Review of fundamental properties of CO2 hydrates

Renewable and Sustainable Energy Reviews 53 (2016) 1273–1302

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Renewable and Sustainable Energy Reviews journal homepage: www.elsevier.com/locate/rser

Review of fundamental properties of CO2 hydrates and CO2 capture and separation using hydration method Z.W. Ma a, P. Zhang a,n, H.S. Bao b, S. Deng c a

Institute of Refrigeration and Cryogenics, MOE Key Laboratory of Power Machinery and Engineering, Shanghai Jiao Tong University, Shanghai 200240, China Sir Joseph Swan Centre for Energy Research, Newcastle University, Newcastle upon Tyne NE1 7RU, UK c Key Laboratory of Efficient Utilization of Low and Medium Grade Energy (Tianjin University), Ministry of Education of China, Tianjin 300072, China b

art ic l e i nf o

a b s t r a c t

Article history: Received 15 November 2014 Received in revised form 13 July 2015 Accepted 13 September 2015 Available online 10 November 2015

Hydration is an alternative promising method for CO2 capture and separation from either post-combustion flue gas or pre-combustion fuel gas. The present paper gathers the researches on CO2 hydrate and the hydrates of gas mixtures of CO2 þN2/H2/CH4, including studies of fundamental thermo-physical properties, molecular structures and hydrate formation equilibrium conditions. Some promoters, i.e. quaternary ammonium salt etc. are usually used in CO2 hydration process to reduce the hydrate equilibrium pressure and to enhance the hydrate kinetic and stability, hence their promotion effect on CO2 hydrate and on the hydrates of gas mixture of CO2 þ N2/H2/CH4 are reviewed. The paper also summarizes the applications of hydrate technology in CO2 capture and separation, and the corresponding performance is summarized and the bottlenecks are discussed. It necessitates more works to promote this technology towards industrial application. & 2015 Elsevier Ltd. All rights reserved.

Keywords: CO2 hydrate Capture and separation Promoters Gas mixture

Contents 1. 2.

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Molecular structures, phase equilibrium data and thermo-physical properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1. CO2 hydrate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2. Clathrate hydrates of tetraalkylammonium salt and others . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3. Hydrates of CO2 with promoters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.1. CO2 þTHF double hydrate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.2. CO2 þTBAB double hydrate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.3. CO2 þTBPB double hydrate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.4. CO2 þTBAC/TBAF/TBPC/TBANO3 double hydrates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4. Hydrates of CO2 with other gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.1. Hydrates of CO2 þ N2 and CO2 þN2 þ promoters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.2. Hydrates of CO2 þ H2 and CO2 þ H2 þ promoters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.3. Hydrates of CO2 þ CH4 and CO2 þ CH4 þ promoters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3. CO2 capture and separation performance by hydrate technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1. Performance parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2. CO2 capture and separation performance from CO2 þ N2 gas mixture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3. CO2 capture and separation performance from CO2 þ H2 gas mixture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4. CO2 capture and separation performance from CO2 þ CH4 gas mixture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acknowledgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

n

Corresponding author. Tel.: þ 86 21 34205505; fax: þ86 21 34206814. E-mail address: [email protected] (P. Zhang).

http://dx.doi.org/10.1016/j.rser.2015.09.076 1364-0321/& 2015 Elsevier Ltd. All rights reserved.

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Z.W. Ma et al. / Renewable and Sustainable Energy Reviews 53 (2016) 1273–1302

1. Introduction CO2 as a greenhouse gas is considered to be the major contributor to the global warming. According to the report of Intergovernmental Panel on Climate Change (IPCC), the predicted CO2 concentration in the atmosphere will be 575–950 ppmv (parts per million by volume) in no-limitation case by 2100 and will continue increasing rapidly, while the present concentration is about 400 ppmv. As a consequence, the global mean temperature will elevate 0.7–4 °C while the global sea level will rise 10–100 cm [1]. Such catastrophic consequence indicates that CO2 capture and storage (CCS) becomes more and more essential and urgent. Fossil fuel combustion, such as in coal power plant, cement industry, steel-making industry as well as petrochemical industry and so on, accounts for about 75% current anthropogenic CO2 emissions [2], 85–95% of which can be captured by available CCS technology. Power generation is the single largest source of CO2 emission. Depending on different plant configuration, CO2 can be captured at different stages of the power generation, like postcombustion capture, pre-combustion capture and oxyfuel combustion capture [3–8], as shown by the schematic process of each type in Fig. 1. Post-combustion CO2 capture separates CO2 from the flue gas at the downstream of fuel combustion. The typical flue gas in power plant contains about 3–15 mol% CO2 at near atmosphere pressure and around 200 °C [5]. Such low CO2 concentration indicates a large volume gas to be handled, leading to a large scale of equipment and

high investment. The rest in the flue gas is mainly N2 with large quantity of impurities like dusts, SOx and NOx which pose another challenge for CO2 capture. The other major disadvantage of postcombustion capture is the large thermal energy input required by CO2 regeneration. In pre-combustion process such as integrated gasification combined cycles (IGCC), fuel reacting with oxygen or air firstly is gasified to synthesis gas that contains mainly hydrogen and carbon monoxide, afterwards the synthesis gas passes through a catalytic reaction where CO reacts with steam and generates CO2 and more H2, as shown in Fig. 1. The IGCC synthesis gas typically contains 30–45 mol% CO2 with hydrogen at a pressure range from 2.5 to 7.0 MPa. Alternatively, if the natural gas is used as the fuel, the synthesis gas would contain 15–25 mol% CO2 [6]. Therefore, comparing to post-combustion, pre-combustion capture engages with relatively higher CO2 concentration and higher pressure, resulting in the smaller scale of the equipment and less energy input. However, the pre-combustion capture is somewhat disadvantaged for the factors that the initial fuel conversion processes are sophisticated and costly, and the syngas temperature is typically around 400 °C which requires cooling energy input for some capture methods, like amine scrubbing technology [7]. The oxyfuel combustion uses nearly pure oxygen instead of the air for fuel combustion and power generation so that it yields very high CO2 concentration in the flue gas which is free of NOx and dominant with CO2 and water. After simple condensation to remove water, CO2 concentration in dry gas is approximately 90 mol%, which eliminates the further separation.

Fig. 1. Schematic processes of different CO2 capture technologies, (1) pre-combustion, (2) post-combustion, and (3) oxyfuel combustion [5].


Although the cost of CO2 capture in oxyfuel combustion is low and the generation of NOx is avoided, the air pre-treatment of gas separation to obtain pure O2 is significantly energy-intensive; moreover, this technology is still at the early stage of development. CO2 capture technology up to date can be primarily categorized as absorption, physical and chemical adsorption, membrane technology and cryogenic process [3–8]. Amine-based absorption solutions, such as monoethanol amine (MEA), are considered as the most mature solvents for CO2 capture, and the technology has been developed for more than 60 years and commercialized and applied across the industrial sectors. Amine scrubbing technology shows very high reaction rate and high CO2 capture capacity, and it is suitable for retrofit. However, it suffers from several disadvantages: large energy penalty for regeneration, additional compression work requirement for the following CO2 transportation and storage (due to the ambient gas pressure after regeneration), high equipment corrosion rate, degradation of amine, and negative environmental impact of solvent emission. Apart from amine-based solution, ammonia solution is another option of chemical solvent for CO2 capture, and it has attracted significant attentions due to its large CO2 loading capacity and additional capture of other acid gases like NOx and SOx without the presence of corrosion and degradation. However, its large-scale application is still in uncertainty. Solid materials with high surface area and pore structure have the capacity to adsorb gas through intermolecular forces. The different sorption conditions for different gases endow sorbent the ability to selectively adsorb gas and separate gas from a mixture. Typical physical sorbents for CO2 capture include zeolite, activated carbon, metalorganic framework and so on, which can perform at high temperature, hence, such physical adsorption process dismisses additional cooling device to reduce the syngas temperature. Comparing to liquid aminebased solvent, the regeneration of physical sorbent could be achieved either by rising temperature (temperature swing adsorption method, TSA) or reducing pressure (pressure swing adsorption method, PSA). PSA method is preferable in the industrial application because it avoids the inefficient heat transfer between solid sorbent and heat transfer fluids (liquid or gas) and eliminates the usage of heating and cooling devices, therefore the energy consumption for regeneration is less. Furthermore, the CO2 regenerated at high pressure benefits its transportation and storage. However, physical adsorption technology faces challenges in handling solid, relatively low CO2 selectivity, low adsorption rate, and the material degradation in cyclic operation. Due to its favorable porous structure, physical sorbent can be used as skeleton for other CO2-capture material, like amine, chemical adsorbents and so on, and the combination makes the capture more effective and reliable. Aside from physical sorbents, there is another type of sorbent capturing CO2 via chemical reaction so that it can be called chemical sorbent. Typical chemical sorbents include alkali metal oxides, like CaO, MgO, alkali metal hydroxides, like Ca(OH)2, KOH, and alkali ceramic based, like Li2ZrO3, Na2ZrO3 and so on. CaO chemical looping method attracts intensive studies in recent years, which is based on the mature circulating fluidized bed reactor so that it exchanges CaCO3 in carbonation reactor while CaO is regenerated in calcination reactor to achieve a continuous processing. Comparing to others, Ca-based chemical looping has higher CO2 loading capacity, and uses natural minerals (usually limestone) as raw material, therefore the cost is reasonably low. The CaO carbonation reaction is exothermic; however, it has a temperature threshold of about 650 °C to drive the reaction, while the calcination reaction is endothermic and the required temperature is higher than 700 °C or even beyond 900 °C. In this instance, it is highly possible that sintering and deterioration takes place within the sorbent caused by the high temperature heating. Membrane technology for CO2 capture is a relatively emerging method, by using membrane as a selective-permeable barrier to

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separate targeted gas from others. There are many types of gas membranes depending on different mechanisms, but in common they all ought to have high permeability and high selectivity to CO2. This technology requires no regeneration energy input; however, it is necessary to compress the gas to form a pressure difference across the membrane to let CO2 pass through. Comparing to absorption and adsorption methods, membrane separation has higher energy efficiency, lower cost and compacter equipment. Currently it is still in its preliminary stage of lab investigation. By cooling and condensation, cryogenic method can separate CO2 and obtain CO2 with very high purity. This method is widely used commercially, and more suitable for high CO2 concentration, typically higher than 50% [8]. There are very few studies that have applied cryogenic separation to post-combustion CO2 capture because of the significant energy penalty for dilute gas mixture. Another major disadvantage is that moisture must be removed from the gas mixture before cooling in order to prevent blockage caused by ice particles. The fact that gas can form solid hydrates within water has been known for many years, and it has driven intensive investigations in recent years for its capability to separate gas, like CO2 from mixture, and to store the gas. Davy [9] discovered the formation of a solid substance when cooling an aqueous solution of chlorine in 1811, which was then confirmed to be a compound containing one part of chlorine and 10 parts of water by Faraday and Davy [10] 12 years later. In the following hundred years after the discovery, gas hydrate was only investigated in the academic aspect. In 1934, gas hydrate was believed to be the culprit of blockages in natural gas transportation pipelines [11], and then intensive explorations were conducted on the gas hydrate molecular structure and thermo-physical properties [12– 15]. Later on researches unveiled the existence of gas hydrate in nature, like natural gas hydrate, CO2 hydrate in the deep ocean where the pressure is very high and temperature is low. Because each individual gas has different hydrate formation conditions, hydrate technology has been recognized as a potential alternative for CO2 capture. Additionally, the merit that per volume gas hydrate contains hundreds volume of gas embraces the promising application for CO2 storage. This new technology involves no or very few chemical agents, but only uses cold water or lean aqueous solution as the working fluid. In most cases, the equilibrium temperature of hydrate is lower than the ambient temperature, hence the regeneration by rising temperature can be easily achieved through the heat exchange with atmospheric environment and release CO2 at high pressure which benefits the following transportation and storage. The technology of CO2 capture by hydration is still at its early stage, some effective promoters or additives have been explored to improve the hydrate formation condition, i.e. reducing the formation pressure and accelerating the gas capture. However, the reported investigations are scattered at different CO2 concentrations, different gas mixtures, different operation conditions, different promoters, and even the opposite conclusions were reported by different authors, which is mainly caused by complicated and stochastic hydration process and diversity of experimental conditions. (1) Phase equilibrium

N2

(2) Hydrate properties: - Molecular structure - Dissociation heat

Promoters Flue gas

TBAB, THF…

Fuel gas

H2

- Other thermo-physical properties

(3) Separation performances

CO2 Fuel gas /Landfill gas

- Induction time - Recovery fraction

CH4

- Separation factor - Gas consumption …

Fig. 2. Content structure of the current paper.

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In order to realize highly efficient CO2 capture and separation using hydrate technology, the present paper reviews the open reports of CO2 hydrate and the relevant applications in CO2 capture and separation to support in-depth investigations. As shown in Fig. 2, the review includes: (1) the phase equilibrium data of CO2 hydrate, hydrates of CO2 with other gas, like N2, H2 and CH4, and hydrates of CO2 with some promoters/additives; (2) molecular structure and thermo-physical properties of these hydrates; (3) overall performance of CO2 capture and separation using hydrate technology from gas mixtures CO2 þN2, CO2 þH2 and CO2 þ CH4.

The phase equilibrium data of CO2 hydrate, i.e. the relationship of pressure and temperature at CO2 hydrate equilibrium has been widely investigated, such as in Refs. [19,21–25], and the data within the temperature range of 30 °C to 30 °C and at 0–8.0 MPa pressure is collected and plotted in Fig. 5. In addition to the hydrate–water equilibrium line, there is a liquid–gas equilibrium line of CO2 due to the condensation of the gas at high pressure, which divides the phase Table 1 Physical properties of sI, sII and sH type gas hydrates [16]. Structure

2. Molecular structures, phase equilibrium data and thermophysical properties 2.1. CO2 hydrate Like other gas hydrates, CO2 hydrate can be formed under the condition of low temperature and high pressure. The nonstoichiometric solid crystalline compound is made up of cage-like water networks as host and CO2 molecules trapped in the cages as guest. CO2 and water molecules connect to each other by weak van der Waals force. The compound is only stable when the guest substance is filling in the cage, otherwise the cages become unstable and will collapse to normal ice structure. There are three most commonly formed structures of gas clathrate hydrate depending on the molecular diameter of the gas enclathrated, named as structure I (sI), structure II (sII) and structure H (sH). These three structures consist of 5 different cages in different shapes and sizes, including 512, 51262, 51264, 435663 and 51268 [16], as shown in Fig. 3. The physical properties of these structures are presented in Table 1 [16]. sI structure consists of 46 water molecules while this number is 136 and 34 for sII and sH hydrates, respectively. CO2 clathrate hydrate is believed to have the structure sI [16–20]. Bollengier et al. [19] conducted an optical observation of CO2 hydrate (Fig. 4), which has high transmissivity and the shape of polygon. CO2 sI hydrate was found to be stable under 0.7 GPa and would change to a new ‘high pressure’ hydrate between 0.7 and 0.8 GPa in the temperature range of 260–280 K, of which the structure was not match those of known hydrate structures.

Cages Number of cages per unit cell Average cage radius, 10 10 m Variation in radius, % Coordination number Number of water per unit cell

sI 12

5 2 3.95 3.4 20 46

sII 12 2

5 6 6 4.33 14.4 24

12

5 16 3.91 5.5 20 136

sH 12 4

5 6 8 4.73 1.73 28

512 3 3.94 4.0 20 34

435663 2 4.04 8.5 20

51268 1 5.79 15.1 36

Fig. 4. Optical observation of CO2 hydrate crystals (sI) near 284 K and 0.65 GPa, liq. is the CO2 saturated aqueous solution, CO2 I is the CO2 ice [19].

Fig. 3. Different cavities in gas hydrates: (a) pentagonal dodecahedron (512); (b) tetrakaidecahedron (51262); (c) hexakaidecahedron (51264); (d) irregular dodecahedron (435663); and (e) icosahedron (51268) [16].


diagram into four parts for different combinations of water, hydrate, liquid CO2 and gas CO2. Moreover, there is a fifth area representing ice and CO2 gas when the temperature is low enough to form ice. More information of the phase equilibrium data within wider pressure range can be found in Ref. [19]. Being provided with phase equilibrium data, the dissociation heat, ΔH of gas hydrate can be easily calculated based on the Clausius–Clapeyron equation [23,26–32], given as Eq. (1). d ln P ΔH ¼ dð1=TÞ ZR

ð1Þ

where P and T are the equilibrium pressure and temperature, respectively, Z is the compressibility factor under the conditions of P

7.0 6.5 6.0 5.5

North et al. Water + hydrate + CO 2 gas Hydrate + CO 2 liq + CO2 gas Water + hydrate + CO 2 liq Water + CO2 gas + CO2 liq Ice + water +CO 2 gas Ice + hydrate + CO 2 gas

Pressure (MPa)

5.0 4.5 4.0

Lin et al. Adisasmito et al. Ye and Zhang Anderson

water + CO2 liq

hydrate + CO2 liq

3.5 3.0 water + CO2 gas

2.5 2.0 1.5

hydrate + CO2 gas

1.0 0.5

ice + CO2 gas

0.0 -35 -30 -25 -20 -15 -10

-5

0

and T, and R is the universal gas constant. If the compressibility factor does not change dramatically, the calculated dissociation heat based on Clausius–Clapeyron method is valid in a narrow pressure and temperature ranges. Although being simple, the accuracy of Clausius–Clapeyron method is argued not as good as that of direct measurement using calorimetrical method due to the facts that volume changes during hydration and the gas could dissolve into water, therefore this method is believed to be valid only for univariant system. Nevertheless, it still provides the acceptable accuracy for engineering application based on the comparison of calculated and measured enthalpies of alkane hydrates [26]. To improve the accuracy of Clausius–Clapeyron method, Yoon et al. [28] developed a new formula taking into account of gas solubility and the volume change during phase change, as shown in Eq. (2).

