Download Hi-Res ImageDownload to MS-PowerPointCite This:Ind. Eng. Chem. Res. 2019, 58, 43, 19958-19972

110th Anniversary: Evaluation of CO₂-Based and CO₂-Free Synthetic Fuel Systems Using a Net-Zero-CO₂-Emission Framework

Daniel Sutter
Daniel Sutter
Institute of Process Engineering, ETH Zurich, Sonneggstrasse 3, 8092 Zurich, Switzerland
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Mijndert van der Spek
Mijndert van der Spek
Institute of Process Engineering, ETH Zurich, Sonneggstrasse 3, 8092 Zurich, Switzerland
More by Mijndert van der Spek
http://orcid.org/0000-0002-3365-2289
, and
Marco Mazzotti*
Marco Mazzotti
Institute of Process Engineering, ETH Zurich, Sonneggstrasse 3, 8092 Zurich, Switzerland
*E-mail: [email protected]
More by Marco Mazzotti
http://orcid.org/0000-0002-4948-6705

Cite this: Ind. Eng. Chem. Res. 2019, 58, 43, 19958–19972

Publication Date (Web):October 1, 2019

https://doi.org/10.1021/acs.iecr.9b00880

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Abstract

This work analyzes quantitatively the energy and exergy efficiencies of storing intermittent renewable energy in chemical fuels. In the future energy system, chemical fuels provide a very effective approach for long-term storage and long-distance transport of renewable electricity. For the sake of completeness and simplicity, we consider both carbon-free fuels, namely, hydrogen and ammonia, and carbon-rich fuels, i.e., methane and methanol, synthesized using CO₂ as the precursor. The latter are called CCU fuels as they constitute an application of CO₂ capture and utilization (CCU), which is often advocated to be an effective approach toward climate change mitigation (though no consensus exists). Instead of focusing on the CO₂ conversion step, we apply a system-oriented perspective, grounded in the net-zero-CO₂-emission framework, to quantify merits and drawbacks. In such a framework, we consider eight systems and technology chains where, in the spirit of a circular economy, the only input is renewable electricity and the only output is a service, consisting in delivering either electricity to the grid on demand (power–fuel–power) or a fuel to propel a means of transportation (power–fuel–propulsion); no fossil carbon is used, and no net CO₂ release to the atmosphere occurs. Providing the service of storing renewable electricity in chemical fuels obviously results in a loss of primary energy, which differs in the eight cases considered, depending on the chemical nature of the chemical fuel and on the number and efficiency of the individual steps to synthesize them. Power–CCU fuel–power systems exhibit an energy loss from 65% to 86%, whereas the energy loss of power–CCU fuel–propulsion systems increases to 83–94%. The energy loss of the corresponding systems using ammonia as fuel is similar, whereas that obtained when using hydrogen is significantly smaller, namely, 50–65% and 57–69% in the power–fuel–power and the power–fuel–propulsion case, respectively. Compared to hydrogen, the other energy carriers suffer from increased system complexity and consequently lower efficiency. Exergy analysis has shown low efficiency improvement potential for especially the fuel synthesis step, while the other steps in the chain (electrolysis, extraction from air of CO₂ or nitrogen, fuel utilization, and associated compression) still exhibit higher improvement potentials.

1. Introduction

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The reuse of CO₂ as a feedstock to produce fuels or chemicals has greatly appealed to scientists, industry, and policy makers, as a way to mitigate climate change and to contribute to a circular economy. (1−5) Since the implementation of CO₂ capture and permanent underground storage (CCS) has so far suffered from insufficient public and political support, CO₂ capture and utilization (CCU) has been advocated as a valid alternative to mitigate CO₂ emissions from power plants and industry. At the same time, the emergence of larger shares of intermittent renewables in the energy system has provided a thrust to search for means of long-term, seasonal storage and long-range transport of renewable electricity; tasks that other electricity storage means such as batteries and pumped hydro are unable to provide. (6,7) For these applications, the production of hydrogen from green electricity and its combination with captured CO₂ to form carbon-based fuels could provide an opportunity. These CCU fuels would allow one to keep using existing energy infrastructures that represent billions of dollars of sunk investments instead of switching to completely new energy infrastructures, such as hydrogen networks. (2,8−10)

However, numerous studies have contrasted the optimism above by showing that the CO₂ mitigation potential of CCU fuels and other products may often be low, (11−13) that the usable CO₂ volumes may be very small, (13,14) and that the costs may be very high. (5,15) This has led to an emerging consensus that CCU in general needs to be considered from a system analysis perspective rather than as a standalone technology, which has so far often been the case. (16) A CCU fuel subsystem would then be analyzed within a larger system that includes harvesting renewable energy (RE), producing hydrogen via water electrolysis, (re)capturing CO₂ from point sources or from air, converting CO₂ (and hydrogen) into C-rich products (e.g., fuels or chemicals) and using such products, and handling the C-rich waste (most often CO₂ again). (16) Initial physical performance indicators of such a system, and of its CCU fuel subsystem, could include the energy use requirements of its components. Key considerations of the analysis of CCU fuel systems include the identification of the need and possibilities to return any CO₂ emissions back into the system when emitted.

The use of detailed system analysis, especially techno-economic and life cycle analysis (LCA), is indispensable to present a complete picture of such complex systems. However, sound techno-economic and life cycle analyses require one to input large amounts of detailed data on a rather heterogeneous set of system components, data that may not be readily available at early stages of technology development. In addition, full cost analysis and LCA may require more time than it would be initially justified for new, early stage technologies. Therefore, we here advocate, and apply, a simplified comparative system analysis approach, rather than a detailed environmental and/or economic analysis. This comparative approach is meant as an initial sanity check for novel energy technologies. Rather than a substitute for detailed LCA or economic analysis, it can be used in a complementary way as a means of prescreening. In addition, it is based on merely physical inputs that are often already available early in a technology’s development cycle as well as on indicators that are easy to interpret.

Our comparative approach is based on the framework of a net-zero-CO₂ world and of net-zero-CO₂ CCU systems functioning within it. We introduce this framework because CCU technologies that are developed now are likely to be deployed in a net-zero-CO₂ world: many leading scientists estimate that we may have to reach net-zero-CO₂ emissions already by 2050 to fulfill the targets of the Paris Agreement. (17−22) Moreover, the net-zero-CO₂-emission constraint drastically simplifies the analysis by eliminating the discussion on how much CO₂ is actually mitigated by CCU (or other GHG mitigation) systems: every carbon atom released to the atmosphere must be taken back; every fossil carbon atom produced must be returned to the subsurface. Finally, the simplified and somewhat idealized approach proposed here allows one to draw very insightful conclusions about key features of CCU fuel (sub)systems based on a robust assessment of the technology’s potential regarding physical limitations.

Using the net-zero-CO₂ emission framework, we will show that it is technically possible for CCU fuel systems to operate in a net-zero-CO₂ world but that such systems face significant challenges in terms of energy efficiency.

This manuscript is organized as follows. In Section 2, we give an illustrative description of net-zero-CO₂-emission systems as compared to their net-positive- and net-negative-CO₂-emission counterparts. Then, in Section 3, we present the synthetic fuels that we are going to analyze in the net-zero-CO₂-emission framework, and we describe the corresponding technology chains for their synthesis using renewable electricity as input and for their use to provide either electricity or propulsion services. In the same section, we describe in detail the methods we use to quantitatively assess the energy efficiency of the eight technology chains considered. In Section 4, we present the results, which include a quantitative assessment of both energy and exergy efficiencies as well as a sensitivity analysis of such values against variations of the input parameters. Finally, we draw conclusions in Section 5.

2. Net-Zero-CO₂ World and Net-Zero-CO₂ CCU Fuel Systems

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First, to place net-zero-CO₂ systems in context, let us define net-zero-CO₂-emission systems in an illustrative manner (Figure 1, yellow frame) together with their two counterparts, i.e., positive- and negative-CO₂ emission systems (Figure 1, red and green frames, respectively). Nine technology chains are represented. In all but chain 9, the blue boxes represent conversion processes (e.g., a power plant, an airplane, or a chemical factory) delivering a function (either a service or a product), while releasing CO₂ from either a point source (amenable to conventional CO₂ capture, large blue box) or a distributed source (not amenable, small blue box).

Figure 1. Representation of possible technology chains yielding linear or circular economies, in a net-positive, net-zero, or net-negative CO₂-emission system. (16,23) The representation includes fossil-based systems, CCU-fuel-based systems, and bioenergy-based systems. Process units include conventional postcombustion CO₂ capture; direct capture of CO₂ from air (DAC, requiring C-free renewable energy to operate); biomass conversion plants; CO₂ conversion, including an electrolyzer for H₂ generation and a collector of C-free renewable electricity (the stylized yellow spark). Arrows represent material fluxes (equipped with storage capacity) of fossil (from the subsurface, red), synthetic (from a conversion plant, blue), biogenic (from biomass, green), or oxidized (CO₂, dark gray) carbon. The ultimate CO₂ fate can be either release to the atmosphere (light gray cloud) or storage in the subsurface (stylized anticline aquifer).

To assign each of the nine technology chains to one of the three categories, i.e., positive-, negative-, or net-zero-CO₂-emission, the following simplifying assumptions are made: the CO₂ capture rate is 100%; the yield and selectivity of conversion reactions are 100%; the biomass conversion plant has 100% yield; the use of biomass to generate bioenergy is carbon neutral; CO₂ conversion and direct air capture (DAC) of CO₂ are powered by C-free renewable energy; no other environmental impact but CO₂ emissions is factored in; CO₂ underground storage is permanent. Though not completely accurate from an engineering and/or environmental perspective, such assumptions provide a straightforward first-order approximation that serves well the purpose illustrated in the introductory section (when discussing Figure 2, we will make more realistic assumptions, as detailed below).

