Membrane Considerations and Plant Design for Pre-Combustion CO2 Capture

Membrane Considerations and Plant Design for Pre-Combustion CO2 Capture

C H A P T E R 15 Membrane Considerations and Plant Design for Pre-Combustion CO2 Capture Giuseppe Bagnato, Aimaro Sanna Heriot-Watt University, Edinb...

986KB Sizes 0 Downloads 27 Views

C H A P T E R 15

Membrane Considerations and Plant Design for Pre-Combustion CO2 Capture Giuseppe Bagnato, Aimaro Sanna Heriot-Watt University, Edinburgh, United Kingdom

1. Introduction Large amount of greenhouse gases (GHG), and in particular CO2, are released worldwide. As reported in Fig. 15.1, according to the US Energy Information Administration (EIA) (2017), the CO2 emission from postcombustion was 30.9 billion metric tonnes in 2014, of which about one-third was emitted in China. Overall, CO2 emissions are linked to the transport sector (30%e25%) and the energy and heating production (35%e40%). The origin of CO2 in China and India differs from that of the other major countries because a large fraction of CO2 (w30%) comes from the manufacturing sector. Being the main gas responsible for climatic change, several methods are under development for reducing CO2 content in the atmosphere, i.e., by producing synthetic fuels (Daza and Kuhn, 2016; Gao et al., 2017; Wei et al., 2017), for polymers production (van Heek et al., 2017), or just by storing it underground (Herna´ndez-Rodrı´guez et al., 2017; Tsupari et al., 2017; Wang et al., 2017). Despite the fact that CO2 separation is already used in common processes such as natural gas pretreatment and ammonia production or for enhanced oil recovery purposes, CO2 separation from power plants and industrial plants is still under development (Koohestanian et al., 2018; Song et al., 2017). Overall, CO2 capture technologies can be divided into three main categories (see Fig. 15.2): •



Postcombustion (Cormos and Cormos, 2017; Denev et al., 2017; Dubois et al., 2017), where the fuel is combusted in presence of air at atmospheric pressure and the CO2 content in the flue gas is about 3e15 mol%, balance to N2 and other gas impurities; Precombustion (Dinca et al., 2017; Jansen et al., 2015). The target of this process is to have a gas fuel without inert or pollutants such us CO2 or H2S, i.e., hydrogen production

Current Trends and Future Developments on (Bio-) Membranes. https://doi.org/10.1016/B978-0-12-813645-4.00015-5 Copyright © 2018 Elsevier Inc. All rights reserved.

415

416 Chapter 15 Figure 15.1 CO2 emission from fuel combustion in 2014. Data published by EIA, 2017. Total Carbon Dioxide Emissions from the Consumption of Energy 2014. Available from: https://www.eia.gov/beta/international/data/browser/#/? pa¼00000000000000000000000002&c¼ruvvvvvfvtvnvv1urvvvvfvvvvvvfvvvou20evvvvvvvvvnvvuvo&ct¼0&vs¼INTL.44-8-AFG-MMTCD. A&vo¼0&v¼H&end¼2014.

Membrane Considerations and Plant Design 417

Figure 15.2 CO2 capture system.



by steam reforming reaction, where the output stream (syngas) contains mostly CO and H2; subsequently the CO is converted into CO2 by wateregas shift (WGS) reaction for maximizing the production of hydrogen. In this case, the CO2 content is in the range of 15e60 mol% at high pressure (Ditaranto et al., 2014); Oxy-fuel combustion (Bueno et al., 2017; Chen, 2018; Liu and Zhang, 2018), where O2 preliminarily separated from N2 is used for the combustion reaction. The product outlet stream will contain mostly CO2 and steam, which are separable by a common flash unit.

Although all the above three configurations are valid and currently under development, this chapter will focus the attention on the state of the art of the precombustion systems and then reports the latest advances on the applications of membrane reactors for CO2 separation.

418 Chapter 15

2. Precombustion CO2 Capture CO2 precombustion capture is typically designed for plants dedicated to the production of H2 derived from syngas that can be obtained from: •

steam reforming, adding steam at the primary fuel or  y Cx Hy þ x H2 O 5 xCO þ x þ H2 DHe > 0 2



using oxygen in partial oxidation of hydrocarbons (called gasification when solid fuels are used): Cx Hy þ

x y O2 0 xCO þ H2 DHe < 0 2 2

To improve the H2 by further converting the CO in the syngas, WGS reaction is carried out: CO þ H2 O 5 CO2 þ H2 DHe < 0 The WGS output stream has a composition of about 60 wt% H2 and 15 wt% CO2 dried, at a pressure in the range of 20e70 bar (Gazzani et al., 2013; Manzolini et al., 2013). The H2 produced is possible to use to produce energy by gas turbine. This technology is applicable for both pulverized coal (PC), integrated gasification combined cycle (IGCC). Although the separation of CO2 applied to PC and IGCC has been technically proved, the energy requirements currently represent a limitation for its wide deployment. The high energy required for separating the CO2 can be observed in Table 15.1, which reports the efficiency for the pulverized coal (PC) and IGCC systems with and without carbon capture and storage (CCS). The table shows a decrement of efficiency of 8%e10% and 6%e7% for the PC and IGCC, respectively, because of the energy required for CCS. The highest energy penalty of about 40% is linked to the PC system with postcombustion technology (Folger, 2013). Davison et al. (2005) estimated a cost of electricity (COE) for IGCC system with CO2 capture between 1.1 and 1.5 c/kWh, increasing the COE of about 25%e30% than the IGCC without carbon capture. Another simulation calculated an increment of COE equal to 38% and 66%, respectively, for IGCC and PC plants, with the target to capture the 90% of CO2 as can be seen in Table 15.2 (Nexant, 2006). Cormos et al. compared the pre- and postcombustion CO2 capture applied at IGCC system using gaseliquid absorption processes (Cormos et al., 2011; Ustadi et al., 2017). The three systems proposed were (1) conventional IGCC without carbon capture; (2) IGCC with

Membrane Considerations and Plant Design 419 Table 15.1: Representative Values of Current Power Plant Efficiencies

Power Plant Type and Capture System Type Existing subcritical PC, postcombustion capture New supercritical PC, postcombustion capture New supercritical PC, oxy-combustion capture New IGCC (bituminous coal), precombustion capture New natural gas combined cycle, postcombustion capture

Net Plant Efficiency without CCS (%)

Net Plant Efficiency with CCS (%)

Energy Penalty: Added Fuel Input per Net kWh Output (%)

References

33

23

40

Katzer (2007)

40

31

30

Katzer (2007)

40

32

25

Katzer (2007)

40

34

19

Berkenpas et al. (2009)

50

43

16

Berkenpas et al. (2009)

CCS, carbon capture and storage; IGCC, integrated gasification combined cycle; PC, pulverized coal.