ΔHd þ nxg ΔHs d ln P ¼ dð1=TÞ Zn R

8.0 7.5

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5

10

15

20

25

30

35

Temperature (°C) Fig. 5. Phase equilibrium data of CO2 hydrate measured by Adisasmito et al. [21], North et al. [22], Anderson [23], Lin et al. [24], Ye and Zhang [25].

ð2Þ

where n is the hydration number, ΔHs is the dissolution heat of the gas in water, xg is the molar fraction of gas in water, and Zn is the modified compressibility factor. Kang et al. [29] used an isothermal microcalorimeter to measure dissociation enthalpies of hydrate formed by not only pure gases but also some binary or even ternary gas mixture. The calorimetrical method was regarded more accurate; however, the application was limited due to its complicated and difficult implementation. Aya et al. [33] built a loop type system with CO2 rich water flowing and heat exchanging. The cooling and heating processes were recorded as CO2 hydrate generating and dissolving, thus the hydrate formation conditions was obtained as well as the dissociation heat which was found to be lower than that calculated based on Clausius–Clapeyron method. Some reported values of latent heat using different methods are presented in Table 2. The hydration number is another important parameter of clathrate hydrate, which is the number of water molecules per guest molecule. If all the cages in the hydrate are occupied by the guest molecules, the hydrate number for structure sI hydrate is 46/ (6 þ2) ¼ 5.75, and the hydrate formula should be Gas 5.75H2O. The hydrate number for sII and sH hydrates is the same and equal to 5.67. However the cages are more unlikely fully occupied,

Table 2 Summary of CO2 hydrate thermo-physical properties. Authors

Hydration number

Dissociation heat Density

kJ/mol Anderson [23] Skovoborg and Rasmussen [27] Yoon et al. [28] Sarshar et al. [30] Sabil et al. [31] Lirio et al. [32] Bozzo et al. [35] Kang et al. [29] Aya et al. [33] Uchida et al. [37] Ripmeester and Ratcliffe [41] Udachin et al. [42] Circone et al. [17] Kumar et al. [43]

6.4 70.3 5.7 70.3 7.67

62.5 7 1.8 58.2 7 3.0 68.71

6.21

57.66 64.22 56.85–75.37 66.8 48.15

7.2 7.3 7 0.1 7.23 7.68 7.24 7.0 6.2 5.6–5.7 5.59–5.74 6.04

65.22 7 1.03 35.57

Hydrate structure

Measuring condition Temperature Pressure °C MPa

kg/m3

1.0 9.0

1.38 3.86

sI

Clausius–Clapeyron Clausius–Clapeyron

1110

0 0 0–8.91 2.15–6.75 10

1.05–3.60 1.59–2.86 0.1

1090–1110 1040 1060

0.5 12 9.05 9.55

0.1 30 4.56 3.93

sI, θS/θL ¼ 0.32 1120

Method involved

2.75 θS ¼ 0.71 θL ¼ 1.0 sI, both θS, θL are close 6.85 to 1 7.35 sI, θS ¼0.81 50 θL ¼ 1.0

Clausius–Clapeyron Clausius–Clapeyron Clausius–Clapeyron Clausius–Clapeyron Clausius–Clapeyron and Miller– Strong method Calorimetry Flow and heat exchange Raman spectroscopy NMR Spectroscopy

3.8

X-ray diffraction

18.3–20.3 17.4–20.1 3.2

Mass consumption Dissociation ATR-IR spectroscopy

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method [29], Raman spectroscopy [37–40], NMR (Nuclear magnetic resonance) spectroscopy [41], X-ray diffraction [17,42], ATR-IR (attenuated total reflection infrared) spectroscopy [43], mass uptake and dissociation test by balance [17], etc. Uchida et al. [37] used a Raman spectrometer to analyze the generated CO2 hydrate as well as the CO2 solution, and the obtained intensities as the function of wave length are shown in Fig. 6. The intensity comparison between CO2 hydrate and solution provided a hydration number of 7.68 (9.05 °C, 4.56 MPa) and 7.24 (9.55 °C, 3.93 MPa) through the following equation: ð7Þ N ¼ I W; L =I W; H = I CO2 ; L =I CO2 ; H =xCO2

Fig. 6. Typical Raman spectroscopy analysis of CO2 hydrate and CO2 aqueous solution [37].

therefore the practical hydration number is normally larger and depends on the occupancy ratio. Taking structure sI hydrate as an example, it consists of 6 large cages (51262) and 2 small cages (512), the hydration number can be calculated by the following equation: N ¼ 46= 6 θL þ 2 θS ð3Þ where θL and θS are the occupancy ratios of the guest molecules in the large cages and small cages, respectively. There are several methods to determine the occupancy ratio and the hydration number of clathrate hydrate, including indirect measurements and direct measurements [34]. (1) Indirect measurements Bozzo et al. [35] employed the Miller–Strong method to calculate the hydration number of CO2 hydrate, the following equation was used: log f 2 =f 1 ð4Þ N¼ log a1 =a2 where f1 and f2 are the fugacity of guest in pure water–hydrate system and salt water–hydrate, respectively, a1 and a2 are the activity of water in pure water–hydrate system and salt water– hydrate, respectively. However, some gases like CO2 have high solubility in water and its effect on the activity of water cannot be ignored, Chen [36] proposed an improved equation to obtain more accurate hydration number, as given in Eq. (5) ln f =f ð5Þ N ¼ 2 01 1x ln an 1 1x0 2ð 2Þ where a* is the activity of water without any gas dissolved in water, x0 is the molar fraction of gas in water, subscripts 1 and 2 denote the system of water–hydrate and salt water–hydrate respectively. Another indirect method to determine the hydration number is based on Clausius–Clapeyron method. Lirio et al. [32] and Anderson [23] calculated CO2 dissociation enthalpies in the hydrate–water and hydrate–ice systems using Clausius–Clapeyron method, then obtained the hydration number based on the difference between these two enthalpies and the dissociation heat of ice, as given in Eq. (6). N ¼ ðΔH d; W ΔH d; I Þ=ΔH I

ð6Þ

where ΔHd, W and ΔHd, I are the dissociation heat of hydrates in hydrate–water and hydrate–ice systems, and ΔHI is the melting heat of ice. (2) Direct measurements Some direct techniques have been applied to study the gas hydrate and to determine the hydration number, including calorimetrical

where I is the intensity that is measured by the spectrometer, xCO2 is the molar fraction of CO2 in water, subscripts W, L, H indicate water, liquid and hydrate, respectively. The obtained hydration number indicates the incomplete occupancy of CO2 in cages. Ripmeester and Ratcliffe [41] employed NMR spectroscopy and observed both the occupancies of CO2 in large and small cages, as shown in Fig. 7. Derived from the spectra, the value of θS/θL is about 0.32 and gives a hydration number of 7.0 under the assumption that all the large cages are occupied by CO2. Udachin et al. [42] applied the X-ray diffraction to a single CO2 hydrate grown in heavy water, and obtained the location of disordered CO2 as well as CO2 occupancy ratios in large and small cages, which were 1.0 and 0.71, respectively. The hydration number was then calculated to be 6.2 by Eq. (3). Circone et al. [17] used a balance to weigh the mass difference before and after hydration (mass uptake) and also dissociation (mass dissociation) to determine the hydration number, and the test results showed nearly full occupancies of CO2 in both large and small cages, therefore the hydration number was close to 5.75. Kumar et al. [43] presented ATR-IR spectroscopy study of CO2 hydrate and distinguished the vibrational frequencies from CO2 in small and large cages, and obtained the occupancy ratios of CO2 in large and small cages as 1.0 and 0.81 respectively while the hydration number as 6.04. Some reported hydration numbers are summarized in Table 2. In conclusion, CO2 forms sI structure hydrate in water, and majority of researchers reported incomplete occupancy of CO2 in cages and the occupancy ratio in large cages was close to 1.0 while that in small cages depended on operation conditions. The hydration number of CO2 hydrate was in the range of 5.7–7.7 or even higher, and the dissociation heat of the hydrate was in the range of 55.0–70.0 kJ/mol, while the hydrate density was 1140–1120 kg/m3. 2.2. Clathrate hydrates of tetraalkylammonium salt and others CO2 hydrate formation requires the condition of high pressure and low temperature as foregoing discussion, whereas, there are many other clathrate hydrates that can be easily generated under atmosphere pressure and room temperature. One typical kind of these easy-generated hydrates is tetraalkylammonium salt (such as halides, sulfate, formate, etc.) clathrate hydrate [44–47], the hydrates are known as semi-clathrate hydrate since their cages are formed together by water molecules and salt molecules due to the relatively large size of salt molecule. Other easy-generated hydrates include trimethylolethane (TME) clathrate hydrate [47,48], tetrahydrofuran clathrate (THF) hydrate [49,50] and so on. As shown in Fig. 8, there are dodecahedral empty cages in the semi-clathrate of TBAB semi-clathrate hydrate, and these cages are capable of encaging and storing small size gas molecules and have the potential of gas separation [51], meanwhile the usage of these hydrates will contribute to a dramatic reduction of formation pressure of gas hydrate. Many studies have been reported about CO2 hydration with the aid of promoters, including TBAB (tetrabutylammonium bromide), TBAC (tetrabutylammonium chloride), TBAF (tetrabutylammonium fluoride), TBPB (tetrabutylphosphonium bromide), THF, TBPC (tetrabutylphosphonium chloride), and TBANO3 (tetrabutylammonium nitrate) etc.


Fig. 7.

13

C NMR spectra of

13

CO2 sI hydrate (top curves) and sII double hydrate of

Fig. 8. (a) Structure of TBAB semi-clathrate hydrate [47] and (b) photo of TBAB hydrate crystals [57].

In this section, the basic knowledge and the thermo-physical properties of such kind of clathrate hydrates are summarized and discussed. Tetraalkylammonium salt clathrate hydrate was firstly reported by Fowler et al. [44], and the following researches focused on the crystal

13

1279

CO2 and propane (bottom curves) [41].

data and structure refinement from the perspective of chemistry. Lorsch et al. [52] and Kimura and Kai [53] proposed the utilization of hydrates for cold energy storage, including gas hydrate and tetraalkylammonium salt clathrate hydrate. Among them TBAB clathrate hydrate slurry (CHS in abbreviation) was particularly extensively investigated as the cold storage and transportation media across the world, as in Japan [54–57], China [58–62] and France [63,64] and so on. The thermo-physical properties of TBAB, TBAC, TBAF, TBPB, TBPC, THF and TBANO3 clathrate hydrates are presented in Table 3, and their phase equilibrium is shown in Fig. 9. These hydrates can be generated at atmospheric pressure and the temperature range of 0–30 °C. To determine the types of the generated hydrates, the morphology characteristics of TBAB hydrate were reported by Oyama et al. [57], as shown in Fig. 8(b). Two kinds of hydrates were observed in the experiments, named as type A and type B, and they have different transmittivities, refractions and crystal morphologies. Type A has columnar shape while type B has undefined shape and is thin with rougher surface. Oyama et al. [57] determined the hydration number of type A and B TBAB hydrate to be 26 and 38, respectively. The authors grew both the hydrate crystals and removed the remaining water on the surface followed by quenching the crystals in liquid nitrogen, and then they measured the dissociation heat of the prepared crystals with differential scanning calorimeter (DSC). In addition to the hydrates generated within low concentration (o40 wt%) TBAB aqueous solution, Lipkowiski et al. [65] revealed the existence of two hydrates with less hydration numbers in concentrated TBAB solution, which were only 2 and 3. The authors then applied single crystal X-ray diffraction method to analyze the structure of TBAB.21/3H2O. Asaoka et al. [66] recorded the generation and melting processes of TBAB hydrates, and the measured dissociation heat were 210 kJ/kg and 224 kJ/kg for type A and B hydrates, respectively; the melted hydrate concentration was further used to determine the hydration number of TBAB hydrates, which were 35 for type A and 47 for type B. Rodionava et al. [68] studied the calorimetric and structural properties of TBAB hydrates using DSC and single-crystal X-ray test, respectively. Three different hydrate structures with the hydration number of 26.4, 32.5 and 38.1 were observed in diffraction experiments based on chemical method, while their dissociation heat were measured to be 188.9 kJ/kg, 197.6 kJ/kg and 217.6 kJ/kg, respectively. Sun et al. [69] and Sato et al. [72] recorded the generation process of TBAB hydrates at a very slow cooling rate in a thermally insulated container, however, both of them obtained only one type of TBAB hydrate.

1280


Table 3 Thermo-physical properties of TBAB/TBAC/TBAF/TBPB/THF/TBPC/TBANO3 clathrate hydrates. Authors

TBAB

TBAC

TBAF

TBPB

THF

TBPC TBANO3

Hayashi et al. [55] Ogoshi and Takao [56] Oyama et al. [57] Darbouret et al. [63] Lipkowski et al. [65] Asaoka et al. [66] Nagatomi et al. [67] Rodionova et al. [68] Sun et al. [69] Dyadin and Udachin [45] Nakayama [70,71] Sato et al. [72] Sun et al. [73] Ye and Zhang [74] Rodionova et al. [75] Mayoufi et al. [79] Dyadin and Udachin [45] Nakayama [70,71] Rodionova and Manakov [76] Sakamoto et al. [77] Lee et al. [78] Dyadin and Udachin [45,46] Mayoufi et al. [79,80] Suginaka et al. [81] Zhang et al. [82] Lin et al. [83] White and MacLean [49] Hanley et al. [84] Anderson and Suga [85] Otake et al. [86] Leaist et al. [89] Ye and Zhang [74] Sakamoto et al. [90] Mayoufi et al. [80]

Hydration number Congruent melting temperature °C

Density

Dissociation heat

Specific heat capacity Thermal conductivity

kg/m3

kJ/kg

J/(kg K)

W/(m K)

26/36

12.3/9.6

1082/1030 193/205

2220/–

0.42/–

26/38

12.0/9.9

26/36 24/26/32/36/2/3 35/47

12.3/9.6 12.4/12.2/11.7/9.5/–/–

38.1/32.5/26.4 22.8 29.7/32.1 30 29.4 29 28.7 32.2/29.7/24.8 30 28.6/32.3 30 29.7/32.8

9.5/12.0/12.0 12.5 15.0/14.7 15.0 15.05 14.9 13.7 15.0/15.1/14.9 15.1 27.4/27.2 28.3 27.7/27.2

28.2 28.2 37/32

27.6 27.55 8.9/8.8

32 35 32-33 33 16.83 14.6 16.9 17 16.9 30.4 29.1 26

8.05/8.9 9.25 9.35 8.95 5 5.05

193.2/199.6

1869–2605/1995– 2541a

1082/1067 2107 10/2247 15 0.371–0.389b 217.6/197.6/188.9 1034/1029 200.7 169.2 208.9/193./176.6 1034 206.2 1057/1035 229.7 223.1/240.5

207.7 214

1966c 0.37–0.51d

4.4 4.25 10.3 10.3 5.4

998.4e 260

1051

1066–1893f

194 174.7

a

Temperature is between 20 °C and 0.2 °C. 80-9 °C. c 13.15 °C. d 223 °C to 23 °C. e 3.22 °C. f 153.15 °C to 3.15 °C. b

Sato et al. [72] and Sun et al. [73] measured the phase equilibrium of TBAC hydrate by using similar methods as they used for TBAB hydrates. The latter authors obtained a dissociation heat of TBAC hydrates as 169.2 kJ/kg by using DSC inside a cold room. Ye and Zhang [74] experimentally measured the phase change temperature of TBAC hydrate, meanwhile observed and recorded the hydrate generation process by using a CCD camera. They noticed that the needle-like hydrate crystals with large length–width ratio were generated before the crystals grew gradually to be of regular columnar shape. Rodionava et al. [75] found three different hydration numbers of TBAC clathrate hydrate, which were 32.2, 29.7 and 24.8, and they used DSC to measure the dissociation heats, which were 208.9 kJ/kg, 193.1 kJ/kg and 176.6 kJ/kg, respectively. Moreover, the authors also studied the structural properties with X-ray single crystal diffraction and powder diffraction and discovered the sI structure of TBAC clathrate hydrate for the first time. Rodionava and Manakove [76] observed the generation of two different TBAF clathrate hydrates, where one was tetragonal shape and the other one had cubic structure, and their hydration numbers were determined by potentiometric titration method to be 32.8 and 29.7, respectively. The dissociation heats of the hydrates were calorimetrically measured by DSC, as shown in Table 3. DSC

tests were also used by Mayoufi et al. [79,80] and Lin et al. [83] to determine the phase change temperature and dissociation heat of TBPB hydrates (Table 3). Both Suginaka et al. [81] and Zhang et al. [82] visualized the generation of TBPB hydrates generation process; however, different morphologies of TBPB hydrates were observed by different authors as the former authors found column shape crystals while the latter ones found the hexagonal plate crystal with high transmittance. White and MacLean [49] measured the specific heat capacity of THF hydrate by using a calorimeter vessel, and it was 141–1966 J/(kg K) within a temperature range of from 253.15 °C to 13.15 °C. Andersson and Suga [85] used transient hot-wire method to measure the thermal conductivity of THF hydrate in the temperature range of 223 °C to 23 °C and the pressure up to 0.16 GPa, and the measured result was around 0.37–0.51 W/(m K) and increased with both temperature and pressure. Otake et al. [86] proposed a simple in-situ technique to measure the density of THF clathrate hydrates with oscillating U-tube, and the result obtained was 998.40 kg/m3 at 3.22 °C and atmospheric pressure. Delahaye et al. [87] measured the phase equilibrium of THF–water system with DSC as the concentration of THF aqueous solution varying from 0 wt% to 30.29 wt%. Leaist et al. [89] measured the dissociation heat of THF


16

14 12

TBAC hydrate

TBAB hydrate

14

Temperature (°C)

10

Temperature (°C)

1281

8 Hayashi et al., N=26

6

Hayashi et al., N=36 Oyama et al., N=26

4

Oyama et al., N=38 Darbouret et al., N=26

2

Darbouret et al., N=36

0

12 10 8 6 Nakayama Dyadin and Udachin Sato et al. Sun et al. Ye and Zhang

4

Lipkowski et al., N=26 Lipkowski et al., N=32

-2

2

Lipkowski et al., N=36

-4 0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.45

0 0.0

0.50

0.1

Aqueous sloution concentration

9

TBAF hydrate 30

0.4

0.5

0.6

TBPB hydrate

8

Temperature (°C)

25

Temperature (°C)

0.3

10

35

20 15 10 Rodionova and Manakov, N=29.7 Rodionova and Manakov, N=32.8 Nakayama Dyadin and Udachin Sakamoto et al. Lee et al.