Figure 2. Block diagram of the power–fuel–power systems investigated: (a) hydrogen, (b) methane, (c) methanol, and (d) ammonia. The blocks include their corresponding pressure levels, energy efficiency, and second-law (exergy) efficiency, and CO₂ capture rate in the case of the power plants. The systems’ cyclic efficiency is given in the upper left corners. The supply of electricity to the fuel synthesis and to the DAC/N₂-separation units is not represented in the figure for the sake of clarity. For methanol, the source of the CO₂ and H₂O emissions is the combustion of a purge stream containing CO₂ and CO. In the case of methane, the water is a byproduct of the Sabatier reaction and the CO₂ is part of the unreacted feed. These are minor streams but are included in the figure for completeness. The abbreviated fuel-to-power conversion plants are hydrogen solid oxide fuel cell (H₂SOFC) and gas turbine combined cycle (GTCC). See Figure 3 for the corresponding power–fuel–propulsion chains.

Chains 1 and 7 are deployed today, the former pulling fossil-C from the subsurface and dispersing it as CO₂ to the atmosphere (exemplary of a linear economy, L-economy) and the latter using biogenic-C, obtained by photosynthesis from atmospheric CO₂ and water, and therefore ideally closing the carbon cycle (paradigmatic of a circular economy, O-economy). Chains 3 and 4 implement CCS with either industrial-scale capture or direct air capture as well as with underground storage. Chains 8 and 9 uptake CO₂ from the atmosphere either naturally or via DAC, either supply or demand energy, and store CO₂ underground; these are the only two chains in the figure that potentially yield negative CO₂ emissions.

Chains 2, 5, and 6 include CCU fuels, whereby the first still belongs to the L-economy, with the fossil carbon being used twice: first in a large-scale plant with CO₂ capture and, then, after conversion, in a decentralized unit with CO₂ release to the atmosphere, hence with CO₂ emissions being reduced by a maximum of 50%. The last two chains realize a closed carbon cycle, indeed a circular economy. Chain 5 on the one hand includes for instance a power–fuel–power technology chain (we use the term “power” here in its colloquial form as an equivalent to electricity, while acknowledging that power is defined in physics as “the rate at which energy is transferred”), whereby the CO₂ generated upon burning the C-rich fuel is captured via postcombustion capture. Chain 6 in turn includes for instance a power–fuel–propulsion technology chain, whereby the CO₂ emitted by the means of transportation (road vehicle, ship, or plane) is taken back from the atmosphere via DAC. Since chains 5 and 6 belong indeed to a net-zero-CO₂-emission world, they are the main subjects of this work and will be analyzed in detail in the following.

3. Methods

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3.1. Technology Assessment Using a Net-Zero-CO₂-Emission Framework

On the basis of the discussion in the previous sections, in this work, we analyze CCU fuel using a net-zero-CO₂-emission framework by going through the following steps:

1.	Defining the functional unit (or the key product) that the system provides, which is good practice in techno-economic and environmental analysis of energy systems.
2.	Drafting a system diagram of the CO₂-positive base system and identifying where in this system there are direct CO₂ emissions.
3.	Introducing measures/technologies to return the CO₂ emissions back to the system, thus closing the carbon loop.
4.	Calculating performance indicators, which can be the typical technical, economic, or environmental indicators; in this work, we consider only technology first-law and second-law efficiencies, i.e., only technical indicators.
5.	Assessing and comparing the results, i.e., interpreting the calculated indicators and comparing them to alternative systems to gain insight in the relative performance of different options.

CCU fuels will be compared with C-free synthetic fuels, whose synthesis and utilization will also be considered under a net-zero-CO₂-emission constraint.

3.2. Case Studies

As indicated in the introduction, a major advantage of synthetic fuels is that they enable long-term (e.g., seasonal) energy storage, because the fuels can be stored with negligible losses and because the amount of energy stored can be decoupled from the capacity of the upstream power uptake and the downstream power generation. This is commonly referred to as power–fuel–power. Moreover, CCU fuels can be used as a transport fuel, where they replace conventional fuels that are based on fossil oil. Such systems are commonly referred to as power–fuel–propulsion. For both cases, we have chosen a functional unit of 1 GW output: 1 GW of electricity in the case of power–fuel–power and 1 GW of propulsion in the case of power–fuel–propulsion.

Two relevant and widely investigated CCU fuels have been chosen for the analysis: (i) methanol (CH₃OH or MeOH), which has been discussed for decades as a major energy vector for its relatively easy synthesis from CO₂ and subsequent handling, (2) and (ii) methane (CH₄), which is obviously of major importance due to the existing natural gas infrastructure and the high efficiency of modern gas-fired power plants. (24) Carbon-free synthetic fuels could also function as synthetic energy carriers, and therefore, we included two for comparison. These are hydrogen and ammonia (NH₃), such that the comparison of carbon-based and carbon-free synthetic fuels includes a liquid and a gaseous fuel each (NH₃ liquefies at moderate pressures of around 10 bar and is therefore considered as a liquid fuel). Ammonia is receiving increasing attention as an efficient hydrogen carrier and as a fuel, (25,26) and while ammonia combustion and possible nitrogen recycling need additional research and development, NH₃ synthesis, transport, and storage are well established. For each of these four cases, a generic system has been designed that fulfils the net-zero-CO₂-emission constraint.

3.3. System Design and Infrastructure Requirements

Figure 2 shows the power–fuel–power technology chains as block diagrams. The hydrogen chain depicted in Figure 2a is the most direct power–fuel–power route. The hydrogen is produced through electrolysis, transported, and stored according to time and spatial needs and converted back to power in a fuel cell. To have zero direct CO₂ emissions, the electricity fed to the electrolyzer needs to be zero carbon (thus, renewable or nuclear-based). The zero-carbon nature of any energy flow entering the system is an important requirement for net-zero systems; any carbon input needed outside of the system boundaries defined here should be compensated by extracting the equivalent amount of carbon dioxide from the atmosphere. Note that, in each block, the operating pressure (see Section 3.4.2) as well as the efficiency (see eq 1) and the second-law or exergy efficiency (see eq 5) are indicated.

The methane technology chain shown in Figure 2b is significantly more complex. While the first step of hydrogen production via electrolysis is the same as before, an additional conversion unit is required that synthesizes CH₄ from H₂ and CO₂. The technology block for power generation from methane is assumed to be a gas turbine combined cycle (GTCC) with postcombustion CO₂ capture, which recycles 90% of the generated CO₂. The remaining CO₂ emissions from the power plant and the emissions from the fuel synthesis unit are here assumed to be balanced by a DAC unit (for the sake of simplicity, we do not consider here uptake of CO₂ from the atmosphere via biomass growth). The technology chain for methanol in Figure 2c obviously has a very similar structure and entails the same technology assumptions as for the methane system. The power–NH₃–power chain in Figure 2d includes the separation of nitrogen from air and an ammonia synthesis step in addition to the H₂ generation via electrolysis that is common to all four chains, but it reduces the complexity compared to the C-based fuels, because the recovery of CO₂ from the power plant is not required (and because the theoretically feasible recycling of N₂ from combustion was omitted).

The storage needs of the different technology chains depend on the operating strategies of the individual technology blocks. Power generation and hydrogen production from surplus RE will intuitively operate asynchronously in order to fulfill the purpose of electric energy storage. To that end, one or more of the chemical compounds present in the electricity storage systems need to be temporarily stored.

For power–fuel–power systems (Figure 2), this could be accomplished in different ways:

Concurrent operation of fuel synthesis and final power generation: this strategy minimizes the need for fuel and CO₂ storage, while hydrogen storage is needed as it effectively bridges the time between RE input and electricity generation. Such operation however foregoes the advantage of the synthetic fuels over H₂ in terms of specific volumetric energy density. It also requires the synthesis plant to run as flexibly as the power plant, which may be unwanted from a plant performance and from a capital cost recovery perspective.
Synchronizing the operation of electrolysis and fuel synthesis: this strategy minimizes the need for H₂ storage, as H₂ is directly converted to fuel. However, large-scale storage both of the synthetic fuel and of CO₂ (since the GTCC power plant with CO₂ capture operates asynchronously to the electrolyzer) is required as a consequence, and the same operational and economic issues of flexible operation of the synthesis plant arise.
Fully independent operation of the fuel synthesis plant, either maximizing its capacity factor or operating it flexibly; this strategy requires storage of significant amounts of H₂, of synthetic fuel and, for carbon-based fuels, of CO₂.

For power–fuel–propulsion systems (Figure 3), neither is the final use of the fuels synchronized with the availability of renewable electricity, nor can the CO₂ generated in the final conversion of the CCU fuels be recycled to the fuel synthesis. Consequently, CO₂ capture (via DAC or BECC) and fuel synthesis can be synchronized, and the need for CO₂ storage minimized. Depending on the operating strategy, large-scale storage of either H₂ (capacity factor of fuel synthesis maximized) or synthetic fuel (fuel synthesis synchronized with renewable energy) is required.

Figure 3. Block diagram of the four power–fuel–propulsion systems investigated: (a) hydrogen, (b) methane, (c) methanol, and (d) ammonia. The blocks include their corresponding pressure levels, energy efficiency, and second-law (exergy) efficiency and CO₂ capture rate in the case of the power plants. The systems’ cyclic efficiency is given in the upper left corners. The supply of electricity to the fuel synthesis and to the DAC/N₂-separation units is not represented in the figure for the sake of clarity. The pressure indicated in the final conversion blocks represents the vehicle’s tank. For methanol, the source of the CO₂ and H₂O emissions is the combustion of a purge stream containing CO₂ and CO. In the case of methane, the water is a byproduct of the Sabatier reaction and the CO₂ is part of the unreacted feed. These are minor streams but are included in the figure for completeness. The abbreviated fuel-to-propulsion technologies are hydrogen polymer electrolyte membrane fuel cell (H₂PEMFC), internal combustion engine (ICE), and direct methanol fuel cell (DMFC).

In summary, from a system design perspective, net-zero-CO₂-emission power–CCU fuel–power systems need the following elements in addition to their CO₂ positive counterparts: CO₂ capture means, fitted to fuel combustion plants and complemented with CO₂ capture from the air via DAC or BECC; large-scale intermediate storage of at least one of the involved chemical compounds, be it hydrogen, CO₂, the CCU fuel, or all three.