Table 15.2: Performance and Economic Impacts of CO2 Capture on IGCC and PC Plants IGCC Net plant output (pre-CO2 capture) (MW) Plant output derating (%) Heat rate increase (%) Total capital cost increase (%) Cost of electricity increase (%) CO2 capture cost (US$/t)

425 14 17 47 38 24

Supercritical PC 462 29 40 73 66 35

IGCC, integrated gasification combined cycle; PC, pulverized coal. From Nexant (2006).

CO2 precombustion capture by physical absorption (Selexol); (3) IGCC technology with CO2 postcombustion capture using chemical absorption (MDEA). The presence of the CO2 capture resulted in an efficiency decrement of about 6.33% for precombustion capture and 7.52% for postcombustion capture. For the IGCC system, the postcombustion system is more penalized than the precombustion capture one because of the low CO2 concentration (about 8e10 vol%) and the need to decrease the pressure stream to the atmospheric one.

420 Chapter 15 CO2 separaon

Absorbon

Chemical

Adsorbion

Physical

Adsorber bed

Cryogenics

Regeneraon method

Membranes

Gas separaon

MEA

Selexsol

Alumina

Pressure Swing

Organic membrane

Causc

Recsol

Zeolite

Temperature Swing

Not organic

Other

Other

Acitvated carbon

Washing

Microbial

Gas absorbon

membrane

Figure 15.3 CO2 separation methods. MEA, monoethanolamine.

Overall, CO2 capture has been studied with different separation technics: solvent absorption, adsorption by solid sorbents, cryogenic systems, and membrane (see Fig. 15.3). The solvent absorption can be realized by chemical or physical techniques. Chemical solvents such as monoethanolamine (MEA), diethanolamine (DEA) have been developed by the chemical and oil industries to remove hydrogen sulfide and CO2 from the exhaust gas streams (Dutcher et al., 2015). In postcombustion applications, the flue gas passes through a washing column where the solvents absorb CO2. The CO2-rich solvent is then heated, releasing high-purity CO2, then reused as CO2-free in the absorber. By using MEA, up to 98% CO2 removal with a purity of over 99% has been achieved. The energy required for regenerating the solvent is one of the main problems associated to chemical absorption, which results in a significant impact on the overall system efficiency. Typically, in physical absorption, the solvent is regenerated by reducing the pressure avoiding heat consumption, but the solvent depressurization is still energetically penalizing. The solvents used differentiate the process: Selexol (dimethylether polyethylene glycol), Rectisol (chilled methanol), Fluor (propylene carbonate), and Purisol (N-methyl-2-pyrollidone) (Chen et al., 2013a; Sun and Smith, 2013). Separating CO2 by adsorption on a solid material such as zeolite or activated carbon is another well-established technique. The gas mixture is passed through a filling bed made up of adsorbent particles until the product gas reaches a balance concentration due to the sorbent saturation. The solid adsorbent is then regenerated both by pressure reduction (pressure swing absorption [PSA]) and/or by increasing temperature (temperature swing absorption [TSA]). PSA technology is currently used in applications that use physical solvents (Lee and Park, 2015).

Membrane Considerations and Plant Design 421 Solid adsorption is currently not sufficiently attractive for a large-scale separation of CO2 from gas combustion, as the yield and selectivity of CO2 of available materials are low. Nonetheless, solid-state adsorption may have a function in combination with other separation technologies. Another proven technique, which uses low temperature to cool and condense CO2, can be an effective way of separating carbon dioxide. Cryogenic separation is widely used in trade where gas streams with concentrated CO2 are available (usually over 90%) but not for more diluted steams. The greatest disadvantage in cryogenic separation is the amount of energy required to provide refrigeration, which makes an inappropriate technique for treating low CO2 gas streams. Membrane technology has been widely employed for gas separation, where the driving force of the separation processes is the different pressure between the retentate and permeate zone. Furthermore, an important parameter of membrane-based processes is the H2 permeability and selectivity H2/CO2, parameters that depend of the interaction of the stream and the membrane material with the necessity for having a chemical and physical stability. There are several types of gas separation membrane, which include porous ceramic membrane, palladium membrane, polymer-based membranes, and zeolites membranes. Polymer membranes can be used for low-temperature applications such as CO2 removal from gas combustion streams. Ceramic and palladium membranes may be more useful in high-temperature and/or high-pressure applications, which can be very interesting for H2 separation. Also, innovative ceramic membrane that will allow the diffusion of high-temperature oxygen (as well as heat transfer) with the aim of achieving an oxy-fuel combustion process, is under investigation. The advantage and disadvantage of CO2 capture systems have been studied simulating them for CCPs for IGCC power plants, as reported in Table 15.3 (Lee et al., 2017).

3. Membrane-Based Capture Processes A membrane is a thin film selective at one compound than others; its nature is different; metallic, polymeric, or ceramic materials have been used for this purpose. The preferential membrane application for CO2 capture is in precombustion configuration, thanks to the possibility to obtain high-selectivity H2/CO2 and the high pressures and temperatures typical for IGCC and PC systems. The membrane unit can be added in different parts of the process, favoring the points of the plant where the pressure and temperature are relatively high, so that the separation factor is maximized. The selection of the membrane materials, such as ceramic, metallic, or polymeric, depends on the physical and chemical limitations in regard to the operating conditions and material tolerance to the various chemical species that might be present in synthesis gas. Fig. 15.4 shows the possible potential membrane application for CO2 capture in precombustion,

422 Chapter 15 Table 15.3: Literature Review of CCPs for Commercial-Scale IGCC Power Plants (Lee et al., 2017) Author

CCP

Major Results

Asif et al. (2015)

AMP

Padurean et al. (2012)

MDEA Selexol Rectisol Purisol

Cau et al. (2014)

Selexol Purisol MEA

Cormos (2012)

Selexol Rectisol MDEA

Field and Brasington (2011)

Selexol

• Simulation and technical analysis with 90% efficiency were performed for IGCC with precombustion (518 MW) and postcombustion (561 MW) using Aspen Plus. • The thermal efficiency and energy consumption were compared. The energy efficiency in the precombustion case was 8.3% higher than that in the postcombustion case. • Exergy analysis was also carried out to evaluate the exergy destruction of equipment and improvements were suggested. • Precombustion carbon capture technologies with four solvents were employed for the technical analysis. • Coal and biomass were employed as feedstock to the IGCC plant. • Selexol consumed the maximum electricity but the least amount of thermal energy, and utility consumption made it the most promising technology. • Case studies in terms of simulation and economic analysis for 70%, 80%, and 90% carbon capture efficiency for Selexol were investigated. The capital cost increased 19.55%, 20.91%, and 22.55% compared with the capital cost incurred for IGCC without carbon capture. • Two power generation technologies, i.e., ultrasuper critical (USC) steam plant and conventional IGCC with precombustion (400e500 MW) were compared via simulation using Aspen Plus and Gate-Cycle. • SOx and NOx emissions were reduced by USC steam plant. • Technical analysis including power generation and consumption was performed for 70% or 90% carbon capture. • Simulation was performed for IGCC with precombustion (400e450 MW) using Aspen Plus. • Technical analysis (efficiency 90%) and detailed evaluation for utilities (steam, cooling medium, and electricity) were conducted. • Economic analysis of IGCC with/without carbon capture was carried out. Operating cost was also evaluated based on technical analysis. • Simulation and technical analysis with 90% efficiency were performed for IGCC with precombustion (464 MW) using Aspen Plus. • Solubility of Selexol was calculated by PC-SAFT. • Improved configuration was compared with that from the DOE report; the suggested configuration showed higher efficiency.