5 0 -5 0.0

0.1

0.2

0.3

0.4

0.5

7 6 5 4 3 2 Mayoufi et al. Suginaka et al. Zhang et al. Lin et al.

1 0 -1

-10 0.6

0.7

-2 0.0

0.8

0.1

0.2

0.3

0.4

0.5

0.6

Aqueous solution concentration


6

11 THF hydrate

5

10

4

9

Temperature (°C)

Temperature (°C)

0.2


3 2 1

TBPC hydrate

8 7 6 5

Hanley et al. Otake et al. Delahaye et al. Anderson et al.

0 -1 -2 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

4 Ye and Zhang Sakamoto et al.

3 0.8


2 0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55


Fig. 9. Phase equilibrium data of TBAB/TBAC/TBAF/TBPB/THF/TBPC clathrate hydrates, (a) TBAB clathrate hydrate, Hayashi et al. [55], Oyama et al. [57], Darbouret et al. [63], Lipkowski et al. [65]; (b) TBAC clathrate hydrate, Dyadin and Udachin [45], Nakayama [70,71], Sato et al. [72], Sun et al. [73], Ye and Zhang [74]; (c) TBAF clathrate hydrate, Dyadin and Udachin [45], Nakayama [70,71], Rodionova and Manakov [76], Sakamoto et al. [77], Lee et al. [78]; (d) TBPB clathrate hydrate, Mayoufi et al. [79,80], Suginaka et al. [81], Zhang et al. [82], Lin et al. [83]; (e) THF clathrate hydrate, Hanley et al. [84], Otake et al. [86], Delahaye et al. [87], Anderson et al. [88] and (f) TBPC clathrate hydrate, Ye and Zhang [74], Sakamoto et al. [90]. All the concentrations are by weight.

hydrate as 98 kJ/mol (260 kJ/kg) at its congruent point of 4.25 °C with a calorimeter, while the specific heat of the hydrate was 1066–1893 J/(kg K) as the temperature increased from 153.15 °C to 3.15 °C. The thermo-physical properties of TBAB hydrate are rather adequate due to the intensive investigation; on the contrary, the thermo-physical properties of other hydrates have been rarely reported, in particular their dissociation heats, thermal conductivities and specific heat capacities. More works on these fundamental properties should be carried out to promote their exploitation.

2.3. Hydrates of CO2 with promoters 2.3.1. CO2 þTHF double hydrate As aforementioned, THF, TBAB, TBAC, TBAF, TBPB, TBPC and TBANO3 can be used as the promoters for CO2 hydrate, the addition of which into water can significantly reduce the formation pressure of CO2 hydrate. THF is one of the prevailing promoters for gas hydration such as CO2, H2 and CH4, or their mixtures. The equilibrium data of the ternary system of CO2 þ THF þwater is shown in Fig. 10, and the available property data of the corresponding hydrate are shown in Table 4.


Sabil et al. [31] measured the hydrate–liquid–vapor equilibrium of CO2 in THF aqueous solution by using a Cailletet tube. A certain amount of THF solution and CO2 were filled into the tube, and the temperature of the mixture was decreased slowly to form the hydrate crystals. Afterwards the temperature was raised up at even slower rate, and the disappearance of the crystals was considered as the sign of phase change point and the corresponding temperature was recorded as the phase transition temperature. At the same time, the dissociation heat of hydrate was determined by Clausius–Clapeyron method. The amount of CO2 in the tube was not found to impose influence on the phase equilibrium but resulted in a different enthalpy change. THF aqueous solution with a concentration varying from 1.2 mol% to 7 mol% was tested as the promoter, and it was found that 3 mol% THF aqueous solution was enough to behave as an effective promoter. Sabil et al. [91,92] also explored the addition of electrolytes like NaCl, KCl, and NaBr etc. in THF aqueous solution for CO2 hydration promotion, unfortunately it was found that the addition of metal halides depressed the THF promotion effect. Lirio et al. [32] measured the equilibrium temperature of CO2 within 5 mol% THF aqueous solution at the pressure of 0.8–3.0 MPa, and the dissociation heat of the formed hydrate was then calculated based on Clausius–Clapeyron method as about 103.6 kJ/mol. The hydration number was estimated to be about 13.3 by Eq. (4). Delahaye et al. [87] identified the solidification and dissociation conditions of CO2 hydrate in THF aqueous solution by both DTA (Differential Thermal Analysis) and DSC. They also developed the model of hydrate formation by combining van der Waals and Platteeuw models, and further predicted the phase equilibrium temperature with a deviation of only about 1.51 °C from the measured results. Dissociation heat of the CO2 þTHF double hydrate calculated by Clausius–Clapeyron method was noticed to increase from 130 kJ/mol to 163 kJ/mol with the increasing THF concentration from 3.8 wt% to 15 wt%, which was 2–2.5 times as large as single CO2 hydrate. It was concluded that the enthalpy increase was attributed to the change of hydrate structure from sI to sII when THF was involved in the hydration of CO2. 2.3.2. CO2 þ TBAB double hydrate TBAB is another promoter enjoying wide popularity for CO2 hydration. The phase equilibrium data of CO2 þTBABþwater system has been extensively measured, such as by Lin et al. [24], Ye and Zhang [25], Arjmandi et al. [96], Li et al. [97], Deschampsa nd Dalmazzone [98], Joshi et al. [99], Lee et al. [100], Mohammadi et al. [101] and so on, as summarized in Fig. 11(a) and (b). Lin et al. [24] measured the phase equilibrium data of CO2 hydrate within 4.43 wt%, 7.02 wt% and 9.01 wt% TBAB aqueous solution with a DTA device. The tested sample was cooled down firstly to form CO2 þTBAB double hydrate, and subsequently heated slowly at a rate of 0.07 °C/min. Since the melting of CO2 þTBAB double hydrate is not congruent, the phase change pressure and temperature were at the last peak point of DTA peaked curves. With the initial aqueous solution concentration of 9.01 wt%, both the calorimetry and Clausius–Clapeyron methods were used to acquire the dissociation heat of the double hydrate, and the results were 139.5 kJ/mol (CO2) and 203.6 kJ/mol (CO2), respectively. The quantity of CO2 in the double hydrate calculated based on P–V–T diagram and CO2 solubility in TBAB aqueous solution was calculated, and the formula of type B CO2 þ TBAB double hydrate was determined as 2.51CO2.TBAB.38H2O. Ye and Zhang [25] reported the phase equilibrium data of CO2 þTBAB double hydrate using 5–55 wt% TBAB aqueous solution. The promotion effect was found to increase with TBAB concentration up to 32 wt% (congruent point), beyond which it started to reduce, as shown in Fig. 11(b). The authors also visualized the hydrates formation with a CCD camera, and noticed that there were two different hydrate morphologies of CO2 þTBAB double hydrate. One was

5.0

CO2+THF+Water

4.5 4.0 3.5

Pressure (MPa)

1282

3.0 2.5

CO2 hydrate

2.0 1.5 1.0 0.5 0.0 -0.5 -2

0

2

4

6

8

10

12

14

16

18

20

Temperature (°C) Fig. 10. Phase equilibrium data of CO2 þ THF þwater system, Sabil et al. [31], ■ 1 mol%, 3 mol%, ▲ 5 mol%, ▼ 7 mol%; Lirio et al. [32], ⊞ 5 mol%; Delahaye et al. [87], ☆ 1.56 mol%,✴ 2.75 mol%; Seo et al. [93], □ 1 mol%, ○ 2 mol%, △ 3 mol%, ▽ 5 mol%; Yang et al. [94], 3 mol%; and Lee et al. [95], ◫ 5.56 mol%. Percentages are the used THF solution concentrations.

columnar shape and the other was thin plate with high transmittance. Moreover, the hydrate was reported to tend to form inside the aqueous solution rather than on the vapor–liquid surface, and then deposited at the bottom due to higher density. Koyanagi and Ohmura [102] also observed the formation of CO2–TBAB double hydrate. However, they found the crystals generation occurred both on the vapor–liquid surface and inside the liquid, and observed sword/needle-like, polygonal columnar and wedge crystals while decreasing the supercooling degree. Deschamps and Dalmazzone [98] reported the dissociation heat of CO2 þTBAB double hydrate (formed in 40 wt% TBAB aqueous solution) to be 346.0–395.8 kJ/kg (water) by DSC tests. 2.3.3. CO2 þTBPB double hydrate The measured phase equilibrium data of CO2 þTBPBþwater system is summarized in Fig. 12. TBPB aqueous solution with a concentration of 20–25 wt% seems sufficient to promote CO2 hydration. Higher concentration, i.e. 35–60 wt%, does not reduce the equilibrium pressure remarkably comparing to the concentration of 20–25 wt%, and the equilibrium pressure of CO2 þ50–60 wt% TBPB aqueous solution was even higher than that using 35 wt% TBPB aqueous solution. Mayoufi et al. [79,80] measured the phase equilibrium data and dissociation heat of CO2 þ TBPB double hydrate by using a high sensitivity DSC, meanwhile they also estimated the dissociation heat by Clausius–Clapeyron equation. The DSC test results indicated that the dissociation heat was 6.65 kJ/mol (H2O) at 1.0 MPa pressure and 7.3 kJ/ mol (H2O) at 1.5 MPa, while the calculated result was 144 kJ/mol (CO2), therefore, leading to the molar ratios of water to CO2 in hydrate as 21.6 and 19.7, respectively, under the corresponding pressure. Zhang et al. [82] studied the phase equilibrium of CO2 þ TBPB double hydrate with 10–50 wt% TBPB aqueous solution in a pressure range of 0.4–4 MPa, and also visualized the formation process. It was observed that when the concentration of TBPB aqueous solution was 10 wt%, dodecagonal shape hydrate crystals formed at first, then changed to columnar shape and finally to large irregular undefined thin crystals. If the concentration of TBPB aqueous solution was increased to 50 wt%, columnar shape crystals generated directly and then large size leaf-like crystals grew on the basis of columnar shape crystals. 2.3.4. CO2 þTBAC/TBAF/TBPC/TBANO3 double hydrates Phase equilibrium data of CO2 þTBAC/TBAF/TBPC/TBANO3 þwater system are summarized in Figs. 13 and 14. Ye and Zhang [74] characterized the phase equilibrium data of CO2 þ TBAC and CO2 þ TBPC double hydrates in a cylindrical


1283

Table 4 Thermo-physical properties of hydrate of CO2 þpromoters. Authors

Promoter

Hydrate compound

Sabil et al. [31]

1.2–20.6 mol% THF

Lirio et al. [32]

5 mol% THF

Delahaye et al. [87]

3.8–15 mol% THF

Lin et al. [24]

4.43 wt% TBAB

Hydration number

13.3

40 wt% TBAB

Mayoufi et al. [80]

37.07 wt% TBPB

Method involved

112.4–152.3 kJ/mol CO2

Clausius–Clapeyron 10–14 °C Clausius–Clapeyron 10–19 °C, 0.8–3.0 MPa Modeling and calorimetry Clausius–Clapeyron 6.85 °C, 0.2–3.5 MPa Clausius–Clapeyron 9.65 °C Calorimetry Clausius–Clapeyron Calorimetry 13.35–15.45 °C Clausius–Clapeyron Calorimetry Calorimetry Clausius–Clapeyron Calorimetry Calorimetry Clausius–Clapeyron Calorimetry Calorimetry

130.6 kJ/mol CO2 130–163 kJ/mol CO2

2.51CO2 TBAB 38H2O

168.2 kJ/mol CO2

9.01 wt% TBAB Deschamps and Dalmazzone [98]

Dissociation heat

139.5 kJ/mol CO2 203.6 kJ/mol CO2 346–395.8 kJ/kg water 144 kJ/mol CO2 6.65 kJ/mol H2O (1.0 MPa) 7.30 kJ/mol H2O (1.5 MPa) 450 kJ/mol CO2 6.01 kJ/mol H2O (1.0 MPa) 6.31 kJ/mol H2O (1.5 MPa) 370 kJ/mol CO2 5.76 kJ/mol H2O (1.0 MPa) 5.82 kJ/mol H2O (1.5 MPa)

36.18 wt% TBAC

39.41 wt% TBANO3

5.0

4.5 4.0

4.0

Pressure (MPa)

TBAB10 wt%

3.5

Pressure (MPa)

4

3.0

CO2 hydrate 2.5 2.0 1.5 1.0 0.5 0.0 0

1

2

3

4

5

6

7

8

9 10 11 12 13 14 15 16 17 18 19

Temperature (°C) Fig. 11. Phase equilibrium data of CO2 þTBABþ water system, (a) TBAB concentration is less than 10 wt%: Ye and Zhang [25], ■ 5 wt%, 10 wt%; Arjmandi et al. [96], □ 10 wt%; Li et al. [97], ○ 5 wt%, △ 10 wt%; Lin et al. [24], ▽ 4.43 wt%, ◁ 7.02 wt%, ▻ 9.01 wt%; Joshi et al. [99], ⊟ 5 wt%, ⊖ 10 wt%; Lee et al. [100], ☆ 9.76 wt%; Mohammadi et al. [101], ✴ 5 wt%,þ 10 wt%. (b) TBAB concentration is larger than 10 wt%: Ye and Zhang [25], ■ 19 wt%, 32 wt%, ▲55 wt%; Arjmandi et al. [96], ✴ 42.7 wt%; Deschamps and Dalmazzone [98], 40 wt%; Joshi et al. [99], þ20 wt%; Lee et al. [100], ⊞ 40.76 wt%, 59.9 wt%; Mohammadi et al. [101], □ 16.7 wt%, ○ 25 wt%, △ 35 wt%, ▽ 50 wt%. Percentage are the used TBAB solution concentrations.

crystallizer, while the morphologies of these two hydrates were observed by a CCD camera. Needle-like and plate shape hydrate crystals of CO2 þTBAC double hydrate formed initially, and then needle-like crystals grew and became larger while the plate crystals changed to columnar shape first and finally became irregular crystals with large length–width ratio. The authors noticed that the presence of CO2 did not change the morphology of TBPC hydrates, and hexagonal thin-plate shape crystals with high transmittance formed and grew to larger ones, and part of the large crystals broke into small pieces. Phase equilibrium data of CO2 þTBAC þwater system and CO2 þ TBANO3 þwater systems measured by a highly sensitive DSC were reported by Mayoufi et al. [80]. TBAC aqueous solution with a concentration of 36.18 wt% and TBANO3 aqueous solution with a concentration of 39.41 wt% were used. Both of the aqueous solutions were at the stoichiometric concentrations of hydrates, i.e. TBAC.30H2O and TBANO3.26H2O. Hydrate dissociation heat were both measured by DSC and estimated by Clausius–Clapeyron equation. For the double hydrates of CO2 þ TBAC, the DSC test results were 6.01 kJ/mol (H2O) and 6.31 kJ/mol (H2O) at 1.0 MPa

1284


The addition of promoters into water can shift CO2 hydration equilibrium line to the higher temperature and lower pressure region, i.e., the aforementioned promoters can reduce the equilibrium pressure from about 4.5 MPa to no more than 0.5 MPa at 10 °C. Higher promoter concentration generally led to a better promotion effect; however, there is an upper limit of the concentration beyond which the increase of promotion effect was not evident. TBAC and TBAF have better promotion effects than others considering their lower equilibrium pressure of CO2 þwaterþ promoter system at the same temperature, which is possibly caused by their relatively higher hydration temperature in water, as shown in Fig. 9.