3.4. Thermodynamic Analysis Assumptions

3.4.1. Building Blocks

The general building blocks that were used within the net-zero-CO₂-emission framework include hydrogen production, fuel synthesis, gas separation (i.e., CO₂ or N₂), fuel combustion, fuel/feedstock compression, and intermediate fuel/feedstock storage. For the thermodynamic analysis, these generic blocks were filled with specific technologies. We used the corresponding technologies that have advanced the furthest: wherever possible, commercial technologies were used; when necessary, technologies that are in pilot or demonstration phase were applied. The rationale behind this criterion for selection was to assess the potential of synthetic fuels under realistic assumptions, being rather optimistic than conservative for technologies still at the demonstration stage. The individual technologies used in the technology chains are illustrated in Figures 2 and 3, and their features are reported in Table 1. In particular, the second and the third columns report the electricity and the heat input per unit product synthesized, respectively, whereas the fourth column shows the conversion efficiency with respect to the lower heating value (LHV); the last column reports the source of the previous data. Note that all technologies, with the exception of ammonia conversion in an internal combustion engine (ICE), are commercial or precommercial.

Table 1. List of Individual Technologies Used in the Technology Chains Illustrated in Figures 2 and 3 and Their Features

building block	electricity input requirement (MWh/t product)	heat input requirement (MWh/t product)	conversion efficiency (LHV) (%)	data source
direct air capture	0.25	1.750		manufacturer estimatea
fuel synthesis methanol	0.169	0.439		modeling studyb
fuel synthesis methane	0.33	–3.008		pilot plantc
fuel synthesis ammoniab	0.03	0		modeling studyd
N₂ production (air separation unit) (45)	0.02	0		manufacturer datae
H₂ compression from 30 to 700 bar	23			Aspen Plus modelf
CH₄ compression from 8 to 66 bar	1.78			Aspen Plus modelf
CH₄ compression from 66 to 250 bar	0.89			Aspen Plus modelf
H₂ production (electrolysis at 30 bar)			70	literature and manufacturer datag
H₂ PEM FC			60	manufacturer datah
direct methanol FC			35	prototype and modeling studyi
H₂ SOFC			61	manufacturer data and modeling studyj
GTCC w/o CO₂ capture			59	modeling study based on vendor datak
GTCC with CO₂ capture			51	modeling study based on vendor datak
fuel conversion methane ICE			22	manufacturer data/US EPA driving cycle testl
fuel conversion ammonia ICE			22	prototype
subcritical steam cycle efficiency			30	modeling studym
biomass power plant with CCS			28	modeling studyn
biomass power plant without CCS			38	modeling studyn
charger/inverter			95	modeling studyo
battery			95	modeling studyo
electric drive			90	modeling studyp
hydrogen-fired boiler			85	manufacturer dataq

^{^a}

Climeworks estimate. (30)

^{^b}

Values used from the process modeling study by Pérez-Fortes et al., (5) based on the process by Van-Dal and Bouallou. (32)

^{^c}

Values retrieved from ref (28), which uses pilot plant results reported by Müller et al. (46)

^{^d}

Based on George and Richards (38) (as cited by Avery (36)).

^{^e}

Industry value reported by Castle, (45) as cited in Grinberg Dana et al. (26)

^{^f}

Compression energies were taken from Aspen Plus, using a 72% isentropic efficiency. An eight-stage integrally geared compressor with intercooling to 35 °C was assumed for H₂ and CH₄ compression to propulsion pressures.

^{^g}

An electrolyzer efficiency of 70% was used on the basis of refs (8and27) where Siemens reports a 75% efficiency of their largest electrolyzer model. (47,48) Late 2000 to early 2010 vendor inquiries by NREL indicate LHV efficiencies between 61% and 66%. (49,50) A 70% LHV efficiency corresponds to an electricity demand of 48 MWh/t_H₂.

^{^h}

Manufacturer data as collected by the US DOE. (44)

^ⁱ

Based on DMFC prototypes and modeling studies. (33,34,51)

^{^j}

Based on the modeling study in ref (43); manufacturer data collected by the US DOE states efficiencies of 60%. (44)

^{^k}

Modeling study based on gas turbine and CO₂ capture plant data from vendors. (29)

^{^l}

Data from car manufacturers and US EPA was used for midrange ICE vehicles running on natural gas. (52)

^{^m}

Based on NETL (53) and Muñoz et al. (54)

^ⁿ

Based on a modeling study by DOE/NETL, reported in Schakel et al. (55)

^{^o}

Using modeling assumptions reported by Van Vliet et al. (56)

^{^p}

Values used from a modeling study by Pellegrino et al. (57)

^{^q}

Manufacturer data from Cleaver Brooks. (58)

The hydrogen is produced in all cases by water electrolysis using polymer electrolyte membrane (PEM) technology. (27) For the methane zero-emission loop that produces 1 GW of power as a functional unit, the specific building blocks included methane (Sabatier) synthesis (28) (including a subcritical steam turbine cycle to recover released heat), combustion of the fuel in a GTCC with CO₂ capture and compression, (29) and DAC of CO₂ to capture residual CO₂ emissions. The Climeworks process (30) was selected for DAC because it is already deployed precommercially, with several units built, and in operation. It is worth noting that, since the same technology for DAC is used in all calculations, the comparative evaluation of the four power–CCU fuel–power and power–CCU fuel–propulsion systems is not affected by the choice of the specific DAC technology and its relevant performance parameters. The sensitivity analysis carried out in Section 4.4 accounts for uncertainties in the performance parameters of DAC that are larger than the declared differences among currently known technologies. GTCC technology was selected because it represents the current state-of-the-art in gas-fired, centralized power generation. When methane was used to provide a functional unit of propulsion, we assumed that it is burned in an internal combustion engine (ICE), as usable low temperature direct methane fuel cells are currently still in a preliminary stage of development, (31) while methane ICEs are in wide use.

For the methanol technology chains, we used the single step methanol synthesis by CO₂ hydrogenation, studied earlier by Pérez-Fortes et al. and Van-Dal and Bouallou. (5,32) For the production of a functional unit of power, we assumed that methanol was also combusted in a GTCC with CO₂ capture and compression, assuming the same efficiency as for natural gas. For a functional unit of propulsion, we chose to use a direct methanol fuel cell. (31,33,34) For the ammonia power–fuel–power system, we also assumed that it is burned in a gas turbine coupled with a combined cycle. While early research and demonstration highlighted the potential for reaching higher electric efficiencies than with conventional hydrocarbon fuels, (35,36) we conservatively assumed the same conversion efficiency as for a natural gas combined cycle without CO₂ capture and compression. Although conventional ammonia plants generate hydrogen via natural gas reforming, we used a route that generates H₂ via electrolysis and N₂ with an ASU to make it comparable to the other synthetic fuels. This production route exists commercially (37) but is less common than the reforming route. The energy demand for feed gas compression in the ammonia synthesis unit was determined from the integrated process design of George and Richards (38) (as cited by Avery (36)). The high efficiency of the synthesis is in agreement with the energy analysis of conventional processes, which have identified the major losses to occur in the, in our case obsolete, reforming section. (39,40) We applied the energy demand for ASU as compiled by Grinberg Dana et al. (26) For propulsion, ammonia combustion in an ICE was assumed to have the same efficiency as methane. (41,42) Finally, for the hydrogen case, we assumed combustion in fuel cell systems: a solid oxide fuel system for the power application (43) and a polymer electrolyte fuel cell for the propulsion application. (44) Before use in the vehicle, the hydrogen is assumed to be compressed to 700 bar, using an isentropic compression efficiency of 72%.

3.4.2. Pressure Levels

The pressure levels selected as reported in

Table 2 determine compression energies and storage densities.

Table 2. Transmission and (Intermediate) Storage Pressure Assumed in This Work and Their Corresponding Densitiesa

gas	pressure (bar)	corresponding density (kg·m^–3)
hydrogen	30	2.4
CO₂	150	876
N₂	100	113
methane	66	48
methanol	1	790
ammonia	10	603

^{^a}

Note that when hydrogen or methane are used for propulsion, they are pressurized at the filling station to pressures of 700 and 250 bar, respectively.

Methane and methanol production are reported to take place at elevated pressure; this work assumed 30 bar for both, equivalent to Pérez-Fortes et al. (5) and in line with studies on CO₂ methanation. (27,59) The methane transmission pressure in Europe is typically between 60 and 70 bar. IEAGHG assumes 66 bar; (29) we adopted this value here. In the case of propulsion, the methane was assumed to be compressed to 250 bar at the fuelling station. As methanol is liquid at ambient pressure, it is assumed that its transport infrastructure operates at 1 bar. Where pressure differentials exist between the operating pressures in the individual building blocks and the transport infrastructure, these were accounted for by additional compression or expansion.

Also, hydrogen was assumed to be produced, transported, and stored at 30 bar. Assumptions on hydrogen transport and storage values vary. Existing hydrogen networks include fairly modest pressures of 25 bar (60) and up to higher pressures of 110 bar. (61) The UK H21 project reports hydrogen storage pressures of 20–60 bar for short-term storage and up to 200 bar for seasonal storage. Only in the case of use for mobility purposes is hydrogen compressed at the fuelling station to 700 bar.

CO₂ storage is likely done at high pressure; in the US, a value of 150 bar is typically assumed. (62) Given the necessity of intermediate (geological) CO₂ storage, we assumed this pressure for the entire CO₂ network.

3.5. Efficiency Analysis

The quantitative comparison of the four power–fuel–power and power–fuel–propulsion systems has been carried out on the basis of chain efficiencies, which are defined as ratios of the generated electric or propulsion energy, respectively, and the ingoing renewable electricity. The efficiency of the individual blocks reported in Figures 2 and 3 is based on the lower heating value (LHV) of the fuels and on electric energy. Heat demands, which occur in the DAC and in the methanol synthesis block, are converted into the calorific value of H₂. In order to guarantee flexibility in the operating strategy of the plant, it is assumed that H₂ is burned to cover these heat demands, independent of the current availability of intermittent RE. The heat rejected by the methane synthesis is converted to electricity applying a subcritical steam cycle. Efficiencies are taken directly from the literature for the electrolysis and the final conversion step and calculated for the fuel synthesis as follows

(1)

where W is electric energy or propulsion work, Q is heat, η_elec is the efficiency of the electrolyzer, η_boiler is the LHV efficiency of a hydrogen boiler, m_i is the mass of component i in the feed stream, m_j is the mass of component j in the product stream, and ΔH^LHV is the enthalpy of combustion of each feed or product species.