Membrane Considerations and Plant Design 423 Table 15.3: Literature Review of CCPs for Commercial-Scale IGCC Power Plants (Lee et al., 2017)dcont’d Author

CCP

Major Results

Kanniche and Bouallou (2007)

Selexol MDEA Rectisol AMP MDEA/ MEA NMP

Kapetaki et al. (2015)

Selexol

Kunze et al. (2011)

Methanol

Moioli et al. (2014)

MDEA

Ordorica-Garcia et al. (2006)

Selexol

Siefert and Litster (2013)

Membrane

• IGCC with precombustion, CO2 compression, and TEG dehydration was considered. • Simulation and technical analysis based on 77%, 81%, 85%, and 88% of carbon capture efficiency were carried out using Aspen Plus. • Technical evaluation indicated that 85% is the maximum possible efficiency due to drastic energy efficiency loss. • The author regarded Rectisol as the most promising process because it required the least amount of energy consumption for regeneration as well as CO2 compression. • Integrated and nonintegrated Selexol schemes were suggested and compared. • Simulation and technical analysis were performed for IGCC with precombustion (464 MW) using UniSim. • 95% carbon capture was achieved through an integrated scheme at the expense of 65% increase in energy consumption compared with the 90% carbon capture alternative. • IGCC with methanol as solvent was employed for simulation and exergy analysis using Aspen Plus. • Exergy efficiency of IGCC with carbon capture was about 40%. • Main exergy destruction occurred at the combined cycle, gasifier, WGSR, and AGRU. • By improving HGCU, the exergy efficiency increased by 54.1%. • Dual-stage MDEA scheme was employed within IGCC (250 MW). • Simulation was performed for IGCC with/without precombustion using Aspen Plus. • Technical analysis including both power generation and consumption was carried out. • IGCC with 87% carbon capture efficiency showed 9.5% energy penalty in comparison with IGCC without carbon capture. • Simulation was performed for IGCC (577 MW) and NGCC (488 MW) with precombustion using Aspen Plus. • Technical analysis with/without carbon capture was performed, and the carbon capture efficiency was 60% and 80%, respectively. • In the case of 80% carbon capture, the CO2 removal cost for IGCC and NGCC was 28 USD/CO2-ton and 30 USD/CO2-ton, respectively. • IGCC and IGFC employed a membrane process for carbon capture. • Simulation and technical analysis (efficiency 90%) were performed. • Cost evaluation including capital and operating cost was performed. Based on that, IRR and LCOE were suggested. • Exergy analysis for IGCC and IGFC was done.

424 Chapter 15 Table 15.3: Literature Review of CCPs for Commercial-Scale IGCC Power Plants (Lee et al., 2017)dcont’d Author

CCP

Major Results

Skorek-Osikowska et al. (2012)

MEA Membrane

Urech et al. (2014)

MDEA Selexol K2CO3

• Simulation was performed for IGCC with precombustion (300 MW) in terms of MEA and membrane using Aspen Plus. • Technical analysis was carried out with the conclusion that the energy consumption of the membrane process is 1/15 times that of MEA. Main reason lies in the fact that WGSR and CO2 compressors are not needed for the membrane process. • Another advantage of the membrane process is that higher purity (98%) of CO2 can be achieved. • However, the capacity and life cycle of the membrane process should be considered for commercialization. • IGCC (440e540 MW) with/without precombustion carbon capture using various solvents such as MDEA, Selexol, and potassium carbonate (PC) was considered. • Technical efficiency of 45.02% was obtained from IGCC without carbon capture. Based on a 90% carbon capture, technical efficiencies of 36.39% for MDEA, 36.42% for Selexol, and 37.33% for PC were obtained. • High technical efficiency of the PC process resulted from the fact that cooling equipment was not required for regeneration and absorption. • Further optimization increased the technical efficiency from 37.33% to 39.31% for the PC process.

AMP, 2-amino-2-methyl-1-propanol; CCP, carbon capture plant; MDEA, methyldiethanolamine; MEA, monoethanolamine; NMP, n-methyl-2-pyrrolidone; PC, pulverized coal.

WGS interstage H2 recovery or WGS membrane reactors Fuel Air/O2

Gasification or partial oxidation

Syngas cooler

Particulate removal

Water gas shift

Post WGS H2 recovery Power & Heat system

Fuel gas

H2 recovery

H 2S removal

CO2 compressor

Syngas cooler

S T R E A M

T E M P E R A T U R E

CO2

Figure 15.4 Membrane integration for precombustion CO2 capture. WGS, wateregas shift.

Membrane Considerations and Plant Design 425 identifying four different configurations, each of which involves specific advantages and disadvantages. Remember that their integration will result in a lower efficiency than the IGCC and PC plant without CCP (Scherer and Franz, 2011). 1. For WGS interstage H2 recoverydThe WSG reactor is carried out in two-stage adiabatic reactor at high and low temperatures, with a cooling stage between them. The different temperature reactions are required to improve the conversion of CO, being the reaction reversible and exothermic. The first reactor is used to improve the kinetic, whereas the second reactor is used to improve the thermodynamics of the reaction (Fig. 15.5A). The presence of a membrane stage, between the two reactors (before or after the cooling system), removes the H2 from the output stream of the first reactor, and the retentate CO-rich feed, is sent to the second reactor. According to the Le Chatelier’s principle, by removing one or more products the reaction equilibrium will be shifted toward their productions. In this case, CO conversion will improve, or the same productivity will be maintained, so that the number of the reactors could be decreased as the catalyst is used. Also, a less drastic operating condition could be employed resulting in an improved efficiency of the process. However, in this configuration, sulfur presence represents an operating limitation for the membranes, thus H2S removal should be performed upstream the H2 separation.

Figure 15.5 Membrane configuration.