4.5

CO2+TBAC+Water CO2+TBAF+Water

4.0

Pressure (MPa)

3.5 3.0

CO2 hydrate 2.5 2.0 1.5 1.0 0.5

2.4. Hydrates of CO2 with other gases

0.0 0

2

4

6

8

10

12

14

16

18

20

22

24

Temperature (°C) Fig. 13. Phase equilibrium data of CO2 þTBAC/TBAFþ water system, Ye and Zhang [74], ■ 5 wt% (TBAC), 10 wt% (TBAC), ▲ 20 wt% (TBAC), ▼ 35 wt% (TBAC), ◄ 50 wt% (TBAC); Mayoufi et al. [80], ★ 36.18 wt% (TBAC); Li et al. [97], □ 4.34 wt% (TBAC), ○ 8.74 wt% (TBAC), △ 4.09 wt% (TBAF), ▽ 8.27 wt% (TBAF); Bouchemoua et al. [105], þ 38.8 wt% (TBAC); Kamran-Pirzaman et al. [106], ⊞ 5 wt% (TBAF), 10 wt% (TBAF); Makino et al. [107], ☆ 34 wt% (TBAC). Percentages are the used TBAC/TBAF solution concentrations.

4.5

CO2+TBANO3+Water CO2+TBPC+Water

4.0

Pressure (MPa)

3.5 3.0

CO2 hydrate

2.5 2.0 1.5 1.0 0.5 0.0 2

4

6

8

10

12

14

16

18

20

Temperature (°C) Fig. 14. Phase equilibrium data of CO2 þ TBPC/TBANO3 þ water system, Ye and Zhang [74], □ 5 wt% (TBPC), ○ 10 wt% (TBPC), △ 20 wt% (TBPC), ▽ 35 wt% (TBPC), ◊ 50 wt% (TBPC); Mayoufi et al. [80], ■ 39.41 wt% (TBANO3); Du et al. [108], 39.41 wt% (TBANO3). Percentages are the used TBPC/TBANO3 solution concentrations.

and 1.5 MPa, respectively; while the calculated value was 450 kJ/ mol (CO2). Therefore the molar ratios of water to CO2 in hydrate were 75 and 72 at the corresponding pressure, respectively. For the double hydrates of CO2 þ TBANO3, the DSC test results were 5.76 kJ/mol (H2O) and 5.82 kJ/mol (H2O) at 1.0 MPa and 1.5 MPa, respectively, and the calculated value by Clausius–Clapeyron equation was 370 kJ/mol (CO2); hence the molar ratios of water to CO2 in hydrate were determined to be 65 and 64 at the corresponding pressure, respectively. Li et al. [97] measured the phase equilibrium data of CO2 þTBAB/TBAC/TBAFþwater system using isochoric pressure search method, and the results showed that the CO2 þTBAF double hydrate had the lowest equilibrium pressure than those of the other two at the same temperature. Using the same method, Kamran-Pirzaman et al. [106] measured the phase equilibrium data of CO2 þ TBAF double hydrate formed in TBAF aqueous solution with the concentration of 5 wt% and 10 wt%. Makino et al. [107] investigated the thermodynamic stability of hydrates formed within TBAC þwaterþH2/N2/CH4/CO2/C2H6 system, and the results indicated that CO2 molecule was the most suitable one for the empty cage of TBAC semiclathrate hydrate.

2.4.1. Hydrates of CO2 þN2 and CO2 þ N2 þ promoters CO2 and N2 are the main components in the flue gas, and the concentration of CO2 is usually in the range of 3–15 mol% as aforementioned. The phase equilibrium data of CO2 þN2 hydrate is then apparently important for CO2 capture using hydration technology. As shown in Fig. 15, the equilibrium pressure of gas mixture is in-between that of pure N2 and pure CO2 [109–111]. Since the equilibrium pressure is very high, many researchers [109,110,112– 114] have attempted to improve the hydration conditions, and the phase equilibrium data of CO2 þ N2 þwaterþpromoter systems are shown in Fig. 16. Kang et al. [29] used a calorimeter to measure the phase equilibrium data and dissociation heat of the hydrate of 0.17 CO2 þ 0.83 N2 (molar ratio, and the same style is used in the following context) and 0.7 CO2 þ0.3 N2, and the measured dissociation heat of the formed double hydrates of these two gas mixtures were 64.59 and 63.41 kJ/ mol (hydrate), respectively. When THF was used as the promoter, the authors believed that the generated hydrate changed from structure sI to sII, resulting in the increase of dissociation heat up to 107– 119 kJ/mol (hydrate). The measured dissociation heat was also found to increase with the increasing concentration of THF aqueous solution. With the assumption of fully occupation of gas molecules in hydrate cages, the authors determined the hydrate compositions based on equilibrium model. The hydrate formed by 0.17CO2 þ0.83N2 in water had the formula of 5.43CO2.1.89N2.46H2O, while the formula was 7.08CO2 0.25N2 46H2O for the hydrate formed by gas mixture of 0.7 CO2 þ0.3 N2. The determined hydrate formulas of 0.17CO2 þ 0.83N2 and 0.7CO2 þ0.3N2 within 1 mol% and 3 mol% THF aqueous solution, as shown in Table 5, indicated that more N2 was captured than CO2 by the hydrate. Therefore, CO2 selectivity of THF aqueous solution was believed to be not as good as pure water. Deschampsa and Dalmazzone [98] studied the promotion effect of 40 wt% TBAB aqueous solution for pure CO2, pure N2 and gas mixture of 0.249 CO2 þ0.751 N2. The dissociation heat of CO2 þN2 þTBAB hydrate was found to increase from 342.25 kJ/kg (H2O) to 394.12 kJ/kg (H2O) as the pressure increases from 2.91 to 9.18 MPa. Lee et al. [111] investigated the phase equilibrium of CO2 þ N2 hydrate by both PTV method and using DSC, and the latter method was also responsible for the measurement of dissociation heat. Furthermore, the authors identified the structure of CO2 þ N2 hydrate through powder X-ray diffraction and Raman spectroscopy. Good agreement between the measured results by PVT method and by DSC test was achieved; moreover, powder X-ray diffraction showed both the mixture of 0.2 CO2 þ0.8 N2 and 0.1 CO2 þ0.9N2 formed structure sI hydrate while the Raman spectroscopy failed to find the transition splitting of gas guests in large cages and small ones. When THF was used as the promoter, Raman spectroscopy succeeded in observing that the hydrate structure changed from sI to sII. The hydrate dissociation heat was measured to be 473.7 kJ/kg (water) and 464.3 kJ/kg (water) for 0.2CO2 þ 0.8N2 and 0.1CO2 þ0.9N2, respectively. After the hydration numbers were determined to be 6.08 and 6.00 based on the


30 28

CO 2+N2+water

26 24

Pressure (MPa)

22

N2 hydrate

20 18 16 14 12 10 8 6 4 2

CO 2 hydrate

0 -1

0

1

2

3

4

5

6

7

8

9

10

11

12

Temperature (°C) Fig. 15. Phase equilibrium data of CO2 þ N2 þwater system, Kang et al. [109], ■ 0.9659 CO2 þ 0.0341 N2, 0.778 CO2 þ 0.222 N2, ▲ 0.4815 CO2 þ 0.5185 N2, ▼ 0.1761 CO2 þ0.8239 N2, ◆ 0.1159 CO2 þ 0.8841 N2, ◄ 0.0663 CO2 þ0.9337 N2; Belandria et al. [110], □ 0.749 CO2 þ 0.251 N2, ○ 0.399 CO2 þ0.601 N2, △ 0.151 CO2 þ 0.849 N2; Lee et al. [111], ⊞ 0.1 CO2 þ 0.9 N2, 0.2 CO2 þ 0.8 N2.

18

CO2+N2+water+promoter 16

CO2 < 40 mol% 14 N2 hydrate

Pressure (MPa)

12 10 8 6

CO2 hydrate 4 2 0 0

2

4

6

8

10

12

14

16

18

20

22

24

22

24

Temperature (°C) 10

CO2+N2+water+promoter

9

CO2 > 40 mol%

8

Pressure (MPa)

7 6 5 4 3

CO2 hydrate

2 1 0 -1 0

2

4

6

8

10

12

14

16

18

20

Temperature (°C) Fig. 16. Phase equilibrium data of CO2 þN2 þ waterþ promoter system, (a) CO2 concentration is less than 0.4: Deschamps and Dalmazzone [98], 0.249 CO2 þ 0.751 N2 þTBAB, ☆ 40 wt%; Kang et al. [109], 0.17 CO2 þ 0.83 N2 þ THF, ⊠ 1 mol%, 3 mol%; Mohammadi et al. [112], 0.151 CO2 þ 0.849 N2 þTBAB, ■ 5 wt%, 15 wt%, ▲ 30 wt%; Mohammadi et al. [112], 0.399 CO2 þ 0.601 N2 þ TBAB,▼ 5 wt%, ◄ 15 wt%, ► 30 wt%; Meysel et al. [113], 0.2 CO2 þ 0.8 N2 þTBAB, □ 5 wt%, ○ 10 wt%, △ 20 wt%. (b) CO2 concentration is larger than 0.4: Kang et al. [109], 0.7 CO2 þ0.3 N2 þ THF, □ 1 mol%, ○3 mol%; Belandria et al. [110], 0.749 CO2 þ0.251 N2 þ TBAB, △ 5 wt%, ▽ 30 wt%; Meysel et al. [113], 0.75 CO2 þ 0.25 N2 þTBAB, ■ 5 wt%, 10 wt%, ▲ 20 wt%; Meysel et al. [113], 0.5 CO2 þ 0.5 N2 þ TBAB, ▼ 5 wt%, ◄ 10 wt%, ► 20 wt%; Bouchafaa and Dalmazzone [114], 0.5 CO2 þ 0.5 N2 þ TBAB, ☆ 10 wt%, ✴ 20 wt%, þ 30 wt%, 40 wt%. Percentages are the used TBAB/THF solution concentrations.

1285

cage occupancies from a thermodynamic model, the hydrate dissociation heat were then estimated to be 51.7 kJ/mol (gas) and 50.1 kJ/mol (gas), respectively. Bouchafaa and Dalmazzone [114] measured the hydrate phase equilibrium temperatures and dissociation heats of hydrates formed with CO2 þN2 in pure water and in TBAB aqueous solution. Both dissociation heats of hydrates of 0.5CO2 þ0.5N2 and 0.1CO2 þ0.9N2 (in pure water) were found to increase with gas pressure. The former hydrate was believed to be more stable than the latter one due to its larger dissociation heat. The same phenomena happened to the hydrates within 40 wt% TBAB aqueous solution, and higher CO2 concentration in the feed gas mixture led to higher phase equilibrium temperature and larger dissociation heat of the hydrate. The reported hydrate dissociation heats are presented in Table 5. SO2 is one of the critical pollutants in the flue gas that is released by the coal-fire power plant, Chen et al. [115] experimentally measured the hydration equilibrium condition of gas mixture of 0.1368CO2 þ0.8547N2 þ0.0085SO2 in SO2 aqueous solution and in SO2 þ TBAB aqueous solution. The presence of SO2 in water reduced the hydrate formation pressure, and the higher the SO2 concentration of the aqueous solution, the lower the formation pressure. However, the use of SO2 aqueous solution led to more SO2 existing in the gas mixture after capture. The addition of 5 wt% TBAB in the SO2 aqueous solution not only brought significant reduction of hydrate formation pressure, but also drove more SO2 in the feed gas mixture to dissolve in the liquid. It was noticed that the promotion effect of TBAB on gas mixture containing SO2 was not as high as on the gas mixture without SO2. 2.4.2. Hydrates of CO2 þ H2 and CO2 þH2 þpromoters As aforementioned, the main components of pre-combustion gas mixture are CO2 and H2, and the concentration of CO2 is usually 30– 45 mol%. The reported phase equilibrium data of CO2 þH2 hydrate are summarized in Fig. 17. The reason for the absence of H2 hydrate data in the figure is the very high hydration pressure of hydrogen, which is at the level of GPa at the room temperature due to the small size of hydrogen molecule. The effects of adding promoters, including TBAB, TBAF, TBANO3 and THF, on the CO2 þH2 hydrate equilibrium conditions are shown in Figs. 18 and 19. Kumar et al. [18,43] analyzed the composition of the formed hydrate with 0.4 CO2 þ 0.6 H2 gas mixture in water using ATR-IR spectroscopic and NMR techniques. The hydrate was found to show sI structure with a hydration number of 6.92. In the hydrate, the large cages were 100% occupied by CO2 while 23% of the small cages were filled by H2 and 6% by CO2 and the rest remained empty. The amount ratio of CO2 to H2 in hydrate was about 0.93 to 0.07. The authors then conducted the similar tests on the gas mixture of 0.383CO2 þ 0.585H2 þ0.032C3H8, and found that the addition of small quantity of C3H8 changed the hydrate structure from sI to sII. Furthermore, 79% of the large cages of sII hydrates were taken by CO2 while the others were taken by C3H8, and the occupancy ratio of small cages by CO2, H2 and C3H8 were 20%, 2.9% and 0%, respectively. Therefore, the amount ratio of CO2, H2 and C3H8 captured by the solid hydrates was 76.2:4.0:19.8. Babu et al. [121] also examined the effects of small quantity of C3H8 on the hydrate formation of CO2 þH2 gas mixture. The hydrate equilibrium pressure of gas mixture 0.381 CO2 þ0.594 H2 þ0.025 C3H8 were found to be much lower than that of 0.4 CO2 þ0.6 H2, e.g. reduced by 66% at the temperature of 5.25 °C. The dissociation heat of the ternary hydrate obtained by Clausius–Clapeyron method was about 110 kJ/mol (hydrate) and the hydrate structure was concluded to be sII based on the similar investigations of Kumar [18,43]. However, the addition of 1 mol% C3H8 to the mixture of 0.8 CO2 þ 0.2 H2 did not change the hydrate structure, and the propane seemed to work as diluent gas. The dissociation heat of hydrate formed with gas mixture 0.8CO2 þ0.188H2 þ0.012C3H8 in water was about 78 kJ/mol (hydrate).

1286


Table 5 Thermo-physical properties of hydrate of CO2 þ N2/H2/CH4 gas mixture. Authors

Gas mixture

Water/ promoter

Hydrate compound

Kang et al. [29]

0.17CO2 þ0.83N2

Water

0.70CO2 þ 0.30N2 0.17CO2 þ0.83N2

Deschamps and Dalmazzone [98]

Dissociation heat

Method involved

5.43CO2 1.89N2 46H2O 6.28

64.59 kJ/mol gas

Water 1 mol% THF

7.08CO2 0.25N2 46H2O 6.28 2.96CO2 9.47N2. 5.71 11.39THF 136H2O

63.41 kJ/mol gas 109.01 kJ/mol gas

Clausius–Clapeyron and calorimetry 0.5 °C, 0.1 MPa

0.17CO2 þ0.83N2

3 mol% THF

6.10

118.94 kJ/mol gas

0.70CO2 þ 0.30N2

1 mol% THF

5.79

107.18 kJ/mol gas

0.70CO2 þ 0.30N2

3 mol% THF

2.35CO2 7.42N2. 12.53THF 136H2O 9.97CO2 2.58N2. 10.94THF.136H2O 8.11CO2 2.19N2 13.16THF 136H2O

5.80

113.66 kJ/mol gas

0.249CO2 þ 0.751N2

40 wt% TBAB 40 wt% TBAB

0.499CO2 þ 0.501CH4

Lee et al. [111]

0.20CO2 þ 0.80N2 0.10CO2 þ 0.90N2

Water Water

Bouchafaa and Dalmazzone [114]

0.5CO2 þ 0.5N2

Water

0.1CO2 þ0.9N2

Water

0.5CO2 þ0.5H2

Water

0.5CO2 þ0.5CH4

Water

0.3CO2 þ 0.7N2

40 wt% TBAB 40 wt% TBAB 40 wt% TBAB

0.5CO2 þ 0.5N2 0.75CO2 þ 0.25N2

0.25CO2 þ 0.75CH4

40 wt% TBAB

0.5CO2 þ 0.5CH4

40 wt% TBAB 40 wt% TBAB

0.75CO2 þ 0.25CH4

sI sI

6.08 6.00

Kumar et al. [116]

0.392CO2 þ 0.608H2 0.579CO2 þ0.421H2 0.833CO2 þ 0.167H2 0.383CO2 þ 0.585H2 þ0.032C3H8

Water Water Water Water

sI sI sI sII

Kumar et al. [18,43]

CO2 0.4CO2 þ 0.6H2

Water Water

0.383CO2 þ 0.585H2 þ0.032C3H8

Water

Babu et al. [121]

0.381CO2 þ 0.594H2 þ0.025C3H8

Water

sI, θS ¼0.81, θL ¼ 1.0 sI, θL, CO2 ¼ 1.0 (1.0) θS, CO2 ¼ 0.06 (0.0) θS, H2 ¼0.23 (0.25) sII, θL, CO2 ¼ 0.79 (0.57) θS, CO2 ¼ 0.20 (0.34) θS, H2 ¼0.029 (0.006) θL, C3H8 ¼ 0.21 (0.43) sII

Sum et al. [38]

0.574CO2 þ0.426CH4

Water

0.341CO2 þ 0.659CH4

Water

θL, θL, θS, θL, θL, θS,

Hydration number

CO2 ¼ 0.787–0.812

342.25–394.12 kJ/ kg H2O 333.95–391.32 kJ/ kg H2O

Calorimetry (2.91–9.18 MPa)

51.7 kJ/mol gas 50.1 kJ/mol gas

Calorimetry

359.63–468.95 kJ/ kg hydrate 389.72– 444.35 kJ/kg hydrate 310.37– 432.26 kJ/kg hydrate 449.83– 472.77 kJ/kg hydrate 206.3–235.28 kJ/ kg hydrate 194.9–224.4 kJ/ kg hydrate 192.68– 237.73 kJ/kg hydrate 194.32– 242.62 kJ/kg hydrate 192.81–225 kJ/kg hydrate 215–239 kJ/kg hydrate

Calorimetry

847 10%

Clausius–Clapeyron 0.75–8.45 °C

6.04 6.92 (7.09)

Calorimetry (1.14–3.20 MPa)

ATR-IR spectroscopy (NMR test results are shown in parentheses)

11.7 (10.1)

110 kJ/mol hydrate

7.42–7.45

Clausius–Clapeyron 2.15–10.15 °C 2.51–7.95 MPa Raman spectroscopy 0–5 °C

CH4 ¼ 0.175–0.197 CH4 ¼ 0.126–0.147 CO2 ¼ 0.604–0.632

7.27–7.32

CH4 ¼ 0.355–0.381 CH4 ¼ 0.190–0.208

A high pressure optical cell was employed by Hashimoto et al. [126] to measure the pressure–composition equilibrium of CO2 þH2 þTHF þwater system at 7 °C, and the results are shown in

Fig. 19(b). THF aqueous solution with 5.6 mol% concentration was found as the most remarkable promoter in pressure reduction compared with 3 mol% and 8 mol% THF aqueous solutions. The


1287

12 12

CO2+H2+water+TBAB

10

11

CO2 ≈ 40 mol%

9

10

8

9

Pressure (MPa)

Pressure (MPa)

13

CO2+H2+water

11

7 6 5 4

8 7 6

CO2 hydrate

5 4 3

3

2

2

CO2 hydrate

1

1

0

0 0

1

2

3

4

5

6

7

8

9

10

-1

11

0

2

4

6

8

Temperature (°C) Fig. 17. Phase equilibrium data of CO2 þ H2 þwater system, Kumar et al. [116], ■ 0.392 CO2 þ 0.608 H2, 0.579 CO2 þ 0.421 H2, ▲ 0.833 CO2 þ 0.167 H2, ▼ 0.383 CO2 þ0.585 H2 þ0.032 C3H8; Mohammadi et al. [117], □ 0.3952 CO2 þ 0.6048 H2, ○ 0.7501 CO2 þ 0.2499 H2; Li et al. [118], △ 0.392 CO2 þ 0.608 H2; Park et al. [119], ▽ 0.4 CO2 þ0.6 H2; Kang et al. [120], ⊠ 0.415 CO2 þ 0.585 H2; Bouchafaa and Dalmazzone [114], 0.5 CO2 þ 0.5 H2; Babu et al. [121], ☆ 0.381 CO2 þ0.594 H2 þ 0.025 C3H8, ✴ 0.8 CO2 þ 0.188 H2 þ 0.012 C3H8.

2.4.3. Hydrates of CO2 þCH4 and CO2 þCH4 þ promoters CO2 and CH4 are the major components of natural gas and landfill gas, and gas hydrate is one of the effective methods to separate and purify these two gases. Moreover, CO2 was intensively investigated to replace methane from methane hydrate. Therefore, it is important to measure the phase equilibrium data of the CO2 þCH4 hydrates. Phase equilibrium data of CO2 þCH4 þwater and CO2 þCH4 þ waterþpromoter systems are shown in Figs. 20 and 21, respectively. Sum et al. [38] used Raman spectrum to analyze the structure of the double hydrate of CO2 þCH4. The formed hydrate had structure sI with the large cavities being filled with both the gases while small fraction of small cavities being filled with CH4. The mass ratio of CO2 to CH4 in the hydrate was about 3.2–3.74 when the molar fraction of CO2 in CO2 þ CH4 gas mixture was 0.5745, and this mass ratio became about 1.3–1.5 when the molar fraction of CO2 was 0.3412. The hydration number was around 7.27–7.45, and the occupancy ratio of CH4 increased with increasing system temperature or pressure. Deschampsa and Dalmazzone [98] studied the promotion effect of 40 wt% TBAB aqueous solution for the hydration with gas mixture of 0.499CO2 þ 0.501CH4. The dissociation heat tested by DSC was in the range of 333.95–391.32 kJ/kg (H2O) for CO2 þCH4 þTBAB hydrate at the pressure of 1.14–3.20 MPa. Bouchafaa and Dalmazzone [114] also measured the hydrate phase equilibrium temperatures and dissociation heats with gas mixture of CO2 þCH4 in pure water and in TBAB aqueous solution using a DSC. Similar to those of CO2 þ N2 hydrates, the dissociation heats of CO2 þCH4 hydrates increased with gas pressure, as shown in Table 5. Fan et al. [127] compared the promotion effects of TBAB, TBAC and TBAF on the hydration of gas mixture of 0.33 CO2 þ0.67CH4, when these aqueous solutions were with 5 wt% TBAB, 4.3 wt% TBAC and 4.1 wt% TBAF, respectively. The best promoter was found to be TBAF due to the largest pressure reduction. Fan and Guo [128] also measured the hydrate equilibrium conditions of CO2 þ CH4 in 10 wt% NaCl solution, and it revealed that the addition of NaCl hindered the hydrate formation as the corresponding hydration pressure became larger at the same temperature comparing to using pure water. In conclusion, the hydration pressure of gas mixtures is generally in-between the hydration pressures of each gas components, which was at the level of several to a dozen MPa. Using the promoters, the

12

14

16

18

20

16

CO2+H2+water+TBAB 14

CO2 ≠ 40 mol%

12

Pressure (MPa)

Raman spectroscopy test results showed that CO2 and H2 molecules were competitively enclathrated in the small cages of the formed sII hydrate while THF molecules occupied the large cages.

10

Temperature (°C)

10 8 6

CO2 hydrate 4 2 0 0

2

4

6

8

10

12

14

16

18

Temperature (°C) Fig. 18. Phase equilibrium data of CO2 þH2 þ waterþ TBAB system, (a) about 40 mol% of CO2: Mohammadi et al. [117], 0.3952 CO2 þ 0.6048 H2 þ TBAB, ⊞ 5 wt%, 30 wt%; Li et al. [118], 0.392 CO2 þ0.608 H2 þTBAB, ■ 2.45 wt%, 3.63 wt%, ▲ 4.95 wt%, ▼ 8.26 wt%, ◄ 15.32 wt%, ► 32.94 wt%; Park et al. [119], 0.4 CO2 þ 0.6 H2 þTBAB, ◧ 9.76 wt%, ◐ 40.76 wt%, ◭ 59.9 wt%; Xu et al. [122], 0.4 CO2 þ 0.6 H2 þ TBAB, □ 4.95 wt%; Wang et al. [123], 0.4 CO2 þ 0.6 H2 þ TBAB, ☆ 5 wt%,þ 10 wt%, ✴ 20 wt%; Kim et al. [124], 0.4 CO2 þ 0.6 H2 þ TBAB, ○ 8.26 wt%, △ 15.3 wt%, ▽ 35.6 wt%, ◊ 53.3 wt%. (b) Other compositions of CO2 þ H2: Mohammadi et al. [117], 0.1481 CO2 þ 0.8519 H2 þTBAB, ▲ 5 wt%, ▼ 30 wt%; Mohammadi et al. [117], 0.7501 CO2 þ 0.2499 H2 þTBAB, ◆ 5 wt%, ◄ 30 wt%; Li et al. [118], 0.185 CO2 þ 0.815 H2 þ TBAB, □ 2.45 wt%, ○ 3.63 wt%, △ 4.95 wt%, ▽ 8.26 wt%, ◊ 15.32 wt%; Xu et al. [122], 0.1 CO2 þ 0.9 H2 þ TBAB, ■ 4.95 wt%; Xu et al. [122], 0.18CO2 þ0.82 H2 þTBAB, 4.95 wt%; Wang et al. [123], 0.6 CO2 þ 0.4 H2 þTBAB, ◧ 5 wt%, ◐ 10 wt%, ◭ 20 wt%. Percentages are the used TBAB solution concentrations.

hydration pressure of CO2 þ N2/H2/CH4 could be reduced to 0.1– 1.0 MPa depending on system temperature and the promoters. However, comparing to the use of pure water, the addition of promoters may lead to relatively less CO2 and more N2 captured. The existence of pollutant, like SO2 in CO2 þ N2 gas mixture and C3H8 in CO2 þH2 gas mixture leads to the hydrate formation pressure reduction. However, the pollutant molecules may occupy some cavities in the hydrates, which would reduce the amount of captured CO2. More researches should be conducted to obtain the dissociation heat of the hydrate, gas occupancy in cavities, compositions of gas mixture in hydrate before and after adding promoters.

3. CO2 capture and separation performance by hydrate technology CO2 capture performance by hydrate technology could be evaluated from many aspects. In this section, the evaluation parameters are introduced and then CO2 capture and separation from CO2 þN2/H2/CH4 gas mixtures is discussed.

1288


8

9

7

7

6

6

5

Pressure (MPa)

Pressure (MPa)

CO2+H2+water+TBAF/TBANO 3 8

5 4 3

CO2 hydrate

4 3 2 1

2 1

0

CO2 hydrate

0

-1 0

2

4

6

8

10

12

14

16

18

20

22

24

26

28

30

6

7

8

9

10

8

Pressure (MPa)

7 6

CO2+H2+water+THF Concentration of THF solution 0 mol% 3 mol% 5.6 mol% 8 mol%

5 4 3 2 1 0 0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Concentration of H2 Fig. 19. Phase equilibrium data of (a) CO2 þ H2 þwaterþTBAF/TBANO3 system: Park et al. [119], 0.4 CO2 þ0.6 H2 þTBAF, ■ 0.8 mol%, 3.3 mol%, ▲ 5.3 mol%; Babu et al. [125], 0.4 CO2 þ0.6 H2 þTBANO3, □ 0.5 mol%, ○ 1.0 mol%, △ 2.0 mol%, ▽ 3.0 mol%, ◁ 3.7 mol%. (b) CO2 þ H2 þwater þTHF system at 7 °C, Hashimoto et al. [126]. Percentages are the used solution concentrations.

CO2+CH4+water

8

Pressure (MPa)

5

CH4 hydrate

U¼

ngas;H nH2 O

ngas;H

Δt nH2 O

3

Cw ¼

2 1

CO2 hydrate 0 1

2

3

15

16

17

18

19

20

ð8Þ

ð9Þ

where Δt is in the unit of hour in the present paper, then the unit of rate of consumption is mol per hour per mol water/ solution. (4) Conversion ratio of water to hydrate.

6

0

14

(1) Induction time. As shown in Fig. 22, the induction time of the hydration usually refers to the time length from the gas–liquid contact to the hydrate formation, which is the sum of dissolution time and the nucleation time, which ranges from several minutes to hundreds of hours. (2) Gas consumption. Gas consumption is the molar number of the gas consumed by the hydration per mole water/solution, and it increases rapidly within a certain period after the hydrate nucleation and hydration starts, thereafter its profile is nearly flat, as shown in Fig. 22. The following equation is used to calculate the gas consumption.

v¼

7

4

13

where ngas, H is the molar number of gas in the hydrate phase, nH2O is the total molar number of water/solution. (3) Rate of consumption. This parameter describes the velocity of the gas hydration.

10 9

12

Fig. 21. Phase equilibrium data of CO2 þ CH4 þ waterþ promoter system, Deschamps and Dalmazzone [98], 0.499 CO2 þ 0.501 CH4 þTBAB, ■ 40 wt%; Bouchafaa and Dalmazzone [114], 0.5 CO2 þ 0.5 CH4 þ TBAB, ◄ 10 wt%, ▼ 20 wt%, ▲ 30 wt%, 40 wt%; Mohammadi et al. [117], 0.4029 CO2 þ0.5971 CH4 þTBAB, ◆ 5 wt%, ► 30 wt%; Acosta et al. [131], 0.4 CO2 þ 0.6 CH4 þ TBAB, □ 5 wt%, ○ 10 wt%, △ 20 wt%; Acosta et al. [131], 0.6 CO2 þ 0.4 CH4 þ TBAB, ▽ 5 wt%, ◊ 10 wt%, ◁ 20 wt%; Fan et al. [127], 0.33 CO2 þ 0.67 CH4, ☆ 5 wt% (TBAB), ✴ 4.3 wt% (TBAC), 4.1 wt% (TBAF). Percentages are the used solution concentrations.

10 9

11

Temperature (°C)

Temperature (°C)

4

5

6

7

8

9

10

11

12

13

14

15

Temperature (°C)

Fig. 20. Phase equilibrium data of CO2 þCH4 þwater system, Fan et al. [127,128], ■ 0.965 CO2 þ 0.035 CH4, 0.33 CO2 þ 0.67 CH4; Mohammadi et al. [117], ▲ 0.4029 CO2 þ 0.5971 CH4; Bouchafaa and Dalmazzone [114], ▼ 0.5 CO2 þ0.5 CH4; Seo et al. [129], ◄ 0.6 CO2 þ 0.4 CH4, ► 0.2 CO2 þ0.8 CH4; Adisasmito et al. [21], □ 0.08 CO2 þ 0.92 CH4, ○ 0.22 CO2 þ0.78 CH4, △ 0.4 CO2 þ 0.6 CH4, ▽ 0.68 CO2 þ 0.32 CH4, ◁ 0.75 CO2 þ0.25 CH4; Servio et al. [130], ☆ 0.2 CO2 þ 0.8 CH4, ✴ 0.5 CO2 þ 0.5 CH4.