We also calculated how much each block contributed to the total efficiency loss of the overall system

(2)

where ΔU_block is the energy loss over a block and W_RE,in is the total renewable energy entering the chain. Note that here, the heat input for DAC or for synthetic fuel synthesis units is included in the term Δ(Σm_iΔH_i^LHV), since we have assumed this to be supplied by hydrogen, which is burnt in a boiler to supply heat.

3.6. Second-Law Analysis

The individual blocks were analyzed in terms of second-law efficiencies in order to study their level of perfection, i.e., the thermodynamic potential for further improvement. In order to consider the value of purified noncombustible materials (CO₂, N₂), exergy efficiencies were calculated, where relevant, by applying the specific exergy of the feed and product components instead of the calorific values (i.e., LHV). Exergy, or availability, is defined as the maximum theoretical work that can be obtained from a system as it interacts with its environment toward equilibrium, and it is based on the second law of thermodynamics. (63) The specific exergy comprises a chemical (e^ch) and a thermomechanical (e^th) contribution.

(3)

The two terms were determined using the tabulated values of Szargut et al. (64) and temperature and pressure specific enthalpy and entropy data reported by NIST, (65) respectively. The exergy of sensible heat was calculated using the Carnot efficiency

(4)

where T₀ is the ambient temperature of 298 K.

The exergy efficiency of the individual blocks was defined as

(5)

where η_ST is the subcritical steam cycle efficiency reported in Table 1. Note that the methane synthesis is the only block in the current analysis, where η_ST was applied, since it is the only block for which the modeled technology assumes the export of power from excess heat. We chose to use the steam cycle efficiency instead of a Carnot efficiency in order to highlight the improvement potential of the technology block as it is modeled in this work, i.e., including improvements in the use of the excess heat compared to the current use in a subcritical steam cycle. The synthesis blocks of MeOH and NH₃ utilize the heat generated by exothermic reactions for internal purposes.

3.7. Sensitivity Analysis

The local (single parameter) sensitivity analysis in this work focused on the sensitivity of net system efficiency to changes in technology specific input values. Minimum and maximum input values were investigated for the electrolysis efficiency, the energy use of DAC and ASU, the energy use (and production in the case of methane) of the fuel synthesis technologies, and the efficiency of the fuel conversion technologies. The minima and maxima were mostly selected based on real lower bounds and optimistic upper bounds (sometimes realistic, sometimes assuming the max theoretical efficiency where the current state of technology is already close to reaching that). The exact values are included in Figure 7, and some assumptions are highlighted in the text below.

For electrolysis, we used 2013 efficiency quotes from 4 vendors, as reported by NREL, (50) as the lower end (61%_LHV efficiency), which likely includes the balance of plant and cycling inefficiencies. (8,49) Siemens currently reports an efficiency of 75%_LHV, (48) and because this is close to our base assumption of 70%_LHV, we rather assumed the maximum theoretical LHV efficiency of 82% (49) as the upper limit. For DAC, we used power and heat consumptions of 150 and 1200 kWh as a lower bound, based on a presentation by Global Thermostat. (66) As the upper bound for the electricity consumption, we used 500 kWh, twice as large as our base case. We used an upper heat input of 2500 kWh, which is our own estimate.

For fuel synthesis, we aimed at representing the most favorable set of assumptions possible for the high end. This implies that reactions would occur with ideal stoichiometry assuming that equilibrium limitations are overcome through recycling of the unreacted reagents. Any consumption of heat and electricity is neglected, and any rejected heat (exothermic reactions) is converted to electricity assuming a Carnot efficiency. Additionally, any release of CO₂ from the synthesis plant, e.g., through purge streams, is captured with a 100% CO₂ capture rate and with a negligible energy requirement. For the low end, we increased all energy and heat requirements of the fuel synthesis step by 50%. These inputs are already small, and increasing them by a lower percentage would not lead to notable changes in output.

For hydrogen conversion to power, we used the lower value of 49% calculated by Peters et al. (43) as our lower bound. The higher bound was set based on the DOE EERE long-term target (70%). (31) For the carbon-based fuels, we selected an upper efficiency value assuming replacement of GTCC’s with natural gas fuel cells with fuel pre-reforming and integrated CO₂ capture (with a capture rate of 99.5%). The lower efficiency value assumes combustion in open cycle gas turbines (OCGT) (67,68) with a CO₂ capture efficiency penalty of 10% pts. For ammonia conversion to power, also fuel cells and OCGTs were assumed as the most and least efficient technologies, although the OCGTs are without CCS in this case, and therefore, their efficiency is higher.

Finally, the minimum and maximum values for fuel conversion to propulsion depend on the fuel type. For hydrogen, we assumed a PEM fuel cell maximum efficiency of 70%, in line with the DOE EERE long-term target. (31) Since the current PEMFC efficiency is approximately 60%, (31,44) it was assumed that the minimum fuel cell efficiency is 50%. For DMFCs, Rashidi et al. (34) report a modeled efficiency range from 20% to 45%, which was adopted here. For (compressed) natural gas combustion in ICEs, Curran et al. (52) used a tank-to-wheel efficiency range of 14–26%, based on various driving cycle tests reported by the US DOE and EPA. One of the sources behind the DOE range is Thomas, (69) who derive combined highway/city tank-to-wheel efficiencies from EPA dynamometer driving cycle tests on 34 passenger vehicles. These data are however for gasoline ICEs, and Zamfirescu and Dincer (70) report that compressed natural gas (CNG) vehicles have an efficiency some 4% higher than gasoline vehicles. Adding another 5% potential upside in ICE development in the next decades, we adopted a maximum efficiency of 35% for CNG ICEs, while using the lower value of 14% reported by Curran et al. (52) For the ammonia ICEs, Mørch et al. (71) measured 5% higher ICE efficiencies for high ammonia (>90%)/low hydrogen (<10%) mixtures compared to petrol ICEs. We therefore adopt the same upper bound as for the CNG ICEs of 35%. This is in line with the ∼45% efficiency reported for a very novel high pressure ratio ammonia ICE design, (70) when subtracting a 10% pt efficiency loss for the drive train and parasitic losses. (72) As a minimum efficiency for the ammonia ICE, we also adopted the lower bound of 14% of Curran et al. (52)

4. Results and Discussion

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4.1. Primary Energy Loss over the Power–Fuel–Power Chains

When the synthetic fuels in a power–fuel–power cycle are analyzed, a large loss of primary renewable power over the system is observed (see Figure 4a and the Supporting Information). Figure 4a shows that the net-zero-CO₂ power–methane–power system loses more than 70% of the primary renewable power, most of which is due to the electrolysis step and to the fuel combustion in the GTCC with carbon capture. A much smaller loss is observed in the methane synthesis step (approximately one-third of the loss in either electrolysis or GTCC), and a minor amount is lost in the DAC operation. In order to better illustrate the comparison, the waterfall diagrams of Figures 4a and S1–S4 have been collapsed into stacked bars in Figure 5. Here, methanol and ammonia show a similar pattern as methane, with electrolysis and fuel combustion representing the major losses. For methanol, the losses attributed to DAC increase compared to methane, due to a higher carbon content of the fuel per unit calorific value. The energy demand for the separation of nitrogen from air in the ammonia chain is significantly smaller than the corresponding demands for CO₂ separation for methane and methanol, owing to an advantageous stoichiometry and to the fact that the nitrogen concentration in air is 3 orders of magnitude higher than that of CO₂. The fuel synthesis steps exhibit similar losses for all three fuels involving fuel synthesis. In the hydrogen system, the losses are limited to electrolysis and fuel combustion, each contributing to a similar extent.

Figure 4. Waterfall diagrams of power–methane–power (a) and power–methanol–propulsion (b).

Figure 5. Breakdown of primary renewable power losses and resulting cycle efficiencies to produce 1 GW of power and/or propulsion (using DAC for the CCU fuel systems). The darkest color represents the relative energy output of each chain. H₂ compression occurs only in the hydrogen for propulsion chain, where additional compression is required after electrolysis. “Air separation” indicates the efficiency loss related to DAC for the CCU fuels and to N₂ separation for ammonia. “Air separation” and “fuel synthesis” do not occur in the hydrogen chains. Of the chemical energy carriers, hydrogen has the highest cycle efficiency, especially when providing propulsion in a transport application. The biggest losses are incurred in all systems in the electrolysis and fuel combustion steps, not in the fuel synthesis step. For the CCU propulsion cases, these losses are complemented with a large loss for direct air capture of CO₂.

Comparing the four energy carriers, Figure 5 shows that the net cycle efficiency of the hydrogen system is the highest, with a value of approximately 43%. Also, ammonia has a higher efficiency (36%) than the CCU fuels (26–28%). This confirms earlier studies on the assessment of chemical energy carriers (8,26,27) in a linear (non net-zero-CO₂) system. In the net-zero-CO₂ assessment, the need to introduce air capture of CO₂ only increases the difference between CCU fuels and hydrogen or ammonia. Overall, the efficiency cost of facilitating long-term, seasonal, electricity storage by means of power–fuel–power chemical energy storage in synthetic fuels is high; i.e., more than half of the energy is lost.

4.2. Primary Energy Loss over the Power–Fuel–Propulsion Chains

The investigation of the power–fuel–propulsion cycle for hydrogen (blue bars in Figure 5) shows only a minor efficiency reduction compared to its power–fuel–power cycle, due to the additional compression to 700 bar typical for mobility applications and a slightly lower efficiency of the final energy conversion step (PEMFC instead of SOFC; see Figure 2). All other fuels show a drastic reduction of the cyclic efficiency to between 9% and 13%. Significantly higher losses occur in the final energy conversion step, where the availability of a fuel cell for mobility applications represents a competitive advantage for methanol (DMFC, 35% LHV efficient) compared to methane and ammonia, where ICEs (22% LHV efficient) are considered to be the state-of-the- art.

In addition, the nonavailability of the CO₂ recycle from the combustion to the fuel synthesis, due to technical and logistical impracticalities, leads to a drastic increase of the DAC utilization and of the corresponding energy requirements (see Figures 4b and 5 and the Supporting Information). This is a large difference to net-positive power–fuel–propulsion systems that only reuse the CO₂ once. In a net-zero-CO₂ setting, the CCU fuels thus perform substantially worse than in a net-positive (the classical) setting. Overall, the hydrogen system is approximately three times more efficient than the systems based on CCU fuels and on ammonia. Its intrinsic advantage (i.e., lower complexity due to the avoidance of the separation/extraction from the atmosphere and of the fuel synthesis) is even clearer in the power–fuel–propulsion chains than in the power–fuel–power systems. In addition, the H₂–PEMFC is the most efficient fuel-to-propulsion energy conversion technology today, when only energy efficiencies (hence, only operating costs) are considered. Such a result should of course be considered together with the costs associated with the implementation of the different technology chains before making strategic decisions about infrastructure development.

In order to guarantee flexibility in the operating strategy of the individual blocks, the base case assumes that the heat demands of DAC and of the fuel synthesis (namely, MeOH synthesis) are covered by hydrogen-fired boilers. In times when RE is available, direct electric heating could be applied, such that the inefficiencies of electrolysis and the H₂ boiler are avoided. For the low-quality heat demand of the adsorption-based DAC units at around 100 °C, high-temperature (HT) heat pumps could further improve the efficiency in such times. However, the effect on the chain efficiencies is limited, even if the availability of RE is assumed to be temporally unlimited and a HT heat pump with a COP of 2 is used to cover the DAC heat demand. The resulting chain efficiencies are 29.1% and 27.4% for the CH₄ and MeOH power–fuel–power chains and 11.1% and 16.4% for the CH₄ and MeOH power–fuel–propulsion chains, respectively.

One argument in favor of CCU fuels has always been that they allow for easier storage and transportation over long distances than hydrogen. The very high cyclic energy losses they incur could therefore be seen as the efficiency cost of ease of long-term (seasonal) storage and of long-distance transportation. Having said that, since hydrogen for transportation purposes can largely be produced on-site at the fuelling station if the required carbon-free renewable electricity is available, (73) the ease of transportation argument for liquid fuels may not hold in every case. Finally, another important consideration on the use of synthetic fuels for seasonal power storage combined with propulsion services is the following: it would be more efficient to store renewable power using power–methane–power and let vehicles drive using the electricity generated in this way, which would yield a 22% cyclic system efficiency (assuming a charger to wheel efficiency of 77.2%, based on literature data (56,57)), than to use CCU fuels or ammonia to power vehicles directly (9–13% cyclic efficiency).

4.3. Analysis of Efficiency Improvement Potential by Exergy Analysis

Exergy analysis, for example, through determining the second-law efficiencies of eq 5, can be applied to identify unit operations in a production process, where exergy is lost, and thus to focus the attention on system elements that offer the largest opportunities for improvement. (63,74) A second-law efficiency of 100% refers to a perfectly reversible process, such as a Carnot cycle, that does not incur any loss of available work (i.e., of exergy).

The efficiencies presented so far were defined in terms of calorific value of the fuels (LHV) and of electricity. Heat streams have been converted to the calorific value of the fuel that is burned in a boiler to generate the heat or to electricity via a subcritical steam cycle. The exergy analysis uses specific exergy instead of calorific value and converts heat demands to exergy by applying a Carnot cycle efficiency at the corresponding temperature. Electricity is 100% recoverable work and does not have to be converted.

For the air separation unit (ASU), for DAC, and for the GTCC with CO₂ capture, only an exergy analysis allows one to account for the nonenergetic but purified product species, namely, CO₂ and N₂, by considering their chemical and thermomechanical exergy (74) (for details of the calculation, see Section 3.5 and the Supporting Information). For electrolysis and fuel synthesis, however, the energy efficiencies reported in Figures 2 and 3 are dominated by electric energy and the calorific value of the fuels. While the second-law efficiencies presented in Figure 6 consider the exergy of educts and products instead of their calorific value, the results do not differ significantly, because the specific exergy of fuels is largely defined by their calorific value. Nevertheless, the second-law efficiency of 70% for the electrolysis confirms that there is still potential for improvement of the energetic performance, besides the current efforts to improve flexibility and ramping. All three fuel synthesis steps exhibit second-law efficiencies of around 90%, which is due to a high efficiency in converting the chemical exergy of H₂ into chemical exergy of the synthetic fuels, assuming nearly stoichiometric reactions, and due to the fact that all reactions are performed at significant pressure and temperature; thus, the heat released from the exothermic reactions can be used effectively to generate steam that then serves internal demands or provides electricity.

Figure 6. Comparison of the second-law efficiency of each system block and of its contribution to the efficiency loss for the power–fuel–power systems. The graph shows that the synthesis step of the synthetic fuels is already highly efficient, as shown by the high second-law efficiency. Fuel synthesis however has only a small impact on the cyclic efficiency loss over the overall system. Electrolysis and fuel combustion in a GTCC (with or without CCS) contribute much more to the overall cyclic efficiency loss, and they still exhibit quite some room for efficiency improvement, especially fuel combustion. DAC shows the highest potential for second-law improvement but has the lowest contribution to the cyclic efficiency loss.

The second-law efficiencies of the final energy conversion units and of the DAC/ASU units are relatively low. For power plants that involve combustion, such low efficiencies are commonly known and to a large extent related to the inability of exploiting the high combustion temperatures effectively and to the resulting exergy losses associated with the hot flue gas. The low exergetic efficiency of cryogenic air separation is also confirmed in the literature, (64) whereas the DAC unit performs comparatively well under the current assumptions.

4.4. Discussion

To assess the robustness of the results obtained in terms of efficiency in the use of renewable electricity, we have performed a local sensitivity analysis on the key input parameters. These were varied in an interval defined by lower and upper bounds, selected specifically for each input parameter to provide an evaluation of what realistic performance ranges are. For some parameters, vendor indications of performance were used, and for others, measured or modeled scientific data were used. For the fuel synthesis steps and electrolysis, the maximum theoretical efficiency was selected for the upper values. For methane conversion to power, we selected as lower and upper bounds other technologies than GTCC with CCS, i.e., open cycle gas turbine with CCS and a natural gas fuel cell system with CCS. Further assumptions and the parameter ranges are indicated in Figure 7 and explained and justified in Section 3.6.

Figure 7. Sensitivity of net system efficiency to changes in electrolysis, DAC/ASU, fuel synthesis, and fuel conversion. The second column from the left indicates how the input parameters were varied, represented on a 0–100% scale where possible. The resulting range of chain efficiencies is reported on the right with the middle line representing the base case. The input parameter assumptions are given as efficiency for electrolysis and final conversion and as an energy requirement for DAC/ASU. For fuel synthesis, see the corresponding text.

Figure 7a shows the results of varying the input parameters on net cycle efficiency of the power–fuel–power cycles. It is immediately apparent that the comparative ranking of the technologies remains the same, no matter which type of parameter is varied. This means that hydrogen remains the most efficient, followed by ammonia, methane, and methanol. It is also clear that all technologies exhibit rather large ranges of possible efficiencies due to the uncertainty in the performance of electrolysis and final fuel conversion steps. This means there is potential for improvement for each of the systems if and when high efficiency electrolysis and final fuel conversion are brought to the market, but it similarly means that, when legacy systems with lower efficiency are used, the chain efficiency will be low. For electrolysis, it means that the high efficiencies quoted by vendors should also be reached during flexible operation and not only during optimal steady state conditions. The figure also shows that improvements in DAC/ASU and fuel synthesis have a significantly smaller effect on the chain efficiency: the former due to its small contribution to the overall efficiency loss (see also Figure 6) and the latter due to its already high exergy efficiency (Figure 6). It is worth noting that the high end of the sensitivity shown for the synthesis reaction represents a highly idealized situation, assuming not only perfect exergy efficiency and ideal reaction stoichiometry but also 100% CO₂ capture within the synthesis step (and the inherent secondary effect of lower DAC demands). This indicates that, for the efficiency improvement of net-zero-CO₂-emission capture CCU fuel, hydrogen, or ammonia systems, the focus should be on improving the efficiency of electrolysis and fuel conversion, more so than on improving that of direct air capture and fuel synthesis. Figure 7a also reconfirms the potential of ammonia as a carbon-free energy carrier that, contrary to hydrogen, is liquid at moderate pressure.

For power–fuel–propulsion, the ranking of technologies also remains the same (Figure 7b), meaning that the efficiency of the hydrogen system prevails over those of ammonia, methanol, and methane. For the propulsion chains, most upside, but also downside, comes from the performance of the fuel conversion step, meaning that high efficiency technologies for the final conversion (be it ICE or FC or other) should receive research priority when developing synthetic chemical energy carriers for transportation purposes. Especially, the development and commercialization of methanol (e.g., direct methanol fuel cells) (33,34) and ammonia (e.g., high-pressure ratio ammonia engines) (70) conversion technologies could contribute to improve the efficiency of liquid chemical energy carrier chains, even though this will not yet close the gap with hydrogen.

5. Conclusions

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This work has analyzed technologies for the seasonal storage of renewable electricity (RE) in synthetic fuels, either carbon-based (methane and methanol) or carbon free (hydrogen and ammonia), under the strong constraint that all technology chains investigated yield net-zero-CO₂ emissions.

As a first result, this net-zero-CO₂-emissions framework has allowed one to identify relevant requirements on the technological characteristics enabling net-zero CCU fuel systems. First, these systems need CO₂ removal technologies to remove residual CO₂ emissions from the air. Second, they require zero-CO₂ hydrogen production. Third, net-zero-emission power–CCU fuel–power systems need intermittent storage not only of hydrogen but also of CO₂ and/or synthetic fuel to overcome periods without sufficient RE generation, thus implying that major geological storage facilities shall be in place.

We conclude that the efficiency cost of facilitating long-term storage and long-range transport of RE by means of synthetic fuels is high to very high: power–fuel–power chains lose between 60% of the original RE in the case of hydrogen to more than two-thirds in the other three cases. Power–fuel–propulsion chains lose between two-thirds in the case of hydrogen to about 90% in the other three cases.

Using exergy analysis and sensitivity analysis, we have demonstrated that the potential for efficiency improvement is the highest for technologies that separate carbon dioxide or nitrogen from air which, however, have a small effect on the overall system efficiency. The efficiency improvement potential is the lowest for the methane, methanol, and ammonia synthesis technologies. Moreover, there is still improvement potential for hydrogen production by electrolysis and for the final fuel-to-power (with CO₂ capture in the case of carbon-based synthetic fuels) and fuel-to-propulsion steps, which have a large effect on the overall system efficiency. These observations are relevant as they may lead to a prioritization of research and innovation needs, more specifically less in favor of methane, methanol, and ammonia synthesis and more in favor of electrolysis for renewable hydrogen production and of final fuel conversion for both power generation and propulsion. The analyses in this paper thus show clear shortcomings in terms of efficiency in the use of RE of the CCU fuels (and to a lesser extent of ammonia). This implies that other advantages (infrastructure-related, economic, environmental, related to safety and public perception) of CCU fuels over carbon-free alternatives need to be rather significant to make them competitive. From a systems perspective, this may mean that these fuels may only be used in applications where they are really needed and where alternatives cannot fulfill the same function, such as air travel, for example.

The net-zero-carbon framework applied in this paper shows those things clearly, and we believe it is therefore very useful to generate a first important level of understanding of the potential of CCU fuels in their context. The simplification of the net-zero-CO₂-emission constraint may seem trivial or logical, but it does change and simplifies the discussion significantly by avoiding a very obvious question (how much CO₂ does a CCU fuel really mitigate?). Furthermore, it allows one to compare CO₂-based and CO₂-free synthetic fuels in a quantitative manner under the same zero-carbon footprint constraint.

Supporting Information

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The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.iecr.9b00880.

Additional remarks about the second-law efficiency analysis; waterfall diagrams of the power–methanol–power, power–ammonia–power, power–methane–propulsion, and power–ammonia–propulsion systems (PDF)

ie9b00880_si_001.pdf (167.86 kb)

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Author Information

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Corresponding Author
- Marco Mazzotti - Institute of Process Engineering, ETH Zurich, Sonneggstrasse 3, 8092 Zurich, Switzerland; http://orcid.org/0000-0002-4948-6705; Email: [email protected]
Authors
- Daniel Sutter - Institute of Process Engineering, ETH Zurich, Sonneggstrasse 3, 8092 Zurich, Switzerland
- Mijndert van der Spek - Institute of Process Engineering, ETH Zurich, Sonneggstrasse 3, 8092 Zurich, Switzerland; http://orcid.org/0000-0002-3365-2289
Notes
The authors declare no competing financial interest.

Abbreviations

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ASU	air separation unit
BECC	bioenergy and CO₂ capture
CCS	CO₂ capture and storage
CCU	CO₂ capture and utilization
CNG	compressed natural gas
DAC	direct air capture (of CO₂)
DACCS	direct air capture and CO₂ storage
DMFC	direct methanol fuel cell
GTCC	gas turbine combined cycle
ICE	internal combustion engine
LCA	life cycle analysis
LHV	lower heating value
MeOH	methanol
OCGT	open cycle gas turbine
PCC	postcombustion capture (of CO₂)
PEM	polymer electrolyte membrane
PEMFC	polymer electrolyte membrane fuel cell
RE	renewable electricity
SOFC	solid oxide fuel cell

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The purpose of this paper is to assess via techno-economic and environmental metrics the prodn. of methanol (MeOH) using H2 and captured CO2 as raw materials. It evaluates the potential of this type of carbon capture and utilization (CCU) plant on (i) the net redn. of CO2 emissions and (ii) the cost of prodn., in comparison with the conventional synthesis process of MeOH Europe. Process flow modeling is used to est. the operational performance and the total purchased equipment cost; the flowsheet is implemented in CHEMCAD, and the obtained mass and energy flows are utilized as input to calc. the selected key performance indicators (KPIs). CO2-based metrics are used to assess the environmental impact. The evaluated MeOH plant produces 440 ktMeOH/yr, and its configuration is the result of a heat integration process. Its specific capital cost is lower than for conventional plants. However, raw materials prices, i.e. H2 and captured CO2, do not allow such a project to be financially viable. In order to make the CCU plant financially attractive, the price of MeOH should increase in a factor of almost 2, or H2 costs should decrease almost 2.5 times, or CO2 should have a value of around 222 euro/t, under the assumptions of this work. The MeOH CCU-plant studied can utilize about 21.5% of the CO2 emissions of a pulverised coal (PC) power plant that produces 550 MWnet of electricity. The net CO2 emissions savings represent 8% of the emissions of the PC plant (mainly due to the avoidance of consuming fossil fuels as in the conventional MeOH synthesis process). The results demonstrate that there is a net but small potential for CO2 emissions redn.; assuming that such CCU plants are constructed in Europe to meet the MeOH demand growth and the quantities that are currently imported, the net CO2 emissions redn. could be of 2.71 MtCO2/yr.
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Akhil, A. A.; Huff, G.; Currier, A. B.; Kaun, B. C.; Rastler, D. M.; Chen, S. B.; Cotter, A. L.; Bradshaw, D. T.; Gauntlett, W. D. DOE/EPRI 2013 Electricity Storage Handbook in Collaboration with NRECA; SAND2013-5131; Sandia National Laboratories: Albuquerque, 2013; https://www.energy.gov/sites/prod/files/2013/08/f2/ElecStorageHndbk2013.pdf.
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Argyrou, M. C.; Christodoulides, P.; Kalogirou, S. A. Energy Storage for Electricity Generation and Related Processes: Technologies Appraisal and Grid Scale Applications. Renewable Sustainable Energy Rev. 2018, 94 (May), 804– 821, DOI: 10.1016/j.rser.2018.06.044
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Schüth, F. Chemical Compounds for Energy Storage. Chem. Ing. Tech. 2011, 83 (11), 1984– 1993, DOI: 10.1002/cite.201100147
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Chemical Compounds for Energy Storage
Schueth, Ferdi
Chemie Ingenieur Technik (2011), 83 (11), 1984-1993CODEN: CITEAH; ISSN:0009-286X. (Wiley-VCH Verlag GmbH & Co. KGaA)
A review. Future energy systems, which will rely on substantially higher contributions from regenerative supply pathways and which will be increasingly less dependent on fossil energy resources, will require high energy d. storage compds. as strategic reserves and for seasonal storage. Hydrocarbons, such as oil and natural gas, are currently serving this purpose. These will also be options in future systems, but in that case, these compds. would have to be synthesized using some other form of energy. Thus, with decreasing importance of fossil resources, other storage compds. also seem to be viable, the most prominent ones under discussion, in addn. to the ones mentioned, being hydrogen, methanol, and ethanol. In this contribution, the different storage compds. will be discussed, and their merits and drawbacks for large scale implementation will be compared.
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Mac Dowell, N.; Fennell, P. S.; Shah, N.; Maitland, G. C. The Role of CO2 Capture and Utilization in Mitigating Climate Change. Nat. Clim. Change 2017, 7, 243, DOI: 10.1038/nclimate3231
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10
Dahl, S.; Chorkendorff, I. Solar-Fuel Generation: Towards Practical Implementation. Nat. Mater. 2012, 11 (2), 100– 101, DOI: 10.1038/nmat3233
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Solar-fuel generation. Towards practical implementation
Dahl, Soren; Chorkendorff, Ib
Nature Materials (2012), 11 (2), 100-101CODEN: NMAACR; ISSN:1476-1122. (Nature Publishing Group)
A review. Limiting reliance on nonrenewable fossil fuels inevitably depends on a more efficient utilization of solar energy. The most viable approaches to produce high-energy-d. fuels from sunlight that can be implemented in existing infrastructures are discussed.
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Schakel, W.; Oreggioni, G.; Singh, B.; Strømman, A.; Ramírez, A. Assessing the Techno-Environmental Performance of CO2 Utilization via Dry Reforming of Methane for the Production of Dimethyl Ether. J. CO2 Util. 2016, 16, 138– 149, DOI: 10.1016/j.jcou.2016.06.005
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11
Assessing the techno-environmental performance of CO2 utilization via dry reforming of methane for the production of dimethyl ether
Schakel, Wouter; Oreggioni, Gabriel; Singh, Bhawna; Stroemman, Anders; Ramirez, Andrea
Journal of CO2 Utilization (2016), 16 (), 138-149CODEN: JCUOAJ; ISSN:2212-9839. (Elsevier Ltd.)
CO2 utilization is gaining attention as a greenhouse gas abatement strategy complementary to CO2 storage. This study explores the techno-environmental performance of CO2 utilization trough dry reforming of methane into syngas for the prodn. of di-Me ether (DME). The CO2 source is a hydrogen prodn. unit at a refinery, where solvent based CO2 capture is applied. Aspen+ modeling and hybrid life cycle assessment (LCA) is used to assess the techno-environmental performance of this utilization option compared to a ref. case without CO2 capture and a case with CO2 capture and storage. Results of the tech. assessment show that although 94% of the captured CO2 can be utilized for DME prodn., only 9% of CO2 is avoided in the entire process as a result of direct CO2 formation during DME synthesis and the combustion of syngas to provide the heat demanded by the dry reforming process. Besides, a substantial amt. of electricity is required for syngas compression. Consequently, the LCA results indicate that climate change potential (CCP) is reduced by 8% while it is 37% higher than CCP when CO2 is stored and DME is produced conventionally. Sensitivity analyses are performed on various process conditions. Overall, this study indicates that this utilization route lowers the CCP although the redn. is limited compared to CCS. While the techno-environmental anal. is a useful tool to gain better insights in the performance of CO2 utilization options, the complex environmental trade-offs make it difficult to draw robust conclusions on the performance.
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Zhang, X.; Bauer, C.; Mutel, C. L.; Volkart, K. Life Cycle Assessment of Power-to-Gas: Approaches, System Variations and Their Environmental Implications. Appl. Energy 2017, 190, 326– 338, DOI: 10.1016/j.apenergy.2016.12.098
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Life Cycle Assessment of Power-to-Gas: Approaches, system variations and their environmental implications
Zhang, Xiaojin; Bauer, Christian; Mutel, Christopher L.; Volkart, Kathrin
Applied Energy (2017), 190 (), 326-338CODEN: APENDX; ISSN:0306-2619. (Elsevier Ltd.)
Electricity generation from intermittent renewable sources is expected to increase rapidly in the next decades. Integrating renewable energy requires energy storage during low-demand periods and potential conversion of surplus electricity into other energy carriers. Power-to-Gas (P2G) is a promising technol. due to its potential to provide large-scale and long-term energy storage. However, this technol. has many system variations, and their environmental performances need to be evaluated and compared with conventional technologies before large-scale deployment. In this paper, we investigate the environmental performance of P2G using Life Cycle Assessment (LCA), and mainly focus on the following three aspects: (1) discussion of differences as consequence of the approach applied for CO2 Capture and Utilization (CCU); (2) evaluation of technol. variations including supply of electricity, alternative system processes (electrolysis technologies and CO2 sources), product gases (hydrogen and methane), and comparison of these P2G systems with conventional technologies, and (3) investigation of further environmental impacts of P2G in addn. to the impact of global warming potential. We argue that in case of P2M, system expansion provides more meaningful results than subdivision for CCU, since it reflects the added value of CO2 utilization providing electricity or cement with low GHG intensity. The results of system variations show that P2G can, depending on electricity supply and CO2 source, reduce GHG emission compared to conventional gas prodn. technologies, and that P2H has higher potential of emission redn. than P2M. Concerning other impact categories, P2H can have lower impacts than conventional hydrogen prodn., while P2M most often has higher impacts than using conventional natural gas.
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van der Giesen, C.; Kleijn, R.; Kramer, G. J. Energy and Climate Impacts of Producing Synthetic Hydrocarbon Fuels from CO2. Environ. Sci. Technol. 2014, 48 (12), 7111– 7121, DOI: 10.1021/es500191g
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Energy and climate impacts of producing synthetic hydrocarbon fuels from carbon dioxide
van der Giesen, Coen; Kleijn, Rene; Kramer, Gert Jan
Environmental Science & Technology (2014), 48 (12), 7111-7121CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
A review. Within the context of carbon dioxide (CO2) utilization there is an increasing interest in using CO2 as a resource to produce sustainable liq. hydrocarbon fuels. When these fuels are produced by solely using solar energy they are labeled as solar fuels. In the recent discourse on solar fuels intuitive arguments are used to support the prospects of these fuels. This paper takes a quant. approach to investigate some of the claims made in this discussion. We analyze the life cycle performance of various classes of solar fuel processes using different primary energy and CO2 sources. We compare their efficacy with respect to carbon mitigation with ubiquitous fossil-based fuels and conclude that producing liq. hydrocarbon fuels starting from CO2 by using existing technologies requires much more energy than existing fuels. An improvement in life cycle CO2 emissions is only found when solar energy and atm. CO2 are used. Producing fuels from CO2 is a very long-term niche at best, not the panacea suggested in the recent public discourse.
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Fernández-Dacosta, C.; Van Der Spek, M.; Hung, C. R.; Oregionni, G. D.; Skagestad, R.; Parihar, P.; Gokak, D. T.; Strømman, A. H.; Ramirez, A. Prospective Techno-Economic and Environmental Assessment of Carbon Capture at a Refinery and CO2 Utilisation in Polyol Synthesis. J. CO2 Util. 2017, 21, 405– 422, DOI: 10.1016/j.jcou.2017.08.005
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Prospective techno-economic and environmental assessment of carbon capture at a refinery and CO2 utilisation in polyol synthesis
Fernandez-Dacosta, Cora; van der Spek, Mijndert; Hung, Christine Roxanne; Oregionni, Gabriel David; Skagestad, Ragnhild; Parihar, Prashant; Gokak, D. T.; Stroemman, Anders Hammer; Ramirez, Andrea
Journal of CO2 Utilization (2017), 21 (), 405-422CODEN: JCUOAJ; ISSN:2212-9839. (Elsevier Ltd.)
CO2 utilization is gaining interest as a potential element towards a sustainable economy. CO2 can be used as feedstock in the synthesis of fuels, chems. and polymers. This study presents a prospective assessment of carbon capture from a hydrogen unit at a refinery, where the CO2 is either stored, or partly stored and partly utilized for polyols prodn. A methodol. integrating tech., economic and environmental models with uncertainty anal. is used to assess the performance of carbon capture and storage or utilization at the refinery. Results show that only 10% of the CO2 captured from an industrial hydrogen unit can be utilized in a com.-scale polyol plant. This option has limited potential for large scale CO2 mitigation from industrial sources. However, CO2 capture from a hydrogen unit and its utilization for the synthesis of polyols provides an interesting alternative from an economic perspective. The costs of CO2-based polyol are estd. at 1200 euro/t polyol, 16% lower than those of conventional polyol. Furthermore, the costs of storing the remaining CO2 are offset by the benefits of cheaper polyol prodn. Therefore, the combination of CO2 capture and partial utilization provides an improved business case over capture and storage alone. The environmental assessment shows that the climate change potential of this CO2 utilization system is 23% lower compared to a ref. case in which no CO2 is captured at the refinery. Five other environmental impact categories included in this study present slightly better performance for the utilization case than for the ref. case.
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Dimitriou, I.; García-Gutiérrez, P.; Elder, R. H.; Cuéllar-Franca, R. M.; Azapagic, A.; Allen, R. W. K. Carbon Dioxide Utilisation for Production of Transport Fuels: Process and Economic Analysis. Energy Environ. Sci. 2015, 8 (6), 1775– 1789, DOI: 10.1039/C4EE04117H
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Carbon dioxide utilisation for production of transport fuels: process and economic analysis
Dimitriou, Ioanna; Garcia-Gutierrez, Pelayo; Elder, Rachael H.; Cuellar-Franca, Rosa M.; Azapagic, Adisa; Allen, Ray W. K.
Energy & Environmental Science (2015), 8 (6), 1775-1789CODEN: EESNBY; ISSN:1754-5706. (Royal Society of Chemistry)
Utilizing CO2 as a feedstock for chems. and fuels could help mitigate climate change and reduce dependence on fossil fuels. For this reason, there is an increasing world-wide interest in carbon capture and utilization (CCU). As part of a broader project to identify key tech. advances required for sustainable CCU, this work considers different process designs, each at a high level of technol. readiness and suitable for large-scale conversion of CO2 into liq. hydrocarbon fuels, using biogas from sewage sludge as a source of CO2. The main objective of the paper is to est. fuel prodn. yields and costs of different CCU process configurations in order to establish whether the prodn. of hydrocarbon fuels from com. proven technologies is economically viable. Four process concepts are examd., developed and modelled using the process simulation software Aspen Plus to det. raw materials, energy and utility requirements. Three design cases are based on typical biogas applications: (1) biogas upgrading using a monoethanolamine (MEA) unit to remove CO2, (2) combustion of raw biogas in a combined heat and power (CHP) plant and (3) combustion of upgraded biogas in a CHP plant which represents a combination of the first two options. The fourth case examines a post-combustion CO2 capture and utilization system where the CO2 removal unit is placed right after the CHP plant to remove the excess air with the aim of improving the energy efficiency of the plant. All four concepts include conversion of CO2 to CO via a reverse water-gas-shift reaction process and subsequent conversion to diesel and gasoline via Fischer-Tropsch synthesis. The studied CCU options are compared in terms of liq. fuel yields, energy requirements, energy efficiencies, capital investment and prodn. costs. The overall plant energy efficiency and prodn. costs range from 12-17% and £15.8-29.6 per L of liq. fuels, resp. A sensitivity anal. is also carried out to examine the effect of different economic and tech. parameters on the prodn. costs of liq. fuels. The results indicate that the prodn. of liq. hydrocarbon fuels using the existing CCU technol. is not economically feasible mainly because of the low CO2 sepn. and conversion efficiencies as well as the high energy requirements. Therefore, future research in this area should aim at developing novel CCU technologies which should primarily focus on optimizing the CO2 conversion rate and minimising the energy consumption of the plant.
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Schlögl, R.; Abanades, C.; Aresta, M.; Azapagic, A.; Blekkan, E. A.; Cantat, T.; Centi, G.; Duic, N.; El Khamlichi, A.; Hutchings, G.; Mazzotti, M.; Olsbye, U.; Mikulcic, H. Novel Carbon Capture and Utilisation Technologies. Research and Climate Impacts; SAPEA: Brussels, 2018; DOI: 10.26356/CARBONCAPTURE .
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Walsh, B.; Ciais, P.; Janssens, I. A.; Peñuelas, J.; Riahi, K.; Rydzak, F.; Van Vuuren, D. P.; Obersteiner, M. Pathways for Balancing CO2 Emissions and Sinks. Nat. Commun. 2017, 8, 14856, DOI: 10.1038/ncomms14856
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Pathways for balancing CO2 emissions and sinks
Walsh, Brian; Ciais, Philippe; Janssens, Ivan A.; Penuelas, Josep; Riahi, Keywan; Rydzak, Felicjan; van Vuuren, Detlef P.; Obersteiner, Michael
Nature Communications (2017), 8 (), 14856CODEN: NCAOBW; ISSN:2041-1723. (Nature Publishing Group)
In Dec. 2015 in Paris, leaders committed to achieve global, net decarbonization of human activities before 2100. This achievement would halt and even reverse anthropogenic climate change through the net removal of carbon from the atm. However, the Paris documents contain few specific prescriptions for emissions mitigation, leaving various countries to pursue their own agendas. In this anal., we project energy and land-use emissions mitigation pathways through 2100, subject to best-available parameterization of carbon-climate feedbacks and interdependencies. We find that, barring unforeseen and transformative technol. advancement, anthropogenic emissions need to peak within the next 10 years, to maintain realistic pathways to meeting the COP21 emissions and warming targets. Fossil fuel consumption will probably need to be reduced below a quarter of primary energy supply by 2100 and the allowable consumption rate drops even further if neg. emissions technologies remain technol. or economically unfeasible at the global scale.
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van Soest, H. L.; de Boer, H. S.; Roelfsema, M.; den Elzen, M. G. J.; Admiraal, A.; van Vuuren, D. P.; Hof, A. F.; van den Berg, M.; Harmsen, M. J. H. M.; Gernaat, D. E. H. J.; Forsell, N. Early Action on Paris Agreement Allows for More Time to Change Energy Systems. Clim. Change 2017, 144 (2), 165– 179, DOI: 10.1007/s10584-017-2027-8
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Early action on Paris Agreement allows for more time to change energy systems
van Soest, Heleen L.; Sytze de Boer, Harmen; Roelfsema, Mark; den Elzen, Michel G. J.; Admiraal, Annemiek; van Vuuren, Detlef P.; Hof, Andries F.; van den Berg, Maarten; Harmsen, Mathijs J. H. M.; Gernaat, David E. H. J.; Forsell, Nicklas
Climatic Change (2017), 144 (2), 165-179CODEN: CLCHDX; ISSN:0165-0009. (Springer)
The IMAGE integrated assessment model was used to develop a set of scenarios to evaluate the Nationally Detd. Contributions (NDCs) submitted by Parties under the Paris Agreement. The scenarios project emissions and energy system changes under (i) current policies, (ii) implementation of the NDCs, and (iii) various trajectories to a radiative forcing level of 2.8 W/m2 in 2100, which gives a probability of about two thirds to limit warming to below 2 °C. The scenarios show that a cost-optimal pathway from 2020 onwards towards 2.8 W/m2 leads to a global greenhouse gas emission level of 38 gigatonne CO2 equivalent (GtCO2eq) by 2030, equal to a redn. of 20% compared to the 2010 level. The NDCs are projected to lead to 2030 emission levels of 50 GtCO2eq, which is still an increase compared to the 2010 level. A scenario that achieves the 2.8 W/m2 forcing level in 2100 from the 2030 NDC level requires more rapid transitions after 2030 to meet the forcing target. It shows an annual redn. rate in greenhouse gas emissions of 4.7% between 2030 and 2050, rapidly phasing out unabated coal-fired power plant capacity, more rapid scale-up of low-carbon energy, and higher mitigation costs. A bridge scenario shows that enhancing the ambition level of NDCs before 2030 allows for a smoother energy system transition, with av. annual emission redn. rates of 4.5% between 2030 and 2050, and more time to phase out coal capacity.
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Millar, R. J.; Fuglestvedt, J. S.; Friedlingstein, P.; Rogelj, J.; Grubb, M. J.; Matthews, H. D.; Skeie, R. B.; Forster, P. M.; Frame, D. J.; Allen, M. R. Emission Budgets and Pathways Consistent with Limiting Warming to 1.5 °C. Nat. Geosci. 2017, 10, 741– 748, DOI: 10.1038/ngeo3031
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Emission budgets and pathways consistent with limiting warming to 1.5°C
Millar, Richard J.; Fuglestvedt, Jan S.; Friedlingstein, Pierre; Rogelj, Joeri; Grubb, Michael J.; Matthews, H. Damon; Skeie, Ragnhild B.; Forster, Piers M.; Frame, David J.; Allen, Myles R.
Nature Geoscience (2017), 10 (10), 741-747CODEN: NGAEBU; ISSN:1752-0894. (Nature Research)
The Paris Agreement has opened debate on whether limiting warming to 1.5°C is compatible with current emission pledges and warming of about 0.9°C from the mid-nineteenth century to the present decade. We show that limiting cumulative post-2015 CO2 emissions to about 200 GtC would limit post-2015 warming to less than 0.6°C in 66% of Earth system model members of the CMIP5 ensemble with no mitigation of other climate drivers, increasing to 240 GtC with ambitious non-CO2 mitigation. Assuming emissions peak and decline to below current levels by 2030, and continue thereafter on a much steeper decline, which would be historically unprecedented but consistent with a std. ambitious mitigation scenario (RCP2.6), results in a likely range of peak warming of 1.2-2.0°C above the mid-nineteenth century. If CO2 emissions are continuously adjusted over time to limit 2100 warming to 1.5°C, with ambitious non-CO2 mitigation, net future cumulative CO2 emissions are unlikely to prove less than 250 GtC and unlikely greater than 540 GtC. Hence, limiting warming to 1.5°C is not yet a geophys. impossibility, but is likely to require delivery on strengthened pledges for 2030 followed by challengingly deep and rapid mitigation. Strengthening near-term emissions redns. would hedge against a high climate response or subsequent redn. rates proving economically, tech. or politically unfeasible.
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IPCC. Summary for Policy Makers. In Climate change 2014: Synthesis Report. Contribution of Working Groups I, II and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change; Pachauri, R. K., Meyer, L. A., Eds.; IPCC: Geneva, Switzerland, 2014; p 151.
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Davis, S. J.; Lewis, N. S.; Shaner, M.; Aggarwal, S.; Arent, D.; Azevedo, I. L.; Benson, S. M.; Bradley, T.; Brouwer, J.; Chiang, Y.-M.; Clack, C. T. M.; Cohen, A.; Doig, S.; Edmonds, J.; Fennell, P.; Field, C. B.; Hannegan, B.; Hodge, B.-M.; Hoffert, M. I.; Ingersoll, E.; Jaramillo, P.; Lackner, K. S.; Mach, K. J.; Mastrandrea, M.; Ogden, J.; Peterson, F.; Sanchez, D. L.; Sperling, D.; Stagner, J.; Trancik, J. E.; Yang, C. J.; Caldeira, K. Net-Zero Emissions Energy Systems. Science 2018, 360 (6396), eaas9793, DOI: 10.1126/science.aas9793
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IPCC. Summary for Policymakers. In Global warming of 1.5°C. An IPCC Special Report on the impacts of global warming of 1.5°C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change; Masson-Delmotte, V., Zhai, P., Pörtner, H. O., Roberts, D., Skea, J., Shukla, P.R., Pirani, A., Moufouma-Okia, W., Péan, C., Pidcock, R., Connors, S., Matthews, J. B. R., Chen, Y., Zhou, X., Gomis, M. I., Lonnoy, E., Maycock, T., Tignor, M., W, T., Eds.; IPCC: Geneva, Switzerland, 2018; p 32.
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van der Spek, M.; Sutter, D.; Antonini, C.; Mazzotti, M. The Role of Direct Air Capture and Bioenergy in Net Zero CCU Fuel Loops. In International Conference on Negative CO2 Emissions , May 22–24, 2018, Göteborg, Sweden; pp 1– 7.
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Sternberg, A.; Jens, C. M.; Bardow, A. Life Cycle Assessment of CO2-Based C1-Chemicals. Green Chem. 2017, 19, 2244– 2259, DOI: 10.1039/C6GC02852G
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Life cycle assessment of CO2-based C1-chemicals
Sternberg, Andre; Jens, Christian M.; Bardow, Andre
Green Chemistry (2017), 19 (9), 2244-2259CODEN: GRCHFJ; ISSN:1463-9262. (Royal Society of Chemistry)
Carbon dioxide (CO2) and hydrogen are promising feedstocks for a sustainable chem. industry. Currently, the conversions of CO2 and hydrogen are most advanced for chems. with 1 carbon atom, the so-called C1-chems., with the first pilot plants in operation. For formic acid, carbon monoxide, methanol, and methane, CO2-based C1-chems. can reduce the impacts of fossil depletion and global warming through the substitution of fossil-based processes. Existing life cycle assessment (LCA) studies for carbon monoxide, methanol, and methane show that a redn. in environmental impacts is achieved if hydrogen is supplied by water electrolysis with renewable electricity. However, in the foreseeable future, renewable electricity will be limited. Thus, from an environmental point of view, renewable electricity should be employed for chem. processes in the order of highest environmental impact redns. Environmental impact redns. are the difference in environmental impacts of fossil-based processes and CO2-based processes. In this study, we compared the CO2-based prodn. of formic acid, carbon monoxide, methanol, and methane. We detd. the redn. of global warming and fossil depletion impacts using 1 kg of hydrogen. Our results show that the CO2-based prodn. of formic acid achieves the highest environmental impact redns., followed by carbon monoxide and methanol. The lowest environmental impact redns. are achieved for CO2-based methane prodn. Our anal. reveals that the CO2-based prodn. of formic acid can reduce environmental impacts, compared to the fossil-based process, even if hydrogen is supplied by fossil-based steam-methane-reforming.
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Schüth, F.; Palkovits, R.; Schlögl, R.; Su, D. S. Ammonia as a Possible Element in an Energy Infrastructure: Catalysts for Ammonia Decomposition. Energy Environ. Sci. 2012, 5 (4), 6278– 6289, DOI: 10.1039/C2EE02865D
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Ammonia as a possible element in an energy infrastructure: catalysts for ammonia decomposition
Schueth, F.; Palkovits, R.; Schloegl, R.; Su, D. S.
Energy & Environmental Science (2012), 5 (4), 6278-6289CODEN: EESNBY; ISSN:1754-5706. (Royal Society of Chemistry)
A review. The possible role of ammonia in a future energy infrastructure is discussed. The review is focused on the catalytic decompn. of ammonia as a key step. Other aspects, such as the catalytic removal of ammonia from gasification product gas or direct ammonia fuel cells, are highlighted as well. The more general question of the integration of ammonia in an infrastructure is also covered.
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26
Grinberg Dana, A.; Elishav, O.; Bardow, A.; Shter, G. E.; Grader, G. S. Nitrogen-Based Fuels: A Power-to-Fuel-to-Power Analysis. Angew. Chem., Int. Ed. 2016, 55 (31), 8798– 8805, DOI: 10.1002/anie.201510618
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Nitrogen-Based Fuels: A Power-to-Fuel-to-Power Analysis
Grinberg Dana, Alon; Elishav, Oren; Bardow, Andre; Shter, Gennady E.; Grader, Gideon S.
Angewandte Chemie, International Edition (2016), 55 (31), 8798-8805CODEN: ACIEF5; ISSN:1433-7851. (Wiley-VCH Verlag GmbH & Co. KGaA)
This paper discussed about nitrogen-based fuels and power-to-fuel-to-power anal.
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27
Götz, M.; Lefebvre, J.; Mörs, F.; McDaniel Koch, A.; Graf, F.; Bajohr, S.; Reimert, R.; Kolb, T. Renewable Power-to-Gas: A Technological and Economic Review. Renew. Renewable Energy 2016, 85, 1371– 1390, DOI: 10.1016/j.renene.2015.07.066
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Sternberg, A.; Bardow, A. Life Cycle Assessment of Power-to-Gas: Syngas vs Methane. ACS Sustainable Chem. Eng. 2016, 4 (8), 4156– 4165, DOI: 10.1021/acssuschemeng.6b00644
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Life Cycle Assessment of Power-to-Gas: Syngas vs Methane
Sternberg, Andre; Bardow, Andre
ACS Sustainable Chemistry & