OPTIONS FOR DELIVERING CO2 IN P2G SYSTEMS PRODUCING SYNTHETIC FUELS Cyril Jose E. Bajamundi a, , Pasi Vainikkab, Janne Kärki a a.
VTT Technical Research Centre of Finland Ltd., Koivurannantie 1 PL 1603, 40 101 Jyväskylä, Finland b. VTT Technical Research Centre of Finland Ltd., Skinnarilankatu 34, 53850 Lappeenranta, Finland
Corresponding author:
[email protected]
Power-to-gas (P2G) technologies producing synthetic fuels have the potential to address the issue of intermittency of electricity from solar and wind farms, and simultaneously contribute to lower CO2 concentration in the atmosphere. However it requires, among others, judicious technical selection of appropriate CO2 capture and delivery technologies. For example, compared to CCS, where the purity of the product CO2 gas is mostly dictated by transportation and subsequent storage requirements, in P2G system producing SNG the catalyst to be used in the Sabatier conversion of CO2 to CH4 is sensitive to trace contents of S and metal impurities. This is also true for Fischer–Tropsch based synthesis of other hydrocarbons. More than 100 technical articles were reviewed to understand CO2 capture technologies including capture from air that have received attention within the last decade. The goal is to determine the applicability of these technologies to P2G systems producing synthetic fuels. The review includes technologies such as absorption, adsorption, and low temperature CO 2 capture. In addition, top sources of renewable CO2, such as biomass combustion, are also presented. An easy-to-understand visual summary on the energy requirements, recovery, CO2 product purity, hydrophobicity issues and technology development status is presented. More importantly, the quality of the product CO2 from the said technologies is assessed. From these properties an appropriate CO2 capture and delivery technology is proposed for the production of synthetic fuel.
Keywords: CO2 capture; power-to-gas; P2G; Power-to-liquids; P2L; Direct air capture; DAC; Amine absorption; NH3 absorption
1
Introduction Between the years 2002 and 2012 the total primary production of renewable energy, RE, in EU
28 has grown by 81%. The renewable energy mix includes hydro power, wind power, solar thermal, solar photovoltaic, solid biofuels, biogas, geothermal, bio-liquid fuels and others. Specifically, the growth of combined wind and solar photovoltaic power production has reached 646%. RE production is expected to rise in order to meet the 20% share of energy from renewable sources in 2020 [1]. In 2013, the worldwide wind power and solar PV capacity have reached 318 GW and 139 GW, respectively. Solar PV capacity in 2013 is 53 times that of the capacity at start of 2004[2]. In EU 28, it is projected that by 2020 the share of electricity from RE sources is to reach 33% - 35%, stressing the need for new infrastructures and improved electricity grids that can manage and balance electricity flows in region [3].
(a) (b) Figure 1. (a) Total primary production of renewable energy in EU 28 from 2002 to 2012. Top 10 renewable energy producing states are indicated. (b) Combined primary production of wind and solar PV in EU 28. Top 5 states with the highest wind and solar PV primary production capacity are indicated. Data from [4].
Intermittency and surges in wind and solar PV energy production are major hurdles in the advancement of the said RE source to the grid infrastructure. Currently, grid stability heavily relies in hydro pumped storage[5]. For example in the UK, between 2011 to March 2013, 224 GWh of potential energy had to be turned down from wind farms alone [5] to prevent overloading of electric grids. Power-to-gas (P2G) technology has the potential to address the issue of intermittency, contribute to lower the net CO2 emissions and provide fuels and chemicals for transportation and industry. In P2G,
excess electricity during peak production is used to split water to O2 and H2. With the aid of an appropriate catalyst, H2 is used to chemically reduce CO2 and produce a hydrocarbon fuel (CxHyOz).
Figure 2. Generic Power-to-Gas technology.
Sabatier reaction or methanation, (1), is a possible chemical CO2 reduction route that can be employed. The reaction is highly exothermic and favorable at temperature range of 150 - 300°C [6,7]. However the eight electron process makes the process reaction limited thus catalysts are required. Nickel is one of the most effective and cheapest surface catalyst suitable for this reaction [8]. CO 2 + 4H 2
CH 4 + 2H 2O
H rxn =(1) -156 kJ/mol
For catalyst longevity, the concentration of sulfur, e.g. H2S, and other trace metals should be kept as minimum as possible, in ppb levels. Therefore any mass input stream, such as the CO2 stream, entering the methanation reactor should be as pure as possible or only contain compounds listed in (1). This requirement is stricter compared to carbon capture and storage (CCS), where the purity of the product CO2 gas is mostly dependent on the transportation and subsequent storage requirements.