426 Chapter 15 If the WGS interstage H2 is composed of an elevate number of stages: 2. A WGS membrane reactor can be used. Membrane reactors have been studied in literature (Basile et al., 1996; Bracht et al., 1997; Ramasubramanian et al., 2013) to produce and separate H2 in the same unit, with highest H2 production and purity. The membrane reactor is composed of two zones: (a) a retentate zone, where the main stream reacts in the presence of the catalyst, with the produced hydrogen passing through the membrane to arrive at (b) the permeate zone, where a sweep gas improves the driving force of the separation mechanism (Fig. 15.5B). 3. Post WGS H2 recoverydThe stream is purified from H2S and CO2 absorbed downstream the WGS reactor. The absence of H2S, which is removed at this stage is an advantage of this configuration because the constant permeation flux of H2S through the membrane would damage it. The disadvantage of this configuration is represented by the low CO2 pressure at the end of the absorption processes (around 3e10 bar), so that a compressor stage is required to maximize the CO2 capture (Fig. 15.5C). 4. CO2 compressor interstage H2 recoverydThe advantage in this part of the process is the high pressure of the streams, which facilitates the membrane separation. The H2 passes through the membrane and is delivered to the gas turbine system, whereas the retentate feed, CO2-rich, continues to be compressed and separated from H2. Furthermore, a sweep gas can be used, with the target to decrease the H2 partial pressure in the permeate zone, maximizing H2 recovery (Fig. 15.5D).

4. Membrane Material After discussing the possible location for the membrane integration in the IGCC plant, a brief overview is reported here about the materials used to develop membrane for H2/CO2 separation (Adhikari and Fernando, 2006; Brunetti et al., 2010; Scholes et al., 2010; Shao et al., 2009).

4.1 Polymeric Membrane Polymeric membranes are used in gas separation because of their low capital cost and they are able for long-term operation under pressure. All these aspects make polymer membranes extremely attractive and economically more competitive than inorganic membranes. Their development for CO2 capture purposes has been recognized as a key scientific topic for the coming years (Basile et al., 2011). CO2 capture by polymeric membrane is obtained from thin dense layer, which have high selectivity for a specific molecule, through a diffusion mechanism. Usually, the thin layer does not have mechanical resistance, and for this reason a support layer, without mass transfer limitation, is added (Basile et al., 2011; Iulianelli et al., 2017).

Membrane Considerations and Plant Design 427 The polymeric membrane for CO2 capture is composed of a dense polymer layer, where the compounds (H2, CO2 or others) across it by a solution-diffusion mechanism, with a drastic decrement in terms of CO2/H2 selectivity operating at high temperature (Vakharia et al., 2015). Composite membranes, studied by Xing and Ho (2011), are membranes containing both amine carriers and fumed silica (FS) in cross-linked poly(vinyl alcohol) epoly(siloxane) (PVAePOS) (FS loading < 22 wt%) and cross-linked PVA (FS loading > 22 wt%). The membrane shown the best performance at 107 C and z4.75 bar, achiving an ideal selectivity CO2/H2 of 138. Supported liquid membranes have a porous support layer impregnated with a liquid transport media, showing attractive transport performances (Bai and Ho, 2011; Pennline et al., 2008). Butyl-3-methlyimidazolium tricyanomethanide ([Bmim][TCM]) was tested as a CO2 absorbent with a tubular glass membrane contactor investigating the stability and the performance at varying temperature, pressure, and gas flow rate. The highest CO2 flux was 2.50  104 mol/m2 s at 80 C 20 bar (Dai and Deng, 2016). Other tests were carried out with 1-ethyl-3-methylimidazolium acetate, [emim][Ac], used as absorbent, and polysulfone (Ps) support. The CO2 removal efficiency was obtained from experimental data, showing a temperature dependence. The efficiency improved from 30% to 45.0% when the temperature increased from 291 to 348K, when the Ps contactor was used (Gomez-Coma et al., 2016). Ilyas et al. (2017) proposed tailor ionic liquids with a very high separation efficiency for CO2/CH4 and CO2/N2. The presence of protic ionic liquid is due to a high CO2 absorption capacity such as (3-aminopropyl) trimethoxysilane and acetic acid. The combination of silyl ether functionalized cation and acetate ion shows CO2 permeance about 23 GPU with CO2/CH4 selectivity of 41. The synthesized SILM was stable up to 10 bar, observing a permeance from 23 to 31 GPU for a temperature from 25 to 65 C, while the selectivity slightly decreased from 41 to 35 over the same temperature range.

4.2 Ceramic Membranes Ceramic membranes are promising for CO2/H2 separation. This group includes silica, zeolites, alumina, nitrides, and oxides with a porous controlled structure, where the hydrogen can pass through the membrane, while the other species are concentrated in the retentate (Bux et al., 2009; Daramola et al., 2017; Wirawan et al., 2011). Advantages of ceramic membranes are linked to their chemical stability and their ability to operate at high temperature. Moreover, they are cheaper than other membranes, such as Pd-based membranes. The main disadvantage of ceramic membrane is the low H2/CO2 selectivity, which also decrease in the presence of steam (Huang et al., 2010). CO2/H2 separation was carried out by an ultrathin modified fouling index (MFI) zeolite membrane at a temperature range 235e310K at 9 bar. The authors observed the highest

428 Chapter 15 selectivity (z260) at 235K, estimating their cost to separate 300 t CO2 per day. With a cost of $26 500, the MFI zeolite membranes are cheaper than polymeric membranes (Korelskiy et al., 2015). A Co-doped multitube silica membrane has been used for CO2 capture from a WGS reactor (Smart et al., 2010). The module was tested up to 300 C for 55 days (1344 h), achieving an H2 purity of 98% for a stream of H2/CO2 of 40/60. Lowest hydrogen purity (about 92.5%) was detected for a mixture feed of 40% H2, 40% CO2, and 20% CO, whereas the hydrogen flux was 60% and 92.5% at 300 and 375 C, respectively (Duke et al., 2007). Cermet membranes are constituted of a combination of ceramic and metallic component for hydrogen separation (Abdollahi et al., 2010; Balachandran et al., 2006). Presence of metal phase (Pd, PdeAg, PdeCu, Nb, Zr, Ta, etc.) enhanced the hydrogen flux, and the presence of the ceramic phase (Al2O3 or ZrO2) improved the thermomechanical stability (Balachandran et al., 2014). Dense cermet membranes with z50e60 vol.% Pd with Y2O3-stabilized ZrO2 have been tested for hydrogen separation from product streams generated during coal gasification and/or steam methane reforming, at 400e900 C. The tests showed high hydrogen purity. The hydrogen flux measured was z26 cm3 [STP]/min-cm2 at 400 C and z52 cm3[STP]/min-cm2 at 900 C, for a membrane thickness z18-mm. Another test was conducted for studying the membrane stability in presence of H2S. The cermet membrane was stable at the temperature range of 450e650 C using a feed gas that contained 10%e73% H2 and 8e400 ppm H2S. Tantalum- and yttria-stabilized zirconia has been used to synthesize a dense cermet membrane for hydrogen separation from a gas mixture. Hydrogen permeation test of the membrane was carried out between 350 and 500 C. The highest hydrogen flux was 1.2 mL/min cm2 for a cermet membrane 0.5 mm cm thick at 300 C, using 100% H2 as the feed gas and Ar as the sweep gas (Park et al., 2011).

4.3 Metallic Membranes Most metallic membranes used for hydrogen separation are Pd membranes (Chiesa et al., 2006), which are able to operate under IGCC conditions. Furthermore, Pd-base membrane have been studied for WGS reaction (Babita et al., 2011; Basile et al., 2015; Jia et al., 2017; Piemonte et al., 2010). Metallic dense membranes, such as Ni, Ta, Va, Zr, Pd, Ag, separate the hydrogen by a solution-diffusion mechanism, defined by six steps (Bagnato et al., 2017): 1. 2. 3. 4.

H2 molecules adsorption from the membrane side at higher H2 partial pressure Dissociation of H2 molecules on the surface Reversible dissociative chemisorption of atomic H2 Reversible dissolution of atomic H2 in the metal lattice of the membrane

Membrane Considerations and Plant Design 429 5. Diffusion into the metal of atomic H2 proceeds from the side of the membrane at a higher H2 pressure to the side at lower pressure 6. Desorption of recombined atomic H2 into molecular form Pd base, due to the higher permeability of hydrogen, can be improved by adding other metals, such as Ag and Au. To decrease the noble metal amount, different porous supports, metallic or ceramic, were added, reducing the purity of the membranes. Moreover, other problems are caused by (1) embrittlement phenomena for temperature lower than 300 C, due to a changing phase of Pd in presence of hydrogen (Chen et al., 2013b; Cotterill, 1961); (2) pollutants contained in the gas, such as S and CO, which create solid bonds with the Pd matrix, with consecutive decrement of hydrogen permeation flux (Khatib et al., 2014). Thanks to the high mechanical stability at high temperature, metallic membrane reactors are able to carry out the reaction and separation of hydrogen in the same unit, with high grade of production and extreme purity. A pilot-scale WGS membrane reactor for hydrogen from coal was tested for 1000 h using flat composite membrane with a thin selectivity layer of Pd (z5 mm) supported on ceramic, without mass transfer limitation, at 400 C and 20 bar, recovering 80% of pure hydrogen (>99.99%) at permeance equal to 1.5 mmol/m2/s/Pa0.5 at 1 bar, while the CO2 was captured at 40 bar with high-purity grade, z95%, and 95% of recovery. The cost for the membrane reactor was assumed to be 2500 $/m2.

5. Techno Design Evaluation Chiesa et al. (2006) compared three different IGCC power plants: (1) a conventional IGCC plant where CO2 is vented to the air; (2) a low CO2 emission IGCC based on commercially available technologies with Selexol physical absorption process; (3) a plant based on the hydrogen separation membrane reactor (HSMR) technology. The best results were achieved from HSMR configuration than the Selexol process, capturing 90.4% of the carbon contained in the input coal. The cost of CO2 capture was calculated to be equal to 32.55 $/tCO2 for the Selexol process and 23.27 $/tCO2 for the HSMR system. Furthermore, the HSMR plant was more efficient for the absence of CO2 compressor system, required for Selexol process, and the capacity of the membrane reactor to improve the syngas conversion. The high efficiency of membrane integration was confirmed by De Lorenzo et al. (2008) when compared with that of Selexol process. A membrane unit for CO2 separation from a CO-shifted syngas stream using polyvinylamine membrane was simulated with on real power plant (ELCOGAS 315 MWe Puertollano plant). The modified process could achieve greater than 85% CO2 recovery at 95 vol% purity. The efficiency penalty for such a process would be approximately 10%

430 Chapter 15 points, including CO2 compression, producing electricity at a cost of 7.6 c/kWh and a CO2 avoidance cost of about 40 AUS$/tCO2 (Grainger and Ha¨gg, 2008). H2 cost was compared with membrane technology and conventional physical solvents for IGCC plant (Plunkett et al., 2009). The presence of the membrane improved the plant efficiency because of the reduction of CO2 compression, which resulted in a decrement of the COE of around 10%e15%, than conventional physical absorption. Other study (Gray et al., 2010) calculated an efficiency of 36.2% for the hydrogen membrane plant, 2.9% points higher than Selexol process, attributed to reducing CO2 compression. The membrane technology reduced the levelized COE, from 0.1000 $/kWh (Selox) to 0.0880 $/kWh. Furthermore, Ku et al. (2011) calculated the efficiency penalty in the separation system to be 6.7 points for conventional liquid separation and only 5 points using membrane units, recovering 90% of hydrogen produced. The membrane system was disadvantageous in terms of system efficiency, resulting in 7% less, for a hydrogen recovery of 70%. Analyzing the membrane manufacturing, the metallic membranes, in particular Pd base, are not yet commercial because of the high cost of the metal, from 2090 to 1672$ per membrane with thickness of 50 and 40 mm, respectively (Dolan et al., 2010). Polymeric membranes with a CO2/H2 selectivity of 15.5 and a H2/CO2 selectivity of 5.91 were used for simulating CO2 capture in a IGCC process, showing an efficiency loss of more than 10% (Franz and Scherer, 2010). The results suggested that to have a CO2 recovery equal to 85% and efficiency losses below 10%, the selectivity CO2/H2 and H2/CO2 should be 10 times more compared with that of the membrane used. The ceramic membranes have been investigated for CO2 capture, setting the selectivity to 400, the maximum purity was 95% and separating the 97% of CO2 with efficiency process loss between 9.07% and 9.43% points (Franz and Scherer, 2011). With the same grade of purity and separation, the efficiency loss decreased to 6.7% using a ceramic membrane reactor (Ku et al., 2011).

6. Conclusion and Future Trends This chapter has reviewed and summarized the major research and development activities aimed to integrate membrane technology for precombustion CO2 capture with different configuration. Advanced plant designs employing new plant integration concepts and advanced technologies such as solid oxide fuel cells also are being actively investigated. The most promising concepts, however, are likely to be decades away from commercial reality.

Membrane Considerations and Plant Design 431

List of Acronyms AMP CCP CCS COE DEA EIA FS GHG HSMR IGCC MDEA MEA MFI PC POS PSA PVA SILM STP TSA WGS

2-Amino-2-methyl-1-propanol Carbon capture plant Carbon capture and storage Cost of electricity Diethanolamine United States Energy Information Administration Fumed silica Greenhouse gases Hydrogen separation membrane reactor Integrated gasification combined cycle Methyldiethanolamine Monoethanolamine Modified fouling index Pulverized coal Poly siloxane Pressure swing absorption Poly vinyl alcohol Supported ionic liquid membrane Standard temperature and pressure Temperature swing absorption Wateregas shift

References Abdollahi, M., Yu, J., Hwang, H.T., Liu, P.K.T., Ciora, R., Sahimi, M., et al., 2010. Process intensification in hydrogen production from biomass-derived syngas. Industrial and Engineering Chemistry Research 49 (21), 10986e10993. Adhikari, S., Fernando, S., 2006. Hydrogen membrane separation techniques. Industrial and Engineering Chemistry Research 45 (3), 875e881. Asif, M., Bak, C.-U., Saleem, M.W., Kim, W.-S., 2015. Performance evaluation of integrated gasification combined cycle (IGCC) utilizing a blended solution of ammonia and 2-amino-2-methyl-1-propanol (AMP) for CO2 capture. Fuel 160, 513e524. Babita, K., Sridhar, S., Raghavan, K.V., 2011. Membrane reactors for fuel cell quality hydrogen through WGSR e review of their status, challenges and opportunities. International Journal of Hydrogen Energy 36 (11), 6671e6688. Bagnato, G., Iulianelli, A., Sanna, A., Basile, A., 2017. Glycerol production and transformation: a critical review with particular emphasis on glycerol reforming reaction for producing hydrogen in conventional and membrane reactors. Membranes 7 (2), 17. Bai, H., Ho, W.S.W., 2011. Carbon dioxide-selective membranes for high-pressure synthesis gas purification. Industrial and Engineering Chemistry Research 50 (21), 12152e12161. Balachandran, U., Lee, T.H., Chen, L., Song, S.J., Picciolo, J.J., Dorris, S.E., 2006. Hydrogen separation by dense cermet membranes. Fuel 85 (2), 150e155. Balachandran, U., Lee, T.H., Park, C.Y., Emerson, J.E., Picciolo, J.J., Dorris, S.E., 2014. Dense cermet membranes for hydrogen separation. Separation and Purification Technology 121 (Suppl. C), 54e59. Basile, A., Criscuoli, A., Santella, F., Drioli, E., 1996. Membrane reactor for water gas shift reaction. Gas Separation and Purification 10 (4), 243e254.

432 Chapter 15 Basile, A., Gugliuzza, A., Iulianelli, A., Morrone, P., 2011. 5-Membrane technology for carbon dioxide (CO2) capture in power plants. In: Advanced Membrane Science and Technology for Sustainable Energy and Environmental Applications. Woodhead Publishing, pp. 113e159. Basile, A., Curcio, S., Bagnato, G., Liguori, S., Jokar, S.M., Iulianelli, A., 2015. Water gas shift reaction in membrane reactors: theoretical investigation by artificial neural networks model and experimental validation. International Journal of Hydrogen Energy 40 (17), 5897e5906. Berkenpas, M.B., Kietzke, K., Mantripragada, H., McCoy, S., Rubin, E.S., Versteeg, P.L., et al., 2009. IECM Technical Documentation Updates Final Report. Carnegie Mellon University, Pittsburgh, PA. Bracht, M., Alderliesten, P.T., Kloster, R., Pruschek, R., Haupt, G., Xue, E., et al., 1997. Water gas shift membrane reactor for CO2 control in IGCC systems: techno-economic feasibility study. Energy Conversion and Management 38, S159eS164. Brunetti, A., Scura, F., Barbieri, G., Drioli, E., 2010. Membrane technologies for CO2 separation. Journal of Membrane Science 359 (1), 115e125. Bueno, V., Alhajaj, A., Zahra, M.A., 2017. The evaluation of oxy-fuel combustion deployment at the Mirfa plant in UAE. Energy Procedia 114 (Suppl. C), 530e538. Bux, H., Liang, F., Li, Y., Cravillon, J., Wiebcke, M., Caro, J., 2009. Zeolitic imidazolate framework membrane with molecular sieving properties by microwave-assisted solvothermal synthesis. Journal of the American Chemical Society 131 (44), 16000e16001. Cau, G., Tola, V., Deiana, P., 2014. Comparative performance assessment of USC and IGCC power plants integrated with CO2 capture systems. Fuel 116, 820e833. Chen, S., 2018. Chapter 2-fundamentals of oxy-fuel combustion A2-Zheng, Chuguang. In: Liu, Z. (Ed.), OxyFuel Combustion. Academic Press, pp. 13e30. Chen, W.-H., Chen, S.-M., Hung, C.-I., 2013a. Carbon dioxide capture by single droplet using Selexol, Rectisol and water as absorbents: a theoretical approach. Applied Energy 111, 731e741. Chen, Y.J., Huang, K.Y., Chen, H.T., Kao, C.R., 2013b. Au and Pd embrittlement in space-confined soldering reactions for 3D IC applications. In: Paper Presented at the 2013 IEEE International Symposium on Advanced Packaging Materials. February 27, 2013eMarch 1, 2013. Cormos, C.-C., 2012. Integrated assessment of IGCC power generation technology with carbon capture and storage (CCS). Energy 42 (1), 434e445. Cormos, A.-M., Cormos, C.-C., 2017. Techno-economic evaluations of post-combustion CO2 capture from suband super-critical circulated fluidised bed combustion (CFBC) power plants. Applied Thermal Engineering 127 (Suppl. C), 106e115. Cormos, C.-C., Padurean, A., Agachi, P.S., 2011. Technical evaluations of carbon capture options for power generation from coal and biomass based on integrated gasification combined cycle scheme. Energy Procedia 4, 1861e1868. Cotterill, P., 1961. The hydrogen embrittlement of metals. Progress in Materials Science 9 (4), 205e301. Dai, Z., Deng, L., 2016. Membrane absorption using ionic liquid for pre-combustion CO2 capture at elevated pressure and temperature. International Journal of Greenhouse Gas Control 54 (Part 1), 59e69. Daramola, M.O., Oloye, O., Yaya, A., 2017. Nanocomposite sodalite/ceramic membrane for pre-combustion CO2 capture: synthesis and morphological characterization. International Journal of Coal Science and Technology 4 (1), 60e66. Davison, J., Bressan, L., Domenichini, R., 2005. CO2 capture in coal-based IGCC power plants. In: Greenhouse Gas Control Technologies, vol. 7. Elsevier Science Ltd, Oxford, pp. 167e175. Daza, Y.A., Kuhn, J.N., 2016. CO2 conversion by reverse water gas shift catalysis: comparison of catalysts, mechanisms and their consequences for CO2 conversion to liquid fuels. RSC Advances 6 (55), 49675e49691. https://doi.org/10.1039/C6RA05414E. Denev, J.A., Dinkov, I., Bockhorn, H., 2017. Burner design for an industrial furnace for thermal postcombustion. Energy Procedia 120 (Suppl. C), 484e491. Dinca, C., Slavu, N., Badea, A., 2017. Benchmarking of the pre/post-combustion chemical absorption for the CO2 capture. Journal of the Energy Institute 91.

Membrane Considerations and Plant Design 433 Ditaranto, M., Li, H., Hu, Y., 2014. Evaluation of a pre-combustion capture cycle based on hydrogen fired gas turbine with exhaust gas recirculation (EGR). Energy Procedia 63 (Suppl. C), 1972e1975. Dolan, M.D., Donelson, R., Dave, N.C., 2010. Performance and economics of a Pd-based planar WGS membrane reactor for coal gasification. International Journal of Hydrogen Energy 35 (20), 10994e11003. Dubois, L., Laribi, S., Mouhoubi, S., De Weireld, G., Thomas, D., 2017. Study of the post-combustion CO2 capture applied to conventional and partial oxy-fuel cement plants. Energy Procedia 114 (Suppl. C), 6181e6196. Duke, M.C., Gopalakrishnan, S., Abdel-Jawad, M., et al., 2007. Hydrogen purification from coal gasification using inorganic membranes in Australia. In: Paper Presented at the American Chemical Society’s 234th National Meeting. Dutcher, B., Fan, M., Russell, A.G., 2015. Amine-based CO2 capture technology development from the beginning of 2013da review. ACS Applied Materials and Interfaces 7 (4), 2137e2148. EIA., 2017. Total Carbon Dioxide Emissions from the Consumption of Energy 2014. Availale from: https://www.eia. gov/beta/international/data/browser/#/?pa¼00000000000000000000000002&c¼ruvvvvvfvtvnvv1urvvvvfvv vvvvfvvvou20evvvvvvvvvnvvuvo&ct¼0&vs¼INTL.44-8-AFG-MMTCD.A&vo¼0&v¼H&end¼2014. Field, R.P., Brasington, R., 2011. Baseline flowsheet model for IGCC with carbon capture. Industrial and Engineering Chemistry Research 50 (19), 11306e11312. Folger, P., 2013. Carbon Capture: A Technology Assessment. Franz, J., Scherer, V., 2010. An evaluation of CO2 and H2 selective polymeric membranes for CO2 separation in IGCC processes. Journal of Membrane Science 359 (1), 173e183. Franz, J., Scherer, V., 2011. Impact of ceramic membranes for CO2 separation on IGCC power plant performance. Energy Procedia 4, 645e652. Gao, P., Li, S., Bu, X., Dang, S., Liu, Z., Wang, H., et al., 2017. Direct conversion of CO2 into liquid fuels with high selectivity over a bifunctional catalyst. Nature Chemistry 9. Gazzani, M., Macchi, E., Manzolini, G., 2013. CO2 capture in natural gas combined cycle with SEWGS. Part A: thermodynamic performances. International Journal of Greenhouse Gas Control 12 (Suppl. C), 493e501. Gomez-Coma, L., Garea, A., Irabien, A., 2016. Carbon dioxide capture by [emim][Ac] ionic liquid in a polysulfone hollow fiber membrane contactor. International Journal of Greenhouse Gas Control 52 (Suppl. C), 401e409. Grainger, D., Ha¨gg, M.-B., 2008. Techno-economic evaluation of a PVAm CO2-selective membrane in an IGCC power plant with CO2 capture. Fuel 87 (1), 14e24. Gray, D., Plunkett, J., Salerno, S., Tomlinson, G., White, C., 2010. Current and Future Technologies for Gasification-based Power Generation. Herna´ndez-Rodrı´guez, A., Montegrossi, G., Huet, B., Vaselli, O., Virgili, G., 2017. A study of wellbore cement alteration controlled by CO2 leakage in a natural analogue for geological CO2 storage. Applied Geochemistry 86 (Suppl. C), 13e25. Huang, A., Dou, W., Caro, J., 2010. Steam-stable zeolitic imidazolate framework ZIF-90 membrane with hydrogen selectivity through covalent functionalization. Journal of the American Chemical Society 132 (44), 15562e15564. Ilyas, A., Muhammad, N., Gilani, M.A., Ayub, K., Vankelecom, I.F.J., Khan, A.L., 2017. Supported protic ionic liquid membrane based on 3-(trimethoxysilyl)propan-1-aminium acetate for the highly selective separation of CO2. Journal of Membrane Science 543 (Suppl. C), 301e309. Iulianelli, A., Algieri, C., Donato, L., Garofalo, A., Galiano, F., Bagnato, G., et al., 2017. New PEEK-WC and PLA membranes for H2 separation. International Journal of Hydrogen Energy 42 (34), 22138e22148. Jansen, D., Gazzani, M., Manzolini, G., Dijk, E.V., Carbo, M., 2015. Pre-combustion CO2 capture. International Journal of Greenhouse Gas Control 40 (Suppl. C), 167e187. Jia, H., Wu, P., Zeng, G., Salas-Colera, E., Serrano, A., Castro, G.R., et al., 2017. High-temperature stability of Pd alloy membranes containing Cu and Au. Journal of Membrane Science 544, 151e160.