3.1. Performance parameters The hydration process can be described and quantified based on different parameters.

ðngas;H þnadd;H Þ N nH2 O

ð10Þ

where nadd, H is the molar number of the added promoters in the hydrate phase and N is the hydration number. (5) Recovery fraction. R¼

ngas;H ngas;feed

ð11Þ

where ngas, feed is the molar number of the certain gas in the feed gas mixture. (6) Separation factor. This factor can be calculated by Eq. (12), and it reflects the CO2 selectivity of the hydration from the feed gas mixture. S¼

nCO2 ;H ngas2;G ngas2;H nCO2 ;G

ð12Þ


Fig. 22. Gas consumption vs time for hydrate formation [16].

where nCO2, H and ngas2, H are the molar numbers of CO2 and the other gas in the hydrate phase, respectively; while nCO2, G and ngas2, G are the molar numbers of CO2 and the other gas remaining in the gas phase. 3.2. CO2 capture and separation performance from CO2 þN2 gas mixture Linga et al. [132,133] used pure water to separate CO2 from 0.169 CO2 þ 0.831 N2 flue gas at 0.55 °C. The required hydration pressure in pure water was as high as 9.0–11.0 MPa to generate enough driving force. The induction time was as long as 10.3–1063 min as using fresh water, and the even worse thing was that no hydration was found if the pressure was not high enough. A better performance was achieved by using memory water which had already experienced hydration process, and its induction time was shortened to 6.3–154 min. Using the hydration method, about 36.7– 42.1 mol% CO2 was captured; however, CO2 concentration in the hydrate phase was only 55.1–57.3 mol% which indicated that considerable amount of N2 was captured by the hydrate formed in pure water, and the separation factor was in the range of 5.3–13.2. When 1.0 mol% THF aqueous solution was used instead of pure water, the hydration pressure dropped down to only 1.5 MPa; however, the authors found that the hydrate growth rate reduced compared to that using pure water. Linga et al. [134] then designed and tested a new apparatus to accelerate the hydrate formation of CO2 þN2 gas mixture in THF aqueous solution. The apparatus comprised a mechanically agitated gas-inducing crystallizer which could enhance the contact between gas and liquid and thus increase the hydrate formation rate. With this newly-designed apparatus and 1.0 mol% THF aqueous solution, the authors managed to reduce the induction time to 10.7–70.3 min, and had it further down to less than 2 min if memory THF aqueous solution was used. When the concentration of THF aqueous solution was 1.5 mol%, the induction time was only 4.0 min and 0.3 min, respectively for fresh and memory solutions. By using THF as promoter, about 60 mol% CO2 in the mixture was captured by the hydrate; however, more N2 was captured at the same time comparing to that of using pure water, and in this instance the separation factor was only around 4. Tang et al. [135] compared the performance of employing sodium dodecyl sulfate (SDS) and THF as promoters to capture CO2 from 0.59 CO2 þ0.41 N2 gas mixture. The addition of SDS could speed up the hydration process, and the optimal concentration was concluded to be 100–300 ppmv. The usage of 0.5–3.0 mol% THF aqueous solution improved CO2 recovery fraction from 0.54 to 0.71– 0.85 comparing to that with pure water; however, similar to the results obtained by Linga et al. [134], the separation factors reduced

1289

from 22.7 to 4–6 by adding THF to water. Experiments done by Daraboina et al. [136] showed quite low CO2 recovery fraction from 0.17CO2 þ0.83N2 gas mixture, which was only 0.04 when using pure water, meanwhile the separation factor was 4. The presence of 1.0 mol% SO2 in the gas mixture was found favorable for the hydrate formation, and improved CO2 recovery fraction and separation factor to 0.09 and 13, respectively. Daraboina et al. then added 1.0 mol% THF as the promoter into water, and found it effective in reducing the hydration pressure and the induction time; however, it also decreased both the hydrate formation rate and final gas consumption with CO2 separation factor of only 2. Li et al. [137] studied the performance of CO2 capture from 0.199CO2 þ0.801N2 gas mixture at 4.5 °C and the pressure range of 4.3–7.3 MPa by using 5 wt% TBAB aqueous solution. The induction time was found to be just 5 min. CO2 molar concentration in remaining gas phase after capture was about 0.08–0.1 while that in hydrate phase was 0.348–0.382. The CO2 recovery fraction and separation factor were in the range of 0.4–0.45 and 5.3–7.3, respectively. Li et al. [138] added different concentration dodecyl trimethylammonium chloride (DTACl) to 0.29 mol% (4.95 wt%) TBAB aqueous solution for CO2 capture. The authors proposed a two-stage capture, with 0.17CO2 þ0.83N2 gas mixture in the first stage and 0.65CO2 þ0.35N2 gas mixture in the second stage. The addition of 140–560 ppmv DTACl to TBAB aqueous solution accelerated the hydrate formation, reduced the induction time, improved CO2 recovery fraction and enriched CO2 concentration in hydrate phase. The optimal condition identified for CO2 separation was initial pressure of 1.66 MPa and 280 ppmv DTACl, which had the recovery fraction of 0.29–0.56 and separation factor of 9.6 in the first stage capture, and recovery fraction of 0.39 and separation factor of 62.25 in the second stage capture. Xu et al. [139] built and tested a twostage pilot-scale system to capture CO2 from CO2 þ N2 gas mixture using 0.29 mol% TBAB aqueous solution, with 0.17CO2 þ0.83N2 gas mixture in the first stage and 0.65CO2 þ 0.35N2 gas mixture in the second stage. The authors concluded that the flow rate of feed gas had positive effect on the gas consumption in the first stage capture, and for the second stage capture, there was an optimum gas flow rate corresponding to a certain TBAB solution flow rate, at which the gas consumption was the highest. The corresponding CO2 recovery fractions and separation factors are given in Table 6. Li et al. [141] compared CO2 capture performances of TBAB, TBPB and TBANO3 aqueous solutions from 0.17 CO2 þ 0.83 N2 gas mixture, where 0.29 mol%, 0.65 mol% and 1.0 mol% TBAB/TBPB aqueous solution and 0.65 mol% and 1.0 mol% TBANO3 aqueous solution were used. The authors pointed out high CO2 solubility in the aqueous solution benefited the capture. CO2 solubility in TBANO3 aqueous solution was as high as it was in pure water and higher than that in TBAB/TBPB aqueous solutions. The hydration induction time in the aqueous solution could be shortened to less than 5 min under each certain operation condition. TBANO3 aqueous solutions had the best capture performance among all the tested solutions as it captured about 67.0 mol% CO2, resulting in around 7.0 mol% CO2 in the remaining gas mixture with the corresponding separation factor of 15.5, whereas the recovery fractions and separation factors for 1.0 mol% TBPB aqueous solution and 0.65 mol% TBAB aqueous solution were 0.53–0.62, 11.4–14 and 0.41–0.47, 10.4–12.9, respectively. Therefore as a promoter for CO2 separation, the performance was in the order of TBANO3 4TBPB4 TBAB. Fan et al. [142] compared the effect of TBAB and TBAF on CO2 hydration capture from 0.166CO2 þ0.834N2 gas mixture. The addition of TBAB and TBAF was proved to effectively accelerate the hydrate formation, and achieved similar CO2 recovery fraction. About 30–60 mol% CO2 were captured by the hydration and the recovery fraction decreased as the increase of the pressure. However, TBAF was more preferable than TBAB judging by the separation factor, which could

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Table 6 CO2 capture and separation performance from CO2 þ N2 mixture. Reference

Results

Temperature (°C) Pressure (MPa)

Induction time (min)

Separation performance

Water

0.55

9, 10, 11 (ΔP¼ 1.3, 2.3, 3.3)

10.3–1063 (fresh) 6.3–154 (memory)

The addition of THF reduced the induction time and the operating pressure; however, the hydration rate decreased.

1 mol% THF

0.55

1.5

o 1

rCO2, g ¼0.097–0.109; rCO2, H ¼ 0.551–0.573; R¼ 0.367–0.421; S¼ 5.3–13.2 rCO2, g ¼0.104;

1.0 mol% THF

0.55

1.5 (ΔP ¼1.2) 2.5 (ΔP ¼2.2)

10.7–70.3, but o 2 min using memory solution

The crystallizer enhanced the contact of gases with water and thus the rate of hydrate crystallization increased. However, required mechanical power increased significantly. Comparing to pure water, the usage of THF aqueous solution increased CO2 recovery rate, however, the separation factor was lower.

1.5 mol% THF

0.55

2.3 (ΔP ¼2.2)

4.0 min using fresh solution, but 0.3 min using memory solution

rCO2, g ¼0.092–0.10; rCO2, H ¼ 0.351–0.383; U¼ 0.009–0.0181; v¼ 0.0012–0.0023; Cwater ¼ 0.076–0.154; R¼ 0.60–0.63; S¼ 4.12–4.52; rCO2, g ¼0.105; rCO2, H ¼0.321; U¼ 0.0163–0.0164; Cwater ¼ 0.139–0.141; R¼ 0.58; S ¼3.88;

Water

1.4

5.0

Water with 10–1000 ppm 1.4 SDS

5.0

SDS can speed up the hydrate growth rate, the optimum concentration of SDS was 100–300 ppm. The usage of THF reduced the hydrate formation pressure and increased the gas recovery fraction but the separation factor of CO2 decreased.

0.5–3.0 mol% THF

1.4

4.8

rCO2, g ¼0.425 ; R ¼0.54; S¼ 22.7 ; rCO2, g ¼0.39–0.45 ; R¼ 0.57–0.658; S¼ 5.58–7.5 ; rCO2, g ¼0.35–0.385 ; R¼ 0.705–0.85; S¼ 4– 6;

Water

0.55

10

43–86

0.17CO2 þ 0.82N2 þ 0.01SO2 Water

0.55

9.6

10–19

Small amounts of SO2 increased the stability of the CO2 þN2 double hydrate. The addition of THF reduced the hydrate formation rate and also the gas consumption.

0.17CO2 þ 0.82N2 þ 0.01SO2 1 mol% THF

0.55

2.45

4–6

rCO2, H ¼ 0.46; R ¼0.04; S¼ 4; rCO2, H ¼ 0.43; R ¼0.09; S¼ 13; rCO2, H ¼ 0.365; R¼ 0.09; S¼ 2;

Li et al. [137]

0.199CO2 þ 0.801N2

5 wt% TBAB

4.5

4.3–7.3

5

rCO2, g ¼0.08–0.10; rCO2, H ¼ 0.348–0.382; R¼ 0.4–0.45; S ¼5.3– 7.3;

The hydration rate increased with increasing feed gas pressure.

Li et al. [138]

0.17CO2 þ 0.83 N2

0.29 mol% TBAB

1.8

0.66–2.66

14–48

1.8

0.66–2.66

0.28–19

0.65CO2 þ 0.35 N2

0.29 mol% TBAB with 140–560 ppm DTACl 0.29 mol% TBAB 0.29 mol% TBAB with 140–560 ppm DTACl

4

0.66–2.66

2.1–12 0–2

rCO2, H ¼ 0.54–0.61; R¼ 0.13–0.23; rCO2, H ¼ 0.483–0.673; R¼ 0.29–0.56; S ¼9.6; rCO2, H ¼ 0.94–0.96; rCO2, H ¼ 0.992; R¼ 0.39;S¼ 62.25;

The addition of DTACl to TBAB aqueous solution speeded up the hydrate formation, improved CO2 recovery fraction and enriched CO2 in hydrate phase. The optimized condition for CO2 separation initial pressure of 1.66 MPa and 280 ppm DTACl.

0.17 CO2 þ 0.83 N2

0.29 mol% TBAB

2.5

1.0–2.5

rCO2, g ¼0.089–0.118; rCO2, H ¼ 0.506–636;

The gas flow rate had a positive effect on the gas consumption. There was an optimum gas flow rate at a certain fluid flow rate

0.169CO2 þ0.831N2

Linga et al. [134] 0.169CO2 þ0.831N2

Tang et al. [135]

Daraboina et al. [136]

Xu et al. [139]

0.59CO2 þ 0.41N2

0.17CO2 þ 0.83N2

Water/promoter

Other conclusions


Working condition

Linga et al. [132,133]

Gas mixture

0.65 CO2 þ0.35 N2

0.29 mol% TBAB

2.5

1.0–2.5

Belandria et al. [140]

0.151 CO2 þ0.849 N2 0.399 CO2 þ0.601 N2 0.749 CO2 þ 0.251 N2

5 wt%, 30 wt% TBAB

2–16.06

0.581–19.085

Li et al. [141]

0.17 CO2 þ 0.83 N2

0.29 mol% TBAB

2, 3, 4

2.0, 2.5, 3.3

0.65 mol% TBAB

R¼ 0.394–0.576; S¼ 8.5–15.3; rCO2, g ¼0.522–0.566; rCO2, H ¼ 0.832–0.897; R¼ 0.234–0.395; S¼ 4.0–7.6; CO2 can be separated from high to low concentrated gas mixtures at reasonable operating conditions in the presence of TBAB aqueous solutions. 2–23 0–12.5

Fan et al. [142]

Duc et al. [143]

0.29 mol% TBPB 0.65 mol% TBPB 1 mol% TBPB

2, 3, 4

2.0, 2.5, 3.3

0.65 mol% TBANO3 1 mol% TBANO3

1, 2 1, 2

2.5, 3.3, 4.0 2.5, 3.3, 4.0

0.166 CO2 þ 0.834 N2

0.293 mol% TBAB

4.5

3.36–7.31

0.166 CO2 þ 0.834 N2

0.293 mol% TBAF

4.5

2.19––6.79

0.166 CO2 þ 0.834 N2

0.293 mol% TBAF

7.1

2.39–6.45

0.535CO2 þ 0.465 N2

0.293 mol% TBAF

4.5

0.74–2.23

0.374 CO2 þ0.626 N2

0.29 mol% TBAB

12

2.01

0–61 0–31

2.5–22

rCO2, g ¼0.079–0.081 rCO2, H ¼ 0.61–0.064; R¼ 0.65–0.67; S¼ 14.5–15.5; U¼ 0.008–0.012a rCO2, g ¼0.05–0.071; rCO2, H ¼ 0.226–0.365; R¼ 0.30–0.53; S ¼3.7– 9.8; rCO2, g ¼0.032–0.054; rCO2, H ¼ 0.4–0.566; R¼ 0.34–0.56; S ¼11.6– 37; rCO2, g ¼0.032–0.043; rCO2, H ¼ 0.354–0.545; R¼ 0.31–0.44; S¼ 12.1–32.2; rCO2, g ¼0.306–0.345; rCO2, H ¼ 0.833–0.904;

TBAF had better performance than that of TBAB as a promoter for CO2 capture.

rCO2, g ¼0.175, rCO2,

The gas storage capacity of hydrates was about 30– 35 m3/m3 of hydrates

H ¼0.789;

13

2.22

TBANO3 solution had the best CO2 capture performance based on the kinetic behavior.


1 mol% TBAB

rCO2, g ¼0.01; U¼ 0.0037–0.0057a R¼ 0.41–0.47; S¼ 10.4–12.9; U¼ 0.0044–0.007a rCO2, g ¼0.088–0.091; rCO2, H ¼ 0.61–0.63; U¼ 0.0043–0.0075a U¼ 0.0038–0.0057a U¼ 0.0061–0.0088a rCO2, g ¼0.083 rCO2, H ¼ 0.5–0.56 R¼ 0.53–0.62; S ¼11.4– 14 U¼ 0.0063–0.0094a

rCO2, g ¼0.205, rCO2, H ¼0.927;

0.375 CO2 þ 0.625 N2

0.29 mol% TBAB

12

2.05

rCO2, g ¼0.174, rCO2, H ¼0.783;

0.103 CO2 þ 0.897 N2

0.29 mol% TBAB

13

2.26

12

3.28

13

3.4

1291

rCO2, g ¼0.023, rCO2, H ¼0.918; rCO2, g ¼0.061, rCO2, H ¼0.275; rCO2, g ¼0.066, rCO2, H ¼0.285;

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Table 6 (continued ) Reference

Adeyemo et al. [146]

a b

0.17CO2 þ 0.83N2

0.166 CO2 þ 0.834 N2

Water/promoter

Working condition

Results



Water þ silica gel (pore size 30 nm)

1

8.0–9.0


1

8.0–9.0

1.0 mol% THF þ silica gel (pore size 100 nm)

1, 1

5.0

Cyclopentane/water emulsion (1:5 volume ratio) Cyclopentane

8.1

2.6–3.66

8.1

2.49–3.95

U is calculated based on mole number of water in 150 mL TBAB/TBPB/TBANO3 solution, density is roughly estimated at 1000 kg/m3. U is calculated based on mole number of the used 35 mL water.

Other conclusions Separation performance

rCO2, g ¼0.147–0.149; rCO2, H ¼ 0.38–0.42; R¼ 0.16–0.21; S ¼3.2– 8.4; Cwater ¼ 0.058–0.147; U¼ 0.009–0.023b rCO2, g ¼0.102–0.113; rCO2, H ¼ 0.45–0.48; R¼ 0.41–0.51; S¼ 3.69–9.86; Cwater ¼ 0.301–0.446; U¼ 0.048–0.071b; rCO2, g ¼0.147–0.148; Cwater ¼ 0.0865– 0.0984; U¼ 0.01–0.011b

Gels with large pores and particle size were found to enhance the gas consumption. Addition of THF reduced the operating pressure in the crystallizer but it also reduced the gas consumption.

rCO2, g ¼0.12–0.14; rCO2, H ¼ 0.29–0.35; S¼ 2.4–4.01; rCO2, g ¼0.11–0.12; rCO2, H ¼ 0.38–0.44; S¼ 4.5–6.2;

Hydrate formation rate could be increased remarkably with cyclopentane/water emulsion, however, its separation factor was lower than using cyclopentane only.


Li et al. [147]

Gas mixture


be up to 37 with TBAF as promoter while it was not more than 10.0 using TBAB. Duc et al. [143] used 0.29 mol% TBAB aqueous solution to realize CO2 separation from gas mixtures of CO2 þN2. They found that the CO2 concentration in the hydrate was at least four times higher than that in the gas phase after capture. The gas storage capacity of the hydrate was 30–35 m3 gas /m3 of hydrates. The authors also numerically simulated a CO2-hydrate capture system to evaluate the overall energy consumption and the cost-effectiveness. It turned out that the system operation cost was 14.5–29.6 €/ton CO2 depending on the inlet CO2 concentration and gas pressure, which was lower comparing to the 20–30 €/ton using classic capture method like membranes, amines and so on. The majority of the operation cost came down to the electricity consumption by compressors, which accounted for 50–80% of the total cost. The production cost, including investment, variable cost and maintenance cost and so on, was estimated as 20–40 €/ton. It was also concluded that the hydration method could be more competitive when the gas mixture was at higher pressure. To overcome the limitation of liquid–gas contact during hydration process, Kumar et al. [144] employed porous silica gel saturated with water inside the fixed bed crystallizer. Liquid was absorbed by this porous material and dispersed inside the pores of silica gel, and the gas can penetrate into these pores; thus the contact between gas and liquid was enhanced due to large surface area of silica gel. The use of silica gel had a positive effect on CO2 hydration by reducing the induction time and boosting the gas consumption. The results also proved that the addition of SDS would enhance the performance further, as the similar conclusion was obtained by other researchers [145]. Adeyemo et al. [146] tested the effectiveness of silica gels with 30 and 100 nm pore size to improve the contact between gas and water/THF aqueous solution for CO2 separation from CO2 þN2 gas mixture. The large particle size and large pore size of silica gel favored the gas consumption. The addition of 1.0 mol% THF reduced the hydrate formation pressure; however, it also significantly reduced the final gas consumption and the separation efficiency due to the blockage of THF hydrate in the silica gel pores. The use of silica gel was concluded to be more suitable for CO2 capture from a flue gas with high CO2 concentration. Shown in Fig. 23 are the summarized CO2 recovery fraction and separation factor using hydration technology from CO2 þN2 gas mixture consisting of around 17 mol% CO2 and 83 mol% N2. The usage of promoters reduced the hydration pressure dramatically, and also increased the CO2 recovery fraction which was in the range of 0.1–0.9, leading to the enhancement of hydration process as about 30–65 mol% CO2 being captured by hydrates; meanwhile, the separation factor of CO2 from CO2 þN2 gas mixture still remained in the range of 3–15, which was not improved comparing to that using pure water, as shown in Fig. 23(b). Some experimental tests concluded that the usage of promoters accelerated the induction time but deteriorated the hydration speed; the use of some surfactant, like SDS and DTACl had the potential to improve the capture and separation performance; there were also some studies which concluded that use of porous water-saturated support material benefited the gas–water contact and improved the gas consumption; however the combination with promoters resulted in a lower gas consumption and separation efficiency since the formed promoter hydrate could block the porous structure. More works should be done to validate these conclusions. 3.3. CO2 capture and separation performance from CO2 þH2 gas mixture A typical fuel gas consists of about 40 mol% CO2 and 60 mol% H2, and many CO2 capture and separation experiments from this fuel gas using hydration technology have been reported recently. Linga et al. [132–134] used pure water to capture and separate CO2 from 0.392CO2 þ0.608H2 gas mixture. The induction time was found to be

1293

less than 10 min at 0.6 °C and 7.5–8.5 MPa, and about 36.1–42.5 mol% CO2 was captured by hydration while the separation factor was 32.4– 98.7 [132]. The authors added propane (C3H8) into CO2 þ H2 gas mixture and the results showed a reduction of the hydrate formation pressure. Similar investigation of adding propane to CO2 þH2 mixture was also carried out by Kumar et al. [148], and it showed that the gas mixture of 0.381CO2 þ 0.594H2 þ0.025C3H8 had lower hydration pressure than that of 0.4 CO2 þ0.6 H2, i.e. 3.8 MPa comparing to 7.5 MPa. The addition of propane did not compromise the separation factor, and the only disadvantage was the reduction of hydration rate. To enhance the contact between liquid and gas during hydration process, Linga et al. [149] employed water-saturated silica sand and compared its hydration performance with that using pure water in a stirred tank. Under the same conditions, the use of silica sand enlarged the gas consumption from 0.0197 mol/mol (water) to 0.0859 mol/mol (water), and eventually transferred about 86.4% of water to hydrate (after 42.8 h) comparing to only 19.8% in stirred tank. However, opposite to other results, the experiments exhibited a longer induction time, i.e. 244.7 min comparing to 1.7 min in stirrer tank. Seo and Kang [150] and Kang et al. [120] used water-saturated silica gel to separate CO2 from 0.41CO2 þ 0.59H2 gas mixture, and identified the optimal silica gel pore size of 100 nm. Although the utilization of silica gel caused the increase of hydration pressure comparing to pure water, the separation factor of the hydration process was improved significantly. CO2 molar fraction in the hydrate phase was 0.965–0.987, while it was 0.832–0.845 without using silica gel. The separation factor could be promoted from around 14 to as high as 57.3–208.4. The hydrate composition was determined by NMR to be (0.14H2/1.86CO2)S (6CO2)L 46H2O. Babu et al. [151,152] compared water-saturated silica gel and silica sand on capturing CO2 from CO2 þH2 gas mixture. It was found that using silica sand was better than using silica gel, and the induction time was shorter and the hydration rate was higher. Moreover, the less water-saturated silica sand, e.g., 50% water-saturated, enlarged the gas consumption considerably based on water quantity. Again, the addition of propane has been proven to reduce the hydration pressure. Lee et al. [153] investigated the hydration of 0.399 CO2 þ0.601 H2 gas mixture in THF aqueous solution with the concentrations of 0.5 mol%, 1.0 mol% and 3.0 mol%. The induction time of hydration was found to decrease with increasing THF concentration and also the driving force, while 1.0 mol% concentration was identified as the most suitable concentration because it resulted in the peak values of hydration rate and final gas consumption. Park et al. [154] separated CO2 from 0.4CO2 þ0.6H2 gas mixture using THF aqueous solution and silica gel with 100 nm in pore size. The addition of THF, especially with a concentration of 5.6 mol%, remarkably increased the stability of the formed hydrate. By enlarging gas–water contact area, the porous silica gel improved the gas consumption, and the hydration rate was little inhibited. Song et al. [155] used porous structure material, including soda glass and silica gel, to assist THFþSDS aqueous solution to capture CO2 from 0.402 CO2 þ0.598 H2 gas mixture. Silica gel was found more suitable for hydrate-based CO2 separation than glass beads. With silica gel, 2.0–4.0 mol% THF and 500–1500 ppm SDS, the CO2 capture had a recovery fraction of 0.372–0.738 and a separation factor of 37.42–55.26. THF concentration of 3.0 mol% was considered as a good promoter, which reduced the hydrate formation pressure and increased the gas consumption. SDS concentrations did not impose much impact on the hydrate formation. Li et al. [156] compared the effects of different TBAB aqueous solutions with concentrations from 0.14 mol% to 1.0 mol% on CO2 separation from 0.392 CO2 þ 0.608 H2 gas mixture, and concluded that 0.29 mol% (4.95 wt%) was the most suitable concentration, as it achieved the maximum CO2 consumption. The results also revealed the strengthened capture performance with increasing driving force (pressure difference), however, if the driving force was too high, e.g., beyond 2.5 MPa, CO2 selectivity of hydrates tended to fade away and

1294


1.0 0.9

CO2 + N2

water [136]

water +100 nm silica gel [146] 1.0 mol% THF [134]

0.8

Recovery fraction

water [132] [133]

0.59CO2 0.17CO2

0.20CO2

1.5 mol% THF [134]

0.7

0.29 mol% TBAB [138]

0.6

4.95 wt% TBAB [139]

0.29 mol% TBAB + DTACl [138]

0.5

0.65CO2

0.4

0.65 mol% TBAB [141] 1.0 mol% TBPB [141] 1.0 mol% TBANO3 [141] 0.293 mol% TBAB [142]

0.3

0.293 mol% TBAF [142] 5.0 wt% TBAB [137]

0.2

water [135]

0.1

0.5-3.0 mol% THF [135]

0.0

4.95 wt% TBAB [139]

0.29 mol% TBAB + DTACl [138]

65 60

water [132] [133]

CO2 + N2

1.0 mol% THF [134]

50

Separation factor

45

water [136]

water +100 nm silica gel [146]

55

1.5 mol% THF [134]

0.17CO2

0.20CO2 0.59CO2 0.65CO2

40 35

0.29 mol% TBAB + DTACl [138] 4.95 wt% TBAB [139] 0.65 mol% TBAB [141] 1.0 mol% TBPB [141]

30

1.0 mol% TBANO3 [141]

25

0.293 mol% TBAB [142]

20 15 10 5

0.293 mol% TBAF [142] 5.0 wt% TBAB [137] water [135] 0.5-3.0 mol% THF [135] 0.29 mol% TBAB + DTACl [138] 4.95 wt% TBAB [139]

0

Fig. 23. CO2 capture and separation performance from CO2 þ N2 mixture using hydrate technology: (a) recovery fraction and (b) separation factor.

more gas H2 turned into hydrate phase with increasing driving force rather than gas CO2. Later on, Li et al. [157] added cyclopentane to 0.29 mol% TBAB aqueous solution, and the results showed that the hydrate generation was accelerated and the gas consumption increased. When the volume ratio of cyclopentane to TBAB aqueous solution was 20.0 vol% and the memory solution was used, the induction time would be less than 1.0 min, while the corresponding CO2 recovery fraction and separation factor were 0.41–0.58 and 12.1– 30.6, respectively. Gholinezhad et al. [158] used 5.0 wt% and 10.0 wt% TBAB aqueous solution to capture CO2 from 0.4 CO2 þ0.6 H2 gas mixture, and pointed out the use of TBAB reduced the hydrate formation pressure but did not compromise the recovery and separation factor comparing to that of using pure water. After the first stage capture, the concentration of CO2 remaining in the gas mixture was about 18.0 mol%, and a secondary stage capture was applied to the gas released from hydrate to achieve further CO2 separation. Kim et al. [124] analyzed the effects of different concentrations of TBAB aqueous solutions on the kinetics of CO2 capture from 0.4CO2 þ 0.6H2 gas mixture. The authors suggested that there was an optimized concentration of TBAB aqueous solution for CO2 separation. Although the induction time was found to drop rapidly with increasing TBAB concentration, the hydrate formation rate decreased with increasing TBAB concentration once it was above 1.0 mol% (17.2 wt%). The concentration of 1.0 mol% also led to the highest hydration rate as well as the biggest recovery fraction and separation factor within the studied concentration range of 0.5–3.0 mol%. Liu et al. [160] used a mixture of TBAB aqueous solution and diesel/cyclopentane (CP) emulsion to separate and capture CO2 from CO2 þH2 gas mixture. TBAB acted as a reliable promoter and at the same time as an anti-agglomerator for the formed hydrate slurry with an optimal TBAB concentration of 0.29 mol% while the optimal water concentration in emulsion of 35 vol%. Hydrogen concentration could be enriched from 53.2 mol% to 84.6 mol% in the remained gas phase or even higher value with higher feed gas pressure, resulting in a separation factor as high as 37–99.

Park et al. [119] tried both TBAB and TBAF aqueous solutions to capture CO2 from 0.4CO2 þ0.6H2 gas mixture. CO2 concentration in hydrate phase was 0.92–0.95 and that in the remaining gas mixture was 0.34–0.36, which indicated the high CO2 selectivity of the studied solutions and the separation factor was in the range of 22.32–35.29. The gas consumption was in the range of 0.0025– 0.01 mol/mol (water) and 0.0004–0.004 mol/mol (water) by using TBAB and TBAF aqueous solution, respectively. Using TBAB was better in terms of gas consumption while the usage of TBAF advantaged in terms of hydrate stability. Babu et al. [161] examined 0.3–3.0 mol% TBAB aqueous solution on capturing CO2 from 0.4 CO2 þ0.6 H2 gas mixture. The highest gas consumption as well as separation factor were acquired when using 0.3 mol% TBAB aqueous solution; however, 0.3 mol% concentration led to the longest induction time among the concentration range of 0.3– 3.0 mol%. Babu et al. [125] also tried TBANO3 aqueous solution with the concentration of 0.5–3.7 mol%. The obtained CO2 separation factor was in the range of 20.6–32.21 when the concentration of TBANO3 aqueous solution was 0.5-1.0 mol%, but it would be only around 2.25–4.39 when using higher concentration solution (1.5– 3.7 mol%). TBANO3 aqueous solution with a concentration of 1.0 mol% (14.6 wt%) was considered as the most preferable, because the use of which resulted in the shortest induction time, the highest gas consumption, and the highest CO2 concentration in hydrate phase. Surovtseva et al. [162] combined the technologies of cryogenic condensation and hydrate formation to implement better CO2 capture from a gas mixture of CO2, H2 and other possible gases in syngas. In the first step, 68.0–75.0 mol% CO2 was captured by the condensation at 55.0 °C and 5.7 MPa. The condensed gas mixture was then heated, and CO2 with a purity of about 96.0 mol% was released. In the second step, another 12.0–19.0 mol% CO2 (compared to the initial amount of CO2) was captured by hydrate

Table 7 CO2 capture and separation performance from CO2 þ H2 mixture. Refs.

Gas mixture

Water/promoter

Working condition

Results

Other conclusions




rCO2, g ¼ 0.203–0.239 rCO2, H ¼0.865–0.851 R ¼0.361–0.425 S ¼ 32.4–98.7

0.392 CO2 þ0.608 H2

Water

0.6

7.5, 8.5

3.7–9.7

Linga et al. [134]

0.381 CO2 þ0.594 H2 þ0.025 C3H8

Water

0.55

3.8 (ΔP ¼1.7)

8.7–13.3 (fresh) U ¼0.0093–0.0104; 3.3–4.7 (memory) Cwater ¼ 0.093–0.104; R ¼0.48

Kumar et al. [148]

0.381 CO2 þ0.594 H2 þ0.025 C3H8

Water

0.55

3.8, 4.8

0.80 CO2 þ0.188 H2 þ0.012 C3H8

Water

0.55

3.5

14.1–33.0 (fresh) 5.0–28.3 (memory) 11.0

0.41 CO2 þ 0.59 H2

Water

1

6.5–8.9

rCO2, g ¼ 0.26–0.285; rCO2, H ¼0.832–0.845; S ¼ 13.7–14.1

CO2 in hydrate phase was enriched by using silica gels.


1

6.0–9.2

rCO2, g ¼ 0.267–0.325; rCO2, H ¼0.965–0.987; S ¼ 57.3–208.4

(0.14H2/1.86 CO2)S.(6CO2)L.46H2O

Water þ silica sand

1

4.5

21–105

5.5

872–1888

6.0

0.3–1.33

The hydrate formation pressure was significantly reduced by adding 2.5 mol% propane. Performance of using silica sand was better than that of using silica gel. Gas consumption increased significantly as reducing the water saturation in silica sand from 100% to 50%.

4.5

1–15

5.5

1–6

6.0

4–5

U ¼0.0115–0.0116; Cwater ¼ 0.115–0.117; U ¼0.028–0.032; Cwater ¼ 0.282–0.324; U ¼0.0318–0.0721; Cwater ¼ 0.32–0.724; U ¼0.0051–0.0086; Cwater ¼ 0.051–0.086; U ¼0.0086–0.0135; Cwater ¼ 0.086–0.136; U ¼0.0114–0.0122; Cwater ¼ 0.114–0.123

7.5

511–1413

8.5

440–928

9.0

0.3–18

7.5 8.5

14-not occur 1.33–618

9.0

72–1041

4.59 (ΔP ¼0.89)

16–241 (fresh)

Seo and Kang [150]

Kang et al. [120]

Babu et al. [151]

0.381 CO2 þ0.594 H2 þ0.025 C3H8

Water þ silica gel

Babu et al. [152]

0.4 CO2 þ0.6 H2

Water þ silica sand

Water þ þ silica gel

Lee et al. [153]

0.399 CO2 þ0.601 H2

0.5 mol% THF

1

1

1

6.45

rCO2, g ¼ 0.231–0.241; R ¼0.47; S ¼27.8;

The crystallizer enhanced the contact of gases with water and thus the rate of hydrate crystallization increased. However, required mechanical power increased significantly. The addition of a small amount of propane reduced the operation pressure and was found not to compromise the separation efficiency.

rCO2, g ¼ 0.643; R ¼0.32; S¼ 91.2


Linga et al. [132,133]

U ¼0.0196–0.0231; Cwater ¼ 0.140–0.164; U ¼0.0362–0.0424; Cwater ¼ 0.257–0.301; U ¼0.0389–0.0504; Cwater ¼ 0.273–0.358; U ¼0.0187; Cwater ¼ 0.133; U ¼0.014–0.0166; Cwater ¼ 0.099–0.118; U ¼0.0169–0.0185; Cwater ¼ 0.120–0.130 rCO2,

H

¼ 0.77–0.78; 1295

1296

Table 7 (continued ) Refs.

Gas mixture

Water/promoter

1.0 mol% THF

3.0 mol% THF

Song et al. [155]

0.4 CO2 þ0.6 H2

0.402 CO2 þ0.598 H2

Results




11–116 (memory)

U¼ 0.0008–0.0038a;

10–25 (fresh)

rCO2,

6.45

6.45

5.57 (ΔP¼ 1.87) 3.14 (ΔP¼ 0.89) 4.12 (ΔP¼ 1.87) 1.55 (ΔP¼ 0.89) 2.53 (ΔP¼ 1.87)

Water

ΔT ¼4.0

8.0

1.0 mol% THF

ΔT ¼4.0

8.0

5.6 mol% THF

ΔT ¼4.0

8.0

Water þ100 nm silica gel

ΔT ¼4.0

8.0

5–7 Waterþ soda glass beads (0.177– 0.25 mm) þ 2–4 mol% THFþ 500– 1500 mg/L SDS 5–7 Waterþ soda glass beads (0.105– 0.125 mm) þ2–4 mol% THF þ500– 1500 mg/L SDS Waterþ silica gel þ2–4 mol% 5–6 THFþ 500–1500 mg/L SDS

Other conclusions

H

¼ 0.74–0.88;

The induction time generally decreased with increasing THF concentration. 1.0 mol% THF was the optimum concentration due to its highest gas consumption.

3.3–6.6 (memory) U¼ 0.0028–0.0087a 8.6–23 (fresh)

rCO2,

H

¼ 0.75–0.86;

2.3–5.8 (memory) U¼ 0.0016–0.006a

rCO2, g ¼0.22; U¼ 0.02 ; rCO2, g ¼0.34; U¼ 0.0025; rCO2, g ¼0.23; U¼ 0.02; rCO2, g ¼0.24; U¼ 0.025

4–6

4–6

4–5

rCO2,

H ¼ 0.95

rCO2,

H ¼ 0.94

rCO2,

H ¼ 0.90

rCO2,

H ¼ 0.95

The addition of THF showed significantly stabilized hydrate dissociation conditions especially at 5.6 mol%. The usage of 100 nm silica gel increased the gas consumption by enhancing water-gas contact with little inhibition effect.

rCO2, H ¼ 0.305–0.353; R¼ 0.257–0.502; S ¼3.48– 11.03; rCO2, H ¼ 0.257–0.347; R¼ 0.252–0.606; S ¼4.1– 6.64; rCO2, H ¼ 0.156–0.299; R¼ 0.372–0.738; S¼ 37.42–55.26

Silica gel was more suitable for hydrate based CO2 separation than that of glass beads. 3 mol% THF was the most suitable concentration for CO2 separation which reduced the hydrate formation pressure and increased the gas consumption. SDS concentrations did not have much impact on the hydrate formation. Increase of drive pressure enhanced the gas consumption but reduced the gas separation efficiency.

Li et al. [156]

0.392 CO2 þ0.608 H2

0.14–1.0 mol% TBAB

2–9.3

ΔP¼ 1–4.5

3.0–43

rCO2, g ¼0.184–0.236

0.29 mol% was determined as the most suitable TBAB concentration. When the driving force is more than 2.50 MPa, H2 preferred going to the hydrate phase with the increase of the driving force, as compared to CO2. Temperature had little effect on the hydrate formation process.

Li et al. [157]

0.386 CO2 þ0.614 H2

0.29 mol% TBAB with 3–20 vol% cyclopentane

0.5–4.5

2.5–4.5

0.15–0.75 (fresh)

rCO2, g ¼0.12–0.22; rCO2, H ¼ 0.89–0.94; U¼ 0.024 (0.29 mol% TBAB with 5 vol% cyclopentane)b; U¼ 0.013 (0.29 mol% TBAB)b; U¼ 0.0021 (5 vol% cyclopentane)b; R¼ 0.41–0.58; S¼ 12.1–30.6

The addition of the cyclopentane into the TBAB solution remarkably enhanced the CO2 separation and speeded up the hydrate nucleation rate.

rCO2, g ¼0.18; rCO2, H ¼ 0.86; R¼ 0.41; S ¼15.7; rCO2, g ¼0.18; rCO2, H ¼ 0.86; R¼ 0.47; S ¼28.0; rCO2, g ¼0.616; rCO2, H ¼ 0.96; R¼ 0.35; S¼ 15.0

The addition of TBAB to water resulted in not compromised recovery fraction and separation factor and more favorable thermodynamic conditions.

0–0.4 (memory)

Gholinezhad et al. [158]

0.402 CO2 þ0.598 H2

0.805 CO2 þ0.195 H2

5 wt% TBAB

0.35

3.8

10 wt% TBAB

0.75

3.9

5 wt% TBAB

3.55

3.31


Park et al. [154]

Working condition

Kim et al. [124]

0.4 CO2 þ0.6 H2

0.5 mol% TBAB

11.0

5413

1.0 mol% TBAB

13.0

1532

3.0 mol% TBAB

14.7

10.2

0.10 CO2 þ 0.90 H2

0.29 mol% TBAB

3

4.0

0.18 CO2 þ0.82 H2

0.29 mol% TBAB

3

4.0

0.392 CO2 þ0.588 H2

`0.29 mol% TBAB

3

4.0

Xu et al. [122]

0.10 CO2 þ 0.90 H2 0.18 CO2 þ0.82 H2 0.40 CO2 þ0.60 H2

0.29 mol% TBAB 0.29 mol% TBAB 0.29 mol% TBAB

1 1 1

4.52 (ΔP¼ 3) 3.25 (ΔP¼ 3) 3.08 (ΔP¼ 3)

Liu et al. [160]

0.468 CO2 þ 0.532 H2

0.1–1.0 mol% TBAB (35 vol%)/diesel–CP emulsion

1

4.3

Xu et al. [159]

Park et al. [119]

Babu et al. [161]

Babu et al. [125]

rCO2, g ¼0.067; rCO2, H ¼ 0.425; U¼ 0.014c; R ¼0.45; S¼ 10.3; rCO2, g ¼0.101; rCO2, H ¼0.685, U¼ 0.011c; R ¼0.62; S¼ 19.4; rCO2, g ¼0.166; rCO2, H ¼0.935; U¼ 0.013c; R ¼0.66; S¼ 72.3 36.4 21.0 10.2

4.3–7.5

0.29 mol% TBAB (35 vol%)/dieselCP emulsion

3-1

4.3

0.4CO2 þ 0.6H2

Water

ΔT ¼4

8

0.6 mol % TBAB

ΔT ¼4

8

3.7 mol % TBAB

ΔT ¼4

8

0.8 mol % TBAF

ΔT ¼4

8

3.3 mol % TBAF

ΔT ¼4

8

0.3 mol% TBAB

6.0

6.0

2.0–76.3

1.0 mol% TBAB

6.0

6.0

0.3–0.7

1.5 mol% TBAB

6.0

6.0

0.3

2.0 mol% TBAB

6.0

6.0

0.3–0.7

3.0 mol% TBAB

6.0

6.0

0.3

0.5–1.0 mol% TBANO3

1.0

6.0

0.33–13

1.5–3.7 mol% TBANO3

1.0

6.0

0.33–1.67

0.4 CO2 þ0.6 H2

rCO2, g ¼0.036, U ¼0.007a; rCO2, g ¼0.072, U¼ 0.011a; rCO2, g ¼0.161, U ¼0.014a rCO2, g ¼0.155–0.213; rCO2, H ¼ 0.904–0.944; R¼ 0.73–0.80; S¼ 35–91; rCO2, g ¼0.144–0.227; rCO2, H ¼ 0.941–0.948; R¼ 0.68–0.88; S ¼54–99; rCO2, g ¼0.022–0.067; rCO2, H ¼ 0.667–0.771; R¼ 0.62–0.77; S¼ 47–87

TBAB was used to improve the separation capacity and also to be a good anti-agglomeration agent for the hydrate slurry.

rCO2, g ¼0.22; rCO2, H ¼ 0.95 S¼ 67.36; U ¼0.02 rCO2, g ¼0.35; rCO2, H ¼ 0.95 S¼ 35.29; U¼ 0.0025 ; rCO2, g ¼0.34; rCO2, H ¼ 0.92; S¼ 22.32; U ¼0.01; rCO2, g ¼0.37; rCO2, H ¼0.95; S¼ 32.35; U¼ 0.0004; rCO2, g ¼0.36; rCO2, H ¼ 0.95; S¼ 33.78; U¼ 0.004

TBAF was better in terms of thermodynamic stability, whereas TBAB was better in terms of gas consumption.

rCO2, H ¼ 0.952; U¼ 0.0079–0.0108; S¼ 31.8–49.5; rCO2, H ¼ 0.885; U¼ 0.0062–0.0073; S¼ 11.0–19.9; rCO2, H ¼ 0.635; U¼ 0.0009–0.0015; S¼ 2.66–2.96; rCO2, H ¼ 0.66; U¼ 0.0017–0.0022 S¼ 2.55–3.35; rCO2, H ¼ 0.59 U¼ 0.0030–0.0032 S¼ 2.14–2.34

The addition of 0.3 mol% TBAB resulted in highest gas consumption and highest separation factor, however, the induction time was the longest and sometime no nucleation.

U¼ 0.0130–0.0137; rCO2, H ¼ 0.904–0.938; S¼ 20.6–32.21; U¼ 0.0029–0.0061;

1.0 mol% was the perfect concentration for TBANO3 aqueous solution, using which the induction time was short, the gas consumption was highest and quickest, CO2 concentration in hydrate phase was also highest.

1297

0.156 CO2 þ 0.844 H2

0.4 CO2 þ0.6 H2

The induction time decreased rapidly with increasing TBAB solution concentration. The hydrate formation rate decreased with increasing the amount of TBAB above 1.0 mol%, making 1.0 mol% the most suitable TBAB concentration.


0.29 mol% TBAB (20–35 vol%)/die- 1 sel-CP emulsion

rCO2, H ¼ 0.849; R¼ 0.115; S ¼16.11; rCO2, H ¼ 0.891; R¼ 0.241; S¼ 25.99; rCO2, H ¼ 0.880; R¼ 0.101; S¼ 20.23

1298


rCO2, g ¼0.071

The combined cycle of cryogenic condensation and hydrate produced gas with hydrogen content better than 90 mol%.

c

b

U is calculated based on mole number of water in 135 mL THF aqueous solution, density is roughly estimated at 1000 kg/m3. U is calculated based on mole number of water in 180 mL liquid, density is roughly estimated at 1000 kg/m3. U is calculated based on mole number of water in 180 mL TBAB aqueous solution, density is roughly estimated at 1000 kg/m3.

3.4. CO2 capture and separation performance from CO2 þCH4 gas mixture

a

rCO2, g ¼0.084; 5–6 1 Water

0.148 CO2 þ 0.791 H2 þ others 0.155 CO2 þ 0.764 H2 þ others

rCO2, H ¼ 0.591–0.737; S¼ 2.25–4.39

Surovtseva et al. [162]

Induction time (min) Temperature (°C) Pressure (MPa)


Other conclusions Results Working condition Water/promoter Gas mixture Refs.

Table 7 (continued )

formed at 1.0 °C. The hydrate was then heated and CO2 with a purity about 90 mol% was released. Table 7 summarizes the reported CO2 capture and separation performance from CO2 þH2 gas mixture. Fig. 24 depicts the recovery fraction data and separation factor values using hydrate technology for CO2 capture from CO2 þ H2 gas mixture. It was found that the separation factor was higher than that of capture from CO2 þ N2 gas mixture, and this was not only because of the higher CO2 concentration in the feed gas mixture but also the larger phase equilibrium difference between the CO2 and H2 hydration. With the aid of promoters, for a typical pre-combustion fuel gas (0.4CO2 þ0.6H2), CO2 recovery fraction was scattered in the range of 0.3–0.8 while the separation factor was generally in the range of 5.0–60.0 but could be as high as about 200.0 reported by one of the experiments. The porous water-saturated supporting materials, like silica gel and silica sand, were used to enhance the gas–water contact, although the formation pressure may be higher than that of using pure water. The usage of porous structure improved the gas consumption while little inhibited the hydration rate. The application of promoter, especially THF and TBAB, was generally believed to have an optimal concentration at which CO2 capture and separation performance were the best.

Table 8 summarizes the reported CO2 capture performance from CO2 þCH4 gas mixture. Denderen et al. [163] concluded that the selectivity of CO2 from CO2 þCH4 gas mixture was not high and the selectivity decreased with increasing gas mixture pressure (4.0–8.0 MPa). The authors attempted to promote the hydration process by adding 1.0 mol% THF, unfortunately, it ended up prolonging the hydration and reducing the gas selectivity from 10.8 by using pure water to only 0.8–3.0. Furthermore, salinity of water was also believed to be an inhibitor for the hydration process, higher salinity caused longer hydration time and less gas consumption. Excess water was suggested for hydration so that the formed solid–liquid slurry could be easily transported in the industrial process. 100.0 ppm cetyl trimethylammonium bromide (CTAB) was found capable of shortening the hydration time. Tang et al. [135] pointed out that the similar molecule sizes of CO2 and CH4 led to the nearly equal chance for them to occupy hydrate cages, therefore resulting in low separation factor. Using pure water, 65.0 mol% CO2 was captured from 0.80CO2 þ0.20CH4 gas mixture, and the corresponding separation factor was 10.8. The usage of 0.5– 3.0 mol% THF could enhance CO2 capture, but degraded the separation with a factor of only 0.8–3.0 because CH4 loading was also increased. Some conclusions could be drawn based on these two examples of CO2 capture and separation from CO2 þCH4 gas mixture. Different from CO2 þ N2 and CO2 þH2 gas mixtures, CO2 and CH4 have close molecular size and also close hydrate equilibrium condition, as shown in Fig. 20, which indicates the two gases could be hydrated with close probability, thus the hydrate has low selectivity for CO2.

4. Conclusions In this paper, the fundamental thermo-physical properties, molecular structures and the formation conditions of CO2 hydrate, hydrate of CO2 þN2/H2/CH4/promoters as well as the application of hydrate technology in CO2 capture and separation were reviewed. The formation of CO2 hydrate in pure water requires high pressure and low temperature, in this instance, the usage of promoters, like the most commonly used TBAB and THF, can significantly reduce the formation pressure and therefore enhance the capture. For CO2 capture and separation from gas mixtures, the usage of promoters


1299

1.1 1.0

water + C3H8 [134] water + C3H8 [148]

0.9

Recovery fraction

water [132] [133]

CO2 + H2 about 0.4 CO 2

water + glass beads

0.8

+THF + SDS [155] water + silica gel

0.7

+THF + SDS [155]

0.8 CO 2

0.6

0.29 mol% TBAB + cyclopentane [157]

0.5

5 wt%, 10 wt% TBAB [158]

0.4

0.5 mol%, 1.0 mol%,

0.3

3.0 mol% TBAB [124]

0.2

0.1-1.0 mol% TBAB

0.29 mol% TBAB [159] + diesel-CP emulsion [160]

0.1

water + C3H8 [148] )

0.0

5 wt% TBAB [158]

220 CO2 + H2

about 0.4 CO2

200

Separation factor

180

water [132] [133]

water + C3H8 [148]

water [150] [120]

water + silica gel [150] [120]

water + glass beads +THF + SDS [155] water + silica gel +THF + SDS [155]

160

0.29 mol% TBAB + cyclopentane [157]

140

5-10 wt% TBAB [158] 0.5 -3.0 mol% TBAB [124]

120

0.8 CO2

100

0.29 mol% TBAB [159] 0.1-1.0 mol% TBAB + diesel-CP emulsion [160]

80

water [119]

60

0.6-3.7 mol% TBAB [119]

0.8-3.3 mol% TBAF [119]

40

0.3 mol% TBAB [161]

20

0.5-1.0 mol% TBANO3 [125]

1.0 mol% TBAB [161]

1.5-3.7 mol% TBANO3 [125]

0

water + C3H8 [148]

5 wt% TBAB [158]

Fig. 24. CO2 capture and separation performance from CO2 þ H2 mixture using hydrate technology: (a) recovery fraction and (b) separation factor.

Table 8 CO2 capture and separation performance from CO2 þ CH4 mixture. Refs.

Tang et al. [135]

Denderen et al. [163]

Gas mixture

Water/ promoter

Water 0.80 CO2 þ 0.20 CH4 0.5–3.0 mol% THF

0.5 CO2 þ 0.5 Water CH4 0.25 CO2 þ 0.75 CH4 0.18 CO2 þ 0.82 CH4

Working condition

Results


Induction time min

1.54

3.5

1.54

3.5

3

4

led to higher recovery fraction and shorter induction time; however, it did not improve the separation factor/selectivity of CO2 comparing to that using pure water. Some surfactants have been tried and believed to be able to enhance the capture and separation performance. The usage of porous structures, like silica gel and silica sand, were tested aiming at enhancing the gas/liquid contact and then promoting the capture and separation; however more tests should be conducted to gain more insights. CO2 capture and separation using hydration technology is still at its early stage of lab-investigation, and the results have diversities though many researches have been reported. The long-term main objective of this technology is the high efficiency, high speed and industrial level CO2 capture and separation. To achieve that, more investigations on accelerating the hydration, enlarging the

Other conclusions Separation performance rCO2, g ¼ 0.66; R¼ 0.65; S ¼ 10.8; rCO2, g ¼ 0.70– 0.73; R¼ 0.58–0.78; S¼ 0.8–3.0

CO2 and CH4 molecule sizes were less different, their competitiveness to occupy hydrate cages was fair, therefore the separation factor was not high.

rCO2, g ¼ 0.39; rCO2, g ¼ 0.16; rCO2, g ¼ 0.11

gas consumption, improving the separation factor should be carried out, so that the large scale system design, economic and environmental impact analysis can be further conducted.

Acknowledgments This research is jointly supported by the National Natural Science Foundation of China under the Contract no. 51176109 and the NSFC-JSPS Cooperative Project under the Contract no. 51311140169. This work was partially supported by open funding of Key Laboratory of Efficient Utilization of Low and Medium Grade Energy, Ministry of Education of China under Contract no. 2014-4201.

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Review of fundamental properties of CO2 hydrates

Review of fundamental properties of CO2 hydrates

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