2
Methodology More than 100 articles1 were reviewed to understand the features of several CO2 capture
technologies (from flue gases and atmosphere) that have received significant attention within the last decade as part of CCS studies. The objective is to understand the features of these capture technologies; and assess their applicability to P2G systems in terms of the quality of CO2 it can produce, energy
1
Not all have been cited in this article due to the article size limitation.
requirement, and technological readiness levels. Different sources of CO2 (fossil and biogenic) are also presented.
3
CO2 emissions in EU 28 and available biogenic CO2
The total CO2 emissions in EU 28 have been decreasing from 2005 to 2012 relative to 1990 levels in compliance with the Kyoto Protocol of the United Nation Framework Convention on Climate Change [9]. On average energy sector accounts for c.a. 93% of the emissions, followed by industrial processes which accounts for c.a. 6% of the emissions, see Figure 3.
Figure 3. Total CO2 emissions in EU 28 and top sources and sinks. Land Use, Land Use Change and Forestation (LULUCF) is not accounted in calculation of the total CO2 emission. Data from European Environment Agency, EEA [10].
Figure 4. Total CO2 emissions (fossil+biogenic) and CO2 emissions from biomass with energy recovery in EU 28 countries from 2005 (enforcement of Kyoto Protocol) to 2012. Data from European Environment Agency, EEA [10].
Figure 4 shows the total emissions of EU 28 for the period of 2005 to 2012. Germany, Great Britain and Italy have the highest total CO2 emission (without deducting LULUCF). Of the total CO2 emissions in EU 28, around 10 % came from energy recovery from biomass. For majority of EU 28 countries, the ratio of CO2 from biomass/total CO2 emissions falls below the EU average. However countries such as Latvia (68%), Finland (57%) and Sweden (48%) have high CO2 from biomass/total CO2 emissions ratio. These states have high potential for adopting P2G systems that utilizes biogenic CO2. In Finland, for example, from 2005 to April 2012 the energy sourced from wood fuels is 676 TWh; of which around 535 TWh (79%) was supplied by heat and power plants while 141 TWh (21%)
was from small scale systems, see Figure 5. Using this ratio, an estimated average of 27 Mt bioCO2/year is available, if captured and can converted to this is equivalent to 128 TWh of CH4 .
Figure 5. Energy Consumption in Finland from 2005 to April 2012 with the source of energy identified. HHP: Heat and power plants, SH: Small scale systems. Data from [11]. Worldwide it is estimated that in 2030, technologies such as integrated gasification and combined cycle with co-gasification of biomass (IGCC-CSS) with 30% biomass, and biomass integrated combined cycle (BIGCC-CSS) with 100% biomass has a potential2 of capturing 1.4 Gt CO2(eq) /year and 1.9 Gt CO2(eq) /year respectively. If synthesized to CH4 this is equivalent to 6.7 PWh and 9 PWh capacity, respectively. Biodiesel based gasification and Fischer-Tropsch synthesis with 100% biomass share also capturing potential of 1.8 Gt CO2(eq) /year at the same period [12].
4 4.1
CO2 Capture Technologies Amine Absorption The absorption processes is a neutralization reaction between a weak acid (CO2) and a weak base
solvent. The solvent dissolves CO2 but not O2, N2 and other components of the flue gas being scrubbed. The CO2 rich solvent is then sent to the regeneration column where CO2 is stripped from the solution and the solvent is recycled for a new batch of gas [13–18]. Monoethanolamine, MEA, is the most commonly used solvent. MEA has high CO2 capacity, high absorption kinetic, a low CO2 partial pressure, high solubility in H2O, low viscosity and is cheap [14]. The reboiler for solvent regeneration is the most energy requiring component of the absorption process [16,19]. For MEA based absorption 2
Based on economics – potential at comparative cost to other alternatives.
process about 3.24 – 4.2 GJ/ton CO2 is required and could result to an estimated power plant efficiency loss of 10% - 12% [17,18]. The steam required in the reboiler could account for half of the operating costs of the plant, thus it is important that the operating and design parameters, e.g. solvent/gas ratio, absorber height, CO2 inlet concentration, are optimized. Up to 10% of the steam requirement reduction can be achieved after optimization [16]. Several remedies are available to reduce the energy requirement of amine based absorption process. Through high thermal integration and optimization for large-scale systems, the specific energy requirement in the reboiler can be reduced significantly to 1.0 – 1.7 GJ/ton CO2 (44.0 – 74.8 kJ/mol CO2)[20]. If each mole of CO2 is converted to methane via (1), barring any heat losses, there is enough heat available for solvent regeneration. Solvent choice also could lower the reboiler duty. For example, the estimated specific reboiler duty for use of piperazine-promoted potassium carbonate [21] and CESAR-1 3 [18] as solvent is only 2.44 GJ/ton CO2 and 2.71 GJ/ton CO2 respectively. Amine absorption also suffers from solvent degradation, formation heat stable salts (HSS) and corrosion. MEA degradation could account for 10% of the total cost of CO2 capture [22]. Thermal degradation, which mainly occurs in the stripper, forms unreactive degradation products, e.g. HEAI, which can accumulate in the solvent solution [14]. Oxidative degradation, which takes place mainly in the absorber may yield products similar to thermal degradation and HSS (sulfate, formate and nitrate) [23]. Elevated HSS concentration accelerates the corrosion by increasing the concentration of dissolved oxygen and H3O+ [24]. 4.2
Ammonia based CO2 capture The use of NH3 as a solvent has been extensively adopted in the gas industry for sweetening of
sour gases. CO2 capture by NH3 follows an acid-base neutralization reaction, where NH3 acts a nucleophile4. NH3 has higher CO2 capture capacity (1.0 mol CO2 / mol NH3) compared to MEA (0.5 mol CO2 /mol MEA) [25] and lower regeneration energy requirement (lower than 2.0 GJ/ton CO2 [26]). In addition, NH3 is chemically stable, less corrosive, and relatively cheaper than MEA by about 1/6 th factor. The power plant efficiency loss by adopting this technology is estimated to be around 8.4% 11.2% [27–29].
3 4
An advanced amine solvent which is an aqueous solution of 2-Amino-2-Methyl-Propanol (AMP) and piperazine (PZ). A Lewis base.
Figure 6. Schematic flow-sheet of the ammoniabased CO2 capture process. Figure is from Li et al., 2014 [30], permission being sought for.
The biggest drawback for this process is NH3 vaporization or slip, which is closely related to chemical loss and absorbent make-up cost. Li et al. estimates that the energy penalty for recovering the fugitive NH3 might be equivalent or more than the energy penalty for the CO2 capture alone [30]. Several technologies are available to address ammonia slip. For example, in CSIRO process a cold absorber is installed to capture fugitive NH3 in the lean flue gas leaving the absorber, see Figure 6. The cold absorber solution containing the captured NH3 is regenerated using the incoming flue gas. This cools the incoming flue gas before the CO2 absorber and regenerated the NH3 solvent simultaneously. The recycling efficiency reached 99.87% and the NH3 exhaust concentration was only 15.4 ppmv. Chilled Ammonia Process by ALSTOM [27] which addresses the same goal is also available. Chemical additives are also available to arrest NH3 vaporization, for example, addition of 1 - 5% AMP increases the absorption of NH3 and suppresses vaporization [31]. 4.3
Adsorption Adsorption is a purely physical capture process in which CO2 is adsorbed from a gas stream on
the surface of solids such as zeolites, carbon cages and metal organic frameworks, MOFs. CO2 can be weakly bounded to the adsorbent (physisorption) or covalently bounded to the adsorbents surface for increased capacity. The desorption of CO2 can be achieved by thermal swing (heating), vacuum swing (near vacuum pressure reduction), pressure swing (decrease in pressure) or electrical swing (voltage is applied to trigger CO2 release) [32]. Because no solvent is required to be heated and vaporized, as in the case of MEA, the energy requirement for desorption is only within the range of 2 – 3.2 GJ/ ton CO2 (88 – 140 kJ/mol CO2). Further energy and cost reduction is accomplished by optimizing the adsorption
process cycle, for example in a 4-step vacuum swing adsorption cycle proposed by Haghpanah et al. the estimated energy penalty is 0.472 GJ/ ton CO2 [33,34]. The use of MOFs as adsorbent has also been gaining ground. MOFs can be tuned or functionalized to achieve high CO2 uptakes with minimal heat absorption range (20 - 50 kJ/mol) compared to MEA (~80 kJ/mol)[35]. However, the synthesis of stable MOFs, especially those being water stable, is still one of biggest challenges for their practical applications. 4.4
Membranes Membranes are low cost means of separating gases when high purity gas streams are not vital
[36]. The maximum separation achieved by any membrane is related to the feed-to-permeate ratio ( p0 pl ): p0 pl
nCO2 ,l nCO2 ,0
(2)
where p = pressure, nCO2 = mole % CO2, o = inlet, l = permeate. The pressure ratio of 5 – 15 is practical for most separation process. The pressure ratio can be increased by either feed compression or vacuum permeate. Vacuum operation is more favoured because of its lower energy consumption5 [37]. The actual performance of the membrane is determined by two factors, permeability (volume of gas flowing through the membrane per area and time) and selectivity (desired component/other components). An optimum membrane for CO2 capture should have (a) large permeance to reduce the surface area required and consequently the cost (b) moderate selectivity [38]. Because of this trade off, a single stage membrane is not enough to produce very high purity CO2 permeate [39]. To achieve the required purity, multistage membrane system is proposed [38,40], however this translates to high capital cost. To achieve 90 mol-% CO2 permeate from the flue gas of a 600MW coal-fired power plant, Zhao et al. estimated an energy consumption of 0.94 GJ/ton CO2 (41.5 kJ/mol) is required for a 3 stage membrane system [40]. Because no chemical or sorbent is used, the energy consumption is only required to supply driving force to the separation processes.
5
Lower volume of gas being processed.
However, very few techno-economic studies and almost no pilot scale tests are reported on the use of membrane technology for CO2 capture from real flue gases. Further improvement in membrane performance is crucial to the adoption of a purely membrane-based CO2 capture process. 4.5
Low temperature CO2 capture (LT) This capture technology relies on the physical changes of CO2 (condensation or desublimation)
during cooling of the flue gas to - 79°C (CO2 solidifies at 1atm) and below. For small scale systems it has been experimentally demonstrated by Sustainable Energy Solutions that the energy penalty is around 0.75 – 0.95 GJ/ton CO2 [41]. For larger scale systems, it has been modelled that the energy penalty is c.a. 1.03 GJ/ton CO2 for desublimation based process [42] and around 0.3 – 0.5 GJ/ton CO2 for compression-condensation based process6 [43], both with optimized thermal integration. Significant savings can come from use of the “cold energy” from LNG revaporization. In a study by Tuiner et al. for the capture of CO2 from the flue gas generated by a 600 MW coal fired power plant, the estimated energy penalty is around 1.09 GJ/ton CO2 when the cold energy from LNG revaporization is used. If no cold energy is available the energy penalty is 3.6 GJ/ton CO2 [44]. Increasing CO2 concentration in the feed gas decreases the energy requirement of the cryogenic process. Berstad et al. estimates that for flue gases with CO2 concentration >60% the specific separation and compression work ranges from 0.4 – 0.65 GJ/ton CO2 ( lowest operating temperature 50 to -56°C)[43]. For most flue gases from solid fuel combustion the CO2 partial pressure is lower than 60%, thus it is proposed to combine membrane filtration with low temperature capture. The membrane pre-concentrates the feed to the cryogenic process. Belaissaoui et al. estimates that for a hybrid membrane-cryogenic system processing a feed with 15 – 30% CO2, the minimum energy requirement is lower than 3 GJ/ton CO2 (including compression of CO2 to 110 bar) [45]. One major advantage of the hybrid process is that it offers a high degree of flexibility, with respect to the capture ratio and/or final CO2 purity. The technical and economic potential of this technology should further be analysed and industrial demonstrations are yet to be made. One important concern is the capital cost. While clever thermal integration can lower the energy requirement of low temperature CO2 capture, the purchase
6
With high CO2 concentration in the feed.
equipment cost is however estimated to be 2.6 times that of MEA based process handling the same feed [42]. 4.6
CO2 Capture from Air or Direct Air Capture (DAC) Currently direct capture of CO2 from the atmosphere is rather superfluous especially when many
point sources with higher CO2 concentration are available (combustion power plants, biogas production etc.). However for grid independent P2G systems or island concept systems, DAC has several merits, especially on CO2 transport. While the ratio of air (mostly N2 and O2) to CO2 molecules is around 2500/1 [46] and is 1/300th times that of flue gases, the cost is not orders of magnitude different. In a study conducted by the American Physics Society, the total cost (operating + capital cost) of DAC using hydroxide adsorbent is 550 $/ton CO2 captured (440 €/ton), while for coal fired power plant using a MEA-based absorption process the total cost is 62 $/ton CO2 captured (50 €/ton) [47]. The estimated thermodynamic minimum energy to capture CO2 from air and other post combustion capture
0.4 0.3 Normal Human Respiration 0.2 0.1 0 -4 10
-3
10
-2
10 Mole fraction of CO2
-1
10
CO2 in IGCC (~40 - 60%)
CO2 in air (380 - 580 ppm)
CO2 in PCC (10 - 15%)
0.5
CO2 in NGCC (5-8%)
Minimum thermodynamic work, [GJ/tonne CO2)
at 1 atm is shown below.
0
10
Figure 7. Thermodynamic minimum work at 25°C for 100% capture and pure CO2 product at 1 atm. Adopted from [47].
DAC technologies can be divided into 3 steps (1) contacting with air (2) adsorption or absorption, others (3) and recovery of solvent [46]. Adsorption and absorption have the highest potential for application, because majority of the energy needed by the process is only for regeneration. Contacting can be made by direct introduction of air to absorption or adsorption column. The concentration of CO2 in ambient air requires that the sorption process be chemisorption. Among possible CO2 adsorption/absorption chemicals are strong bases such as calcium hydroxide (Ca(OH) 2) [48–53], potassium hydroxide (KOH) [54,55] and sodium hydroxide (NaOH) [54,56–59], these bases
react with CO2 to form carbonates (CO32-). Functionalized physisorbents are also available, monomeric or polymeric amines are either physically adsorbed or permanently immobilized on support materials such as silica, mesoporous materials, carbon fibre and other supports[60–63]. Redox active CO2 carrier molecules have also been applied for electrochemical CO2 capture from air to increase the overall efficiency of atmospheric CO2 to CH3OH production [64]. Electrochemical CO2 capture from air uses redox-active molecules that strongly binds CO2 and can be regenerated by applying an electrochemical potential. This process can likely cut the energy requirement of conventional caustic solvent absorption to around half and even up to a quarter [64,65].
5
Comparison of technology Unlike in CCS, where installing a capture device can lead to reduction of power plant efficiency
through steam bleeding for use in solvent regeneration, when CO 2 capture is thermally integrated to P2G systems, the heat requirements for regeneration may come directly from the heat released by the CO2 reduction process. If the CO2 reduction process follows the Sabatier reaction, there is enough heat from this reaction that can be utilized for the heating requirements of amine absorption (e.g. MEA), NH3 absorption and temperature swing adsorption, see Figure 8. The maximum purity of the CO2 product from the technologies surveyed is presented in Figure 9. Low temperature technologies offer high purity product and narrow purity range. However, amine absorption by MEA and NH3 are also able to supply high CO2 products. Pre-treatment of the flue gas to reduce concentration of trace gases such as H2S may improve this purity. Membrane and temperature/pressure swing adsorption have a wide range of CO2 product purity, therefore these technologies may not offer a reliable supply of high purity CO2 without intensive process optimization design and significant investments. Figure 10 shows the grouping of the CO2 capture technologies reviewed according to the need to dry the gas before CO2 capture. Drying the gas may require auxiliary equipment that can potentially increase the capital investment of the capture plant. MEA and NH3 absorption do not require flue gas drying while LT, membrane and TSA/VSA do. For LT it is especially important that the flue gas is dry to prevent clogging of heat exchange devices.
Figure 8. Summary of energy requirements of different CO2 capture technologies.
Low Temperature Single
Membrane Multi TSA and/or VSA
NH3
MEA
CO2 Product Purity, [%]
Figure 9. Product purity from different CO2 capture technologies reviewed.
Figure 10. Moisture related concerns.
The technological readiness level, TRL, of the CO2 capture technologies surveyed is presented below. MEA and NH3 absorption have the biggest potential for adoption to P2G systems because they cut across all readiness level. Low temperature CO2 capture technologies are still in the laboratory to small pilot scale, but if the experiences from low temperature O2 capture can be adopted, there is opportunity for this technology to become viable.
Figure 11. Technological readiness level of CO2 capture technologies surveyed.
As a rule of thumb, large P2G systems could take advantage of economies of scale. The capacity/size of P2G systems can be a factor of the demand for peak shaving need or the availability of CO2. Therefore it is also important to examine the CO2 recovery rate of the CO2 capture technologies reviewed. In Figure 12, MEA absorption and LT have the highest maximum recovery possible, albeit MEA has a narrow recovery range. Membrane capture on the other hand, has a broad recovery range which is dependent of the number of stages applied. Multi-stages membrane process increases the recovery and product purity with the expense of higher capital cost.
Figure 12. CO2 recovery rate of CO2 capture technologies surveyed.
6
Conclusion P2G technology could support the growth of renewable energy production by addressing the issue
of wind and solar intermittent production. CO2 needed for these technologies could be supplied from point sources or direct air capture. Among the technologies reviewed MEA and NH3 based absorption process are compatible to P2G systems. Their advantage includes, energy compatibility (can be thermally integrated to capture the heat released from the chemical reduction of CO2), high product purity, moisture tolerant (no need to remove moisture prior to the process), high CO2 recovery (especially for MEA) and technological readiness (can be adapted to date). Membrane, TSA/VSA, and low temperature (LT) processes require further development, pilot and demonstration studies, and lower capital cost reduction. For LT, cold energy from LNG regasification can be a potential source of its cooling requirement.
7
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