasing the amount of HCO3− in the ocean are unknown. As an example, Marubini and Thake11 found that the addition of bicarbonate to ocean water enhances coral growth, which could be positive for marine calcifying organisms. However, if large-scale introduction of HCO3− into the oceans causes the amount of dissolved CO2 to increase, through increased absorption of atmospheric CO2 in the ocean or conversion of HCO3− to CO2, this could have a negative impact on marine life, as some species are sensitive to ecosystem disturbances and high CO2 levels.10 But, as the CO2 partial pressure in the atmosphere increases as a result of increased anthropogenic emissions, more CO2 will be dissolved in the oceans and the CO2 equilibrium between the oceans and atmosphere will shift to higher CO2 levels.10 Thus, marine ecosystems may be at risk regardless. Further research is required to clarify these issues. Nevertheless, the opportunity to avoid transportation and storage costs could be important for the economic viability for small-scale CCS implementations, for which the specific cost for transportation could be high unless it can be coordinated with other larger plants. Furthermore, with respect to “traditional” CCS, a costly part is the significant energy demand required. For the MEA-cycle up to 80% of the operating costs are linked to solvent regeneration.12 A once-through process configuration could therefore be a less costly option and enable the use of, for example, seawater as a solvent. Ma and Yoon13 studied CO2 absorption in salt water solution with magnesium ions to estimate the potential to use seawater for CO2 capture, whereas Li et al.14 measured CO2 solubility in seawater and found that seawater with added CaO could greatly enhance CO2 capture. Dziedzic et al.15 showed that NaOH enhances CO2 absorption in water. In addition, K2CO3 has been studied in this regard.16−19 Solutions with calcium carbonate dissolved in water have also been considered, with experimental testing of reactor setups,8,20 and cost estimations.7 However, the CO2-absorption rates of alternative solvents tend to be inferior to that of MEA. To enhance the kinetics of CO2 absorption processes, experimental studies in which the solvent is promoted with carbonic anhydrase (CA) have been performed, with promising results (for example,16,21−23). CA is an enzyme that is present in virtually all living organisms, in which it catalyzes the reversible hydration of CO2 to bicarbonate, HCO3−, thereby increasing the reaction rate. The enzyme kinetics have been quantified,17,19,24,25 and the reaction mechanism has been summarized by others.12,26 The direction of the reaction is pH-controlled:21,27,28 under alkaline conditions HCO3− is produced, whereas in acidic to neutral pH solutions, CO2 is generated. Alkaline solvents, such as water enhanced with a mineral base, thus have potential for application in CO2 capture processes enhanced with CA. CA-based enzymatic reactive CO2 absorption has been studied in lab-scale stirred-cell reactors to experimentally determine reaction rate constants17,19,29 that are important for estimation of equipment dimensions. Upscaling to bench- and pilot-scale testing in absorber columns has also been reported with subsequent development of process models30 and longterm evaluation of CA thermo-stability.18 The methods developed for the application of CA in industrial processes and reactors have been summarized by Russo et al.26 Typically,

Figure 1. Cumulative CO2 emissions from Swedish industry and heatand power plants (kton/a) for 2016, where the plants are ordered by annual CO2 emissions [kton/a]. Plants emitting less than 1 kton/a have been omitted. Plants emitting less than 100 kton/a account for around 22% of total emissions.

capture is applied. Thus, there is a need for carbon capture technologies that are low cost and easy to implement and operate, and all types of capture technologies must be considered. In line with this, the focus of this work is a process that could be used for separation of CO2 from flue gases at smaller point sources by absorption in water, and the enhancement of this process through the use of a pH-controlling base and a catalyzing enzyme. Figure 2 illustrates the process idea in

Figure 2. Process overview of ”conventional” CCS and the process considered in this study, highlighting the major steps and differences between the processes.

comparison to “conventional” CCS. Contrary to what is commonly proposed, i.e., to transport and store the captured CO2 gas in geologic formations, this study considers the storage of CO2 in oceans in the form of aqueous bicarbonate, HCO3−, as proposed by, for example, Rau and Caldeira.7−9 This process is based on the assumptions that CO2 is converted to HCO3− under controlled conditions in a reactor system, and that the aqueous HCO3− can be stably dissolved in oceans. This should not be confused with earlier attempts at ocean storage by dissolving CO2 directly in the seawater at great depths (see, e.g., ref 10). 14276

DOI: 10.1021/acs.iecr.9b02688 Ind. Eng. Chem. Res. 2019, 58, 14275−14283

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Industrial & Engineering Chemistry Research the enzyme is used as a “free” catalyst dissolved in the solution16 or immobilized onto a solid structure,31 for example, column packing material.32 Immobilization of the enzyme was recommended to increase enzyme longevity.18 Combining the ideas presented here, the use of water, together with an alkaline agent and CA, to capture CO2 and convert it to HCO3− for subsequent storage in oceans may, thus, represent a competitive CCS technology for comparatively small point sources, having a relatively low energy penalty. This work applies the present understanding of the involved chemistry to assess the industrial feasibility of such a CO2 capture process. The study provides a description of the process considered, where three process concepts (or pathways) are identified and compared based on kinetics and process simulation. The process is applied to four industrial plants where CO2 capture could be employed, for estimations of mass flow rates and identification of challenges for practical implementation of the process.

Figure 4. Compositions of the dissolved inorganic carbon (CO2, HCO3− and CO32−) at different pH levels in water. Based on data from the Aspen Plus database.

2. PROCESS DESCRIPTION The CO2 capture process separates CO2 from flue gases by absorption into pH-controlled water, promoted by a mineral carbonate or hydroxide base. The absorbed, dissolved CO2 reacts to bicarbonate, HCO3−, which is a stable ion in solution at a pH of around 8. The process setup is illustrated in Figure 3. The CO2 capture process takes place in an absorber, where

that the stream pH matches the pH of the water recipient by dimensioning the amount of base added to the absorber water.

Figure 5. Overview of the two-step CO2 capture process, including the three process concepts (A, B, and C) investigated and the process end-products.

Figure 3. Illustration of the overall CO2 capture process and the model used in simulations.

the pH-controlled water is brought into contact with flue gases containing CO2. The water stream is mixed with an alkaline base containing hydroxide or carbonate anions in a mixing vessel upstream of the absorber. The base anions control the pH of the water, thereby directing the CO2 conversion toward HCO3− production. Carbonic anhydrase (CA) can be immobilized in the absorber to catalyze the conversion of CO2 to HCO3− and may thereby increase the reaction rate. The exiting streams from the absorber are a gaseous CO2-lean stream and a liquid stream rich in HCO3− and mineral cations. The CO2-lean flue gas is vented through a stack, whereas the liquid effluent is assumed to be released into a water recipient, for example, the ocean, for storage as HCO3−. CO2 dissolved in water is in equilibrium with two other forms of dissolved inorganic carbon (DIC): HCO3− and CO32−. Figure 4 shows the distribution of DIC mole fractions as a variable of the pH level in water. A pH value of about 8 maximizes the mole fraction of HCO3−, which also coincides with the approximate pH level in the oceans. To release the liquid absorber effluent into the ocean, it is therefore important

Reaction-wise, the CO2 absorption process consists of two steps, as illustrated in Figure 5. In the first step, gaseous CO2 is dissolved in water. CO2 (g) ↔ CO2 (aq)

(R1)

In the second step, the dissolved CO2 is reacted to form HCO3−. Three reactions (R2a−R2c) are possible for the conversion of CO2 to HCO3−:27 CO2 (aq) + H 2O(l) ↔ HCO−3 (aq) + H+(aq) −

CO2 (aq) + OH (aq) ↔

HCO−3 (aq)

(R2a) (R2b)

CA

CO2 (aq) + H 2O(l) ← → HCO−3 (aq) + H+(aq)

(R2c)

33

As the dissolution of CO2 in water (R1) is rapid, the overall reaction rate of the CO2 capture and conversion process will be limited by the reaction rate of step 2 (R2a−R2c). Each of Reactions R2a-R2c could be applied in the absorber for CO2 conversion, albeit under specific conditions. Reaction R2a predominates in acidic-to-neutral solutions, whereas Reaction 14277


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Industrial & Engineering Chemistry Research 3.2. Modeling of involved in the process model as equilibrium categorized in Table 1.

R2b is dominant under alkaline conditions, where hydroxide is abundant.34 Reaction R2c is a catalyzed version of Reaction R2a, in which CA increases the rate of reaction. These three reactions can be represented by three process concepts, or pathways, as shown in Figure 5:

Table 1. Reactions Defined for the Absorber Model. Reactions R2a−R2c is Used, Together with Reactions R3 and R5

• Concept A: Reaction with H2O through Reaction R2a. The pH control is mediated by carbonate bases, such as CaCO3 or Na2CO3. • Concept B: Reaction with OH− through Reaction R2b, in which CO2 reacts with hydroxide. The base added for pH regulation is a hydroxide base, for example, NaOH. • Concept C: CA-catalyzed reaction with H2O based on Reaction R2c, in which CA catalyzes the reaction of CO2 with H2O. Both hydroxide and carbonate bases can be used for pH control, because the anions themselves do not participate in the catalytic mechanism.

reaction R2a R2b

(R3)

OH−(aq) + H+(aq) ↔ H 2O(l)

(R4)

H 2O(l) ↔ H+(aq) + OH−(aq)

(R5)

formula

CO2 (aq) + H 2O(l) ↔

CO2 (aq) + OH (aq) ↔ CA

CO2 (aq) + H 2O(l) ← →

R3

HCO−3 (aq)

↔

type

HCO−3 (aq)

−

R2c

R5

All the concepts involve pH control through the addition of a base to the water: the base anions, CO32− or OH−, react with the acidic H+ according to Reactions R3 and R4, thereby maintaining the pH level. The water dissociation reaction, Reaction R5, is included for completeness. Independent of the reaction applied in step 2, the process end-product is the same, namely, a water stream that contains HCO3− and base cations. CO32 −(aq) + H+(aq) ↔ HCO−3 (aq)

Reaction Kinetics. The reactions are included in the RadFrac column reactions or kinetic reactions as Reactions R3 and R5 are defined as

+ H (aq)

HCO−3 (aq)

HCO−3 (aq)

CO32 −(aq)

+

kinetic +

+ H (aq)

+

+ H (aq) equilibrium

+

H 2O(l) ↔ H (aq) + OH−(aq)

equilibrium reactions, with equilibrium constants, Keq, computed using built-in correlations in Aspen,35 on the form displayed in eq 1. α, β, and γ are parameters from the Aspen database. The water dissociation and bicarbonate equilibrium reactions are fast relative to the time-scale for CO 2 equilibrium,34 which motivates the assumption that Reactions R3 and R5 reach equilibrium. Reactions R2a−R2c are modeled as kinetic reactions of the Arrhenius form (eq 2), with both forward and reverse reactions being defined. For each reaction the rate constant, k, is computed based on the pre-exponential factor, A; the activation energy of the reaction, Ea; the ideal gas constant, R; and temperature, T. ln Keq = α +

3. METHOD 3.1. Model of Capture Process. The capture process shown in Figure 3 is modeled in Aspen Plus ver. 8.8. The process design considered in this work is an absorption column reactor that provides a large surface area for gas−liquid contacts, which favor the absorption of CO2. CA is assumed to be immobilized on packing material in the column. Research has experimentally validated an enzyme immobilization approach for packed columns, with granular CA in mesh pockets of Sulzer Katapak-SP.30 Seeing as a once-through process is considered here, use of CA as dissolved in the solvent is not modeled. The absorber column is modeled with the RadFrac unit, as a rate-based packed column with 20 stages of standard Sulzer Mellapak 250Y. The column diameter is adapted to a maximum flooding rate of 80%, and set to 8 m with a liquid velocity of 0.02 m/s and a gas velocity of 0.78 m/s. The Bravo et al. (1985) correlation included in Aspen is used as interfacial area and mass transfer coefficient method; while the holdup method used is according to Bravo et al. (1992). The mass transfer between the gas and liquid phases is modeled based on the two-film theory, with standard settings. Mass transfer between the liquid and solid surfaces is not included in the model. The column has neither a reboiler nor a condenser. The defined reactions (see Section 3.2) are assumed to take place at all stages in the absorber. The built-in electrolyte nonrandom two-liquid (NRTL) method is used to compute the physical properties, and the true components approach is applied for electrolyte reactions. The mixing vessel depicted in Figure 3 is modeled as an adiabatic equilibrium reactor (Gibbs free energy minimization).

β + γ ln(T ) T

(1)

i E y k = A expjjj− a zzz k RT {

(2)

In practice, Reactions R2a and R2c do not follow the Arrhenius equation; enzyme kinetics are generally better described by Michaelis−Menten kinetics.17,19 However, for the purpose of simulations all reaction kinetics are simplified and fitted to eq 2, which is the standard option in the RadFrac column for modeling of kinetics. The parameter values for A and Ea are given in Table 2. For Reaction R2b, which follows the Arrhenius equation, the parameter values are obtained from Pinsent et al.36 For Reaction R2a, the rate constant correlations from Roy et al.37 and Johnson,38 are fitted to the Arrhenius form in the temperature interval of 15°−35 °C using the least-squares method, with a fit (R2 value) of 0.9947. For Reaction R2c, the parameter values are taken from,30 in which Table 2. Kinetic Parameters for Computation of the Rate Constants for Reactions R2a−R2caa R2a R2ar R2b R2br R2c R2cr

Ea (kJ mol−1)

A

reaction 2.01 2.65 4.32 2.38 2.01 2.65

× × × × × ×

109 (dm3 mol−1 s−1) 1012 (dm3 mol−1 s−1) 1013 (dm3 mol−1 s−1) 1017 (s−1) 109 (dm3 mol−1 s−1) 1012 (dm3 mol−1 s−1)

61.40 45.86 55.47 123.30 47.41 115.25

ref 37,38 37,38 36 36 30 30

The Arrhenius equation is used, k = Aexp(−Ea/RT). The term ‘r’ denotes a reverse reaction.

aa

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not considered. The water is assumed to be pure. All inlet streams are at a temperature of 15 °C and a pressure of 1 bar. 3.3.2. Technical Assessment of Industrial Application. On the basis of the results presented in Section 4.1, Concept B is selected for application to four industrial plants emitting CO2. The plants are the waste-fired combined heat and power (CHP) plant Lillesjö in Sweden, the Yara ammonia factory in Norway, the coal-fired CHP plant Nordjyllandsværket (NJV) in Denmark, and the geothermal CHP plant Hellisheidi in Iceland. Lillesjö, Yara, and Hellisheidi represent comparatively small plants, whereas NJV is included as a reference case for larger plants. The relevant process data for the plants are given in Table 5. Note the high flue gas pressure and CO2 concentration of Yara and Hellisheidi. On the basis of the respective mass flows of flue gases at each plant, the mass flows of water and NaOH are obtained for a target CO2 capture of 90%, with a liquid effluent containing the aqueous end-products HCO3− and Na+ at a pH of 8. All absorber reactions are assumed to reach equilibrium and NaOH is used for pH control. Furthermore, simulations are preformed to analyze how water and NaOH mass flows are influenced by a varying target for CO2 capture rate (partial capture40), in the interval 10−90% capture.

experimental data from CO2 absorption in MDEA solution with immobilized CA was used to fit the reaction rate constant to the Arrhenius form. The CA was of microbial origin and considered suitable for application in reactive absorption due to its stability; and the weight fraction of immobilized CA available during the experiments was estimated to 0.038%.30 It should be noted that immobilization of the enzyme entails an additional mass transfer resistance to the enzyme surface which might have a negative impact on the reaction rate. Penders-van Elk et al.23 argue that the slow mass transfer through the liquid film surrounding the immobilized enzyme will lead to negligible enhancement of the reaction rate, as it will take time for the CO2 to traverse the film and reach the enzyme for its conversion. However, if kinetics, rather than transport phenomena, are rate-determining, which may be the case for the carbonate/bicarbonate solutions studied here, the enzyme can have an enhancing effect on the overall capture efficiency.23 Larachi et al.32 experimentally compared the performances of dissolved CA and CA immobilized on column packing material, and found that immobilized CA outperforms raw packings in terms of CO2 conversion, although dissolved CA is superior to immobilized CA. Russo et al.26 and Yadav et al. 39 summarize studies on the development of CA immobilization, further emphasizing the need for additional studies of mass transfer, the materials for immobilization, and multiphase contacting concepts, so as to realize the potential of CA. 3.3. Simulations. 3.3.1. Comparison of Concept Reaction Rates. The three concepts presented in Section 2 are compared based on the rates of the concept-defining Reactions R2a−R2c. The reaction rate affects the required equipment dimensions for a specific separation rate and is, thus, a key factor to assess. The process concepts are simulated with the setup defined in Section 3.1, and with the reaction sets presented in Table 1 applied in the absorber. For each concept, a set of three reactions is defined according to Table 3.

4. RESULTS 4.1. Comparison of Reaction Kinetics and Packed Column Length. The total lengths of column packing required for a capture rate of 90% are presented in Figure 6 for Concepts A−C. The total column length could either be in one cohesive segment or divided into a multicolumn configuration. There are distinct differences in the computed lengths required. Concept C reaches 90% capture at a packed height of 40 m, whereas Concept B requires about 100 m and Concept A needs 1300 m (e.g., 10 columns, each 130m in height). The column length required for Concept A is in line with previous work, as Penders-van Elk et al.23 reported that for 90% CO2 capture, the commercial column height approaches 800 m for the noncatalyzed reaction with H2O. For Concept B, 100 m is at the extremity of what is practically feasible unless a multicolumn design is applied. However, as seen in Figure 6, a packed height of around 40 m would suffice for a capture rate of 80% under the specified conditions. Clearly, Concept A with Reaction R2a, which is the predominant reaction in oceans, does not provide fast enough CO2 conversion on its own for the concept to be viable, but the use of CA in Concept C could enhance the rate of this reaction. It should, however, be noted that in these computations the liquid-phase mass transfer has been neglected, which might be an important factor to consider in the case of enzyme immobilization, see Section 3.2. Given that the kinetics of Concepts B and C could be feasible for practical implementation and that equilibrium can be reached for reasonable column sizes, the assumption made in Section 3.3.2 regarding the included reactions reaching equilibrium is justified. Thus, for the technical assessment cases (Section 3.3.2), no distinction is made between the concepts or the catalyzed/noncatalyzed reactions; it is assumed that kinetics is not the limiting factor for the process, and that acceptable results are achievable both with and without enhancement by CA (Concept B or C). 4.2. Technical Assessment−Mass Flow Estimations. The estimated process mass flows in the four industrial-scale capture cases (Table 5) are summarized in Figure 7a, b. The