434 Chapter 15 Kanniche, M., Bouallou, C., 2007. CO2 capture study in advanced integrated gasification combined cycle. Applied Thermal Engineering 27 (16), 2693e2702. Kapetaki, Z., Brandani, P., Brandani, S., Ahn, H., 2015. Process simulation of a dual-stage Selexol process for 95% carbon capture efficiency at an integrated gasification combined cycle power plant. International Journal of Greenhouse Gas Control 39, 17e26. Katzer, J., 2007. The Future of Coal. Massachusetts Institute of Technology, Cambridge MA, ISBN 978-0-61514092-6. Khatib, S.J., Yun, S., Oyama, S.T., 2014. Sulfur resistant Pd and Pd alloy membranes by phosphidation. Journal of Membrane Science 455, 283e293. Koohestanian, E., Sadeghi, J., Mohebbi-Kalhori, D., Shahraki, F., Samimi, A., 2018. A novel process for CO2 capture from the flue gases to produce urea and ammonia. Energy 144, 279e285. Korelskiy, D., Ye, P., Fouladvand, S., Karimi, S., Sjoberg, E., Hedlund, J., 2015. Efficient ceramic zeolite membranes for CO2/H2 separation. Journal of Materials Chemistry A 3 (23), 12500e12506. https:// doi.org/10.1039/C5TA02152A. Ku, A.Y., Kulkarni, P., Shisler, R., Wei, W., 2011. Membrane performance requirements for carbon dioxide capture using hydrogen-selective membranes in integrated gasification combined cycle (IGCC) power plants. Journal of Membrane Science 367 (1), 233e239. Kunze, C., Riedl, K., Spliethoff, H., 2011. Structured exergy analysis of an integrated gasification combined cycle (IGCC) plant with carbon capture. Energy 36 (3), 1480e1487. Lee, S.-Y., Park, S.-J., 2015. A review on solid adsorbents for carbon dioxide capture. Journal of Industrial and Engineering Chemistry 23, 1e11. Lee, W.-S., Lee, J.-C., Oh, H.-T., Baek, S.-W., Oh, M., Lee, C.-H., 2017. Performance, economic and exergy analyses of carbon capture processes for a 300 MW class integrated gasification combined cycle power plant. Energy 134, 731e742. Liu, Z., Zhang, T., 2018. Chapter 10-pilot and industrial demonstration of oxy-fuel combustion. In: Oxy-fuel Combustion. Academic Press, pp. 209e222. Manzolini, G., Macchi, E., Gazzani, M., 2013. CO2 capture in natural gas combined cycle with SEWGS. Part B: economic assessment. International Journal of Greenhouse Gas Control 12 (Suppl. C), 502e509. Moioli, S., Giuffrida, A., Gamba, S., Romano, M.C., Pellegrini, L., Lozza, G., 2014. Pre-combustion CO2 capture by MDEA process in IGCC based on air-blown gasification. Energy Procedia 63, 2045e2053. Nexant, I., 2006. Environmental Footprints and Costs of Coal-based Integrated Gasification Combined Cycle and Pulverized Coal Technologies (No. EPA-430-R-06e006 EPA Contract No. 68-W-03-33; TRN: 001100233). Ordorica-Garcia, G., Douglas, P., Croiset, E., Zheng, L., 2006. Technoeconomic evaluation of IGCC power plants for CO2 avoidance. Energy Conversion and Management 47 (15), 2250e2259. Padurean, A., Cormos, C.-C., Agachi, P.-S., 2012. Pre-combustion carbon dioxide capture by gaseliquid absorption for integrated gasification combined cycle power plants. International Journal of Greenhouse Gas Control 7, 1e11. Park, J.H., Jeon, S.I., Sim, W.J., Baek, I.H., Choi, S.H., 2011. Stability of Ta/YSZ cermet membrane for hydrogen separation. Energy Procedia 4 (Suppl. C), 756e762. Pennline, H.W., Luebke, D.R., Jones, K.L., Myers, C.R., Morsi, B.I., Heintz, Y.J., et al., 2008. Progress in carbon dioxide capture and separation research for gasification-based power generation point sources. Fuel Processing Technology 89 (9), 897e907. Piemonte, V., De Falco, M., Favetta, B., Basile, A., 2010. Counter-current membrane reactor for WGS process: membrane design. International Journal of Hydrogen Energy 35 (22), 12609e12617. Plunkett, J., Gerdes, K., Gray, D., White, C., 2009. Performance and cost comparisons of alternate IGCC based CO2 capture technologies. In: Paper Presented at the 2009 Gasification Technologies Conference, Colorado. Ramasubramanian, K., Song, M., Ho, W.S.W., 2013. Spiral-wound water-gas-shift membrane reactor for hydrogen purification. Industrial and Engineering Chemistry Research 52 (26), 8829e8842.

Membrane Considerations and Plant Design 435 Scherer, V., Franz, J., 2011. CO2 separation via pre-combustion utilizing membranes in coal power plants. In: Stolten, D., Scherer, V. (Eds.), Process Engineering for CCS Power Plants. WV Verlag, Weinheim, Germany, pp. 431e471. Scholes, C.A., Smith, K.H., Kentish, S.E., Stevens, G.W., 2010. CO2 capture from pre-combustion processesdstrategies for membrane gas separation. International Journal of Greenhouse Gas Control 4 (5), 739e755. Shao, L., Low, B.T., Chung, T.-S., Greenberg, A.R., 2009. Polymeric membranes for the hydrogen economy: contemporary approaches and prospects for the future. Journal of Membrane Science 327 (1), 18e31. Siefert, N.S., Litster, S., 2013. Exergy and economic analyses of advanced IGCCeCCS and IGFCeCCS power plants. Applied Energy 107, 315e328. Skorek-Osikowska, A., Janusz-Szymanska, K., Kotowicz, J., 2012. Modeling and analysis of selected carbon dioxide capture methods in IGCC systems. Energy 45 (1), 92e100. Smart, S., Lin, C.X.C., Ding, L., Thambimuthu, K., Diniz da Costa, J.C., 2010. Ceramic membranes for gas processing in coal gasification. Energy and Environmental Science 3 (3), 268e278. https://doi.org/ 10.1039/B924327E. Song, C., Liu, Q., Ji, N., Deng, S., Zhao, J., Kitamura, Y., 2017. Natural gas purification by heat pump assisted MEA absorption process. Applied Energy 204 (Suppl. C), 353e361. Sun, L., Smith, R., 2013. Rectisol wash process simulation and analysis. Journal of Cleaner Production 39, 321e328. Tsupari, E., Arponen, T., Hankalin, V., Ka¨rki, J., Kouri, S., 2017. Feasibility comparison of bioenergy and CO2 capture and storage in a large combined heat, power and cooling system. Energy 139 (Suppl. C), 1040e1051. Urech, J., Tock, L., Harkin, T., Hoadley, A., Mare´chal, F., 2014. An assessment of different solvent-based capture technologies within an IGCCeCCS power plant. Energy 64, 268e276. Ustadi, I., Mezher, T., Abu-Zahra, M.R.M., 2017. The effect of the carbon capture and storage (CCS) technology deployment on the natural gas market in the United Arab Emirates. Energy Procedia 114, 6366e6376. Vakharia, V., Ramasubramanian, K., Ho, W.W.S., 2015. An experimental and modeling study of CO2-selective membranes for IGCC syngas purification. Journal of Membrane Science 488, 56e66. van Heek, J., Arning, K., Ziefle, M., 2017. Differences between laypersons and experts in perceptions and acceptance of CO2-utilization for plastics production. Energy Procedia 114, 7212e7223. Wang, L., Yao, B., Xie, H., Winterfeld, P.H., Kneafsey, T.J., Yin, X., et al., 2017. CO2 injection-induced fracturing in naturally fractured shale rocks. Energy 139 (Suppl. C), 1094e1110. Wei, J., Ge, Q., Yao, R., Wen, Z., Fang, C., Guo, L., et al., 2017. Directly converting CO2 into a gasoline fuel. (Article). 8, 15174. Wirawan, S.K., Creaser, D., Lindmark, J., Hedlund, J., Bendiyasa, I.M., Sediawan, W.B., 2011. H2/CO2 permeation through a silicalite-1 composite membrane. Journal of Membrane Science 375 (1), 313e322. Xing, R., Ho, W.S.W., 2011. Crosslinked polyvinylalcoholepolysiloxane/fumed silica mixed matrix membranes containing amines for CO2/H2 separation. Journal of Membrane Science 367 (1), 91e102.

Further Reading Franz, J., Maas, P., Scherer, V., 2014. Economic evaluation of pre-combustion CO2-capture in IGCC power plants by porous ceramic membranes. Applied Energy 130, 532e542.