Table 3. Sets of Reactions Defined for Simulation of Each Concept concept

reactions in absorber

A B C

R2a, R2ar, R3, R5 R2b, R2br, R3, R5 R2c, R2cr, R3, R5

For the simulations, the base used for pH control is NaOH; a common and strong base that ensures adequate pH regulation. The input mass flows of water and NaOH are dimensioned for a CO2 capture rate of 90%. For example, a flue gas flow of 50 kg/s results in 1000 kg/s of water and 9.3 kg/s NaOH. The flue gas composition, as specified in Table 4, is representative for a typical coal-fired power plant. Trace species, such as nitrogen oxides, sulfur oxides, and particles, are Table 4. Flue Gas Composition Used in the Absorber Model species

mol %

N2 CO2 H2O O2

80 16 2 2 14279


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Industrial & Engineering Chemistry Research Table 5. Plant Data for the Four Industrial Cases Considered in the Technical Assessment parameter plant type flue gas flow (kg/s) flue gas pressure (bar) flue gas inlet temp. (C) water inlet temp. (°C) CO2 flow (kg/s) flue gas composition (vol %) CO2 H2O N2 O2 H2 H2S ref

Lillesjö

Yara

Hellisheidi

Nordjyllandsværket

waste CHP 25 1 50 15 5.32

ammonia industry 22 26 50 10 11.95

geothermal CHP 0.4 5 20 20 0.33

coal CHP 370 1 56 15 80

14.6 4.5 73.7 7.2 0 0

18.9 1.2 19.9 0 60 0

77.8 0 6.7 0 0 15.5

14.4 8.8 73.9 2.9 0 0

41

42

43,44

45

Figure 7a presents the absolute water and NaOH flow rates. Relatively low flow rates are found for all cases but NJV, which obviously requires higher flow rates because of the larger flue gas, and CO2, flow at the plant (resource consumption being proportional to CO2 captured). To put the numbers in perspective, the condenser water flow rate (in this case, district heating water) at Lillesjö is in the order of 150 kg/s41 and 13,400 kg/s at NJV.45 On the basis of the results, and assuming an operating time of 7000 h/a, the annual demand for NaOH at Lillesjö would be 0.1 Mton/a for a capture rate of 90%. Currently, the global annual production of NaOH is around 60 Mton/a. Thus, a non-negligible share of the available NaOH production would be consumed if only one, relatively small, power plant implements the process. Figure 7b compares the cases based on material per CO2 mass flow ratios. The results suggest that the water demand is affected to a greater extent than the NaOH consumption by plant specific operating conditions, such as pressure and temperature. The mass ratio of NaOH/CO2 is similar for all the cases, with slightly increased values for the pressurized conditions at Yara and Hellisheidi; which may reflect their considerably higher CO2 partial pressures that cause increased absorption of CO2 in the water, so that more base is required to stabilize the pH level. The H2O/CO2 ratio varies more

Figure 6. Fraction of CO2 captured as a function of packed column length for the three concepts studied. Equilibrium is reached when no further increase in capture is observed. The column diameter is 8 m and the target capture rate 90%.

computed water and NaOH flow rates correspond to the materials required to capture 90% of the inlet CO2 given the plant operating conditions, and to achieve an effluent pH of approximately 8. The mass ratios of water and NaOH per kg of captured CO2 are displayed for comparison of the cases.

Figure 7. (a) Absolute flow rates of water and NaOH for the four cases, with CO2 capture rate of 90%. (b) Comparison of the H2O/CO2 and NaOH/CO2 mass flow ratios of the different plants. 14280


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Especially so with the use of NaOH, which is expensive to manufacture with the electricity-intensive chlor-alkali process. While the production could be increased to accommodate an increased demand for base, H2 and Cl2 gases are also obtained from the chlor-alkali process, so there needs to be a market for these chemicals to justify higher production levels. In addition, electrochemical approaches are generally costly; but in a future scenario with a surplus of electricity at times (leading to lower electricity prices), technologies based on electrochemistry may become increasingly interesting. Other bases could also be considered for pH control, as long as their solubility in water is sufficient and the anion is a hydroxide or carbonate (Section 2). Waste materials have been investigated as sources of minerals for CO2 capture processes,28,47,48 as has the use of brines;15,33 although if the effluent is to be disposed in, for example, oceans, care should be taken to avoid emission of species that are not naturally abundant in water bodies. Alternative options for pH management could be considered, for example, Aines et al.49 suggested ion pumping (reverse osmosis) for regulation of the HCO3− concentration.

significantly between the cases; again highlighting the effect of pressurization as the flow ratio is several-fold lower for Yara and Hellisheidi than for the cases operating at ambient pressure. H2O/CO2 flow ratios of some 100 kg/kg could be realistic for power plants if condenser water can be utilized in the absorption process. Typical condenser water flow rates are in the region of 150 kg H2O/kg CO2, which would be sufficient for all the cases. To put the results in perspective, for an MEA cycle that is adapted to NJV, the H2O/CO2 ratio is approximately 15 kg H2O/kg CO2,46 as compared to the 86 kg/kg for the studied process. In contrast, the ratios for Yara and Hellisheidi (7 and 10 kg/kg, respectively) are lower than those in the NJV-MEA case. Figure 8 illustrates how the flow rates of NaOH and water vary with target CO2 capture rate for the Lillesjö case. The flow

6. CONCLUSION A carbon capture process that absorbs CO2 in water and converts it to HCO3− in an absorption column, with subsequent storage of HCO3− in the ocean, is studied. The following points sum up the main findings: • The utilization of carbonic anhydrase to increase the CO2 conversion reaction rate (Concept C) could enhance the process if the enzyme is efficiently immobilized in the absorber. On the other hand, an alternative, noncatalyzed, reaction path (Concept B, involving OH− anions) could also be feasible. • The associated water and base mass flows were computed for industrial-scale settings. The water flow rates are within an acceptable range. However, the consumption of alkaline base required for capture of large amounts of CO2 is a limitation. Yet, the process could represent a feasible alternative for smaller units emitting lower amounts of CO2, or niche applications with suitable operating conditions (e.g., high CO2 concentration in flue gases), but the process is likely not a favorable option for large plants, such as the coalfired CHP assessed in this work. • Partial capture of CO2 could be an option to reduce utility demands for units that are not required to reach CO2 capture rates as high as 90%.

Figure 8. Variations in NaOH and water flow rates as a function of the CO2 capture rate for the case of Lillesjö, with a fixed flue gas flow of 25 kg/s containing 14.6 mol % CO2.

rates are adjusted for an effluent pH in the range of 8.04−8.07. For a fixed flue gas flow, the required flow rates of NaOH and water are linearly dependent upon the fraction of CO2 captured, with higher mass flows required for higher capture rates. Furthermore, NaOH has the strongest effect on the capture rate, whereas the flow of water mainly has an impact on the pH value of the effluent.

5. FEASIBILITY OF THE CAPTURE PROCESS On the basis of the obtained results, the process considered appears to be both theoretically and technically feasible, albeit under certain conditions, including the availability of large volumes of water, a high CO2 partial pressure in the flue gas, and promotion of the water with an alkaline base for pH management. It seems as if the process can have a niche for smaller emission sources that will result in reasonable mass flows of water and base. As mentioned in the introduction, there might be a considerable number of comparatively smaller plants that could have a need for a less costly CO2 capture method than the MEA-process, if strict emission targets are to be reached. For such plants, the specific cost of transport and storage infrastructure, which are not needed for the process investigated, may be more challenging than for large emission sources. Furthermore, the process is especially interesting for applications where either pressurized gas flow is feasible, or the flue gas mole fraction of CO2 is high, allowing lower water consumption compared to ambient columns. However, the concept could be challenging for large-scale plants, beause of the high mass flows of base required.

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AUTHOR INFORMATION

Corresponding Author

*Email: [email protected] (J.B.). ORCID

Johanna Beiron: 0000-0002-6710-2728 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This work is a part of the CO2stCap project funded by the Norwegian CLIMIT−Demo program via Gassnova, The Swedish Energy Agency, and participating industry and research partners. 14281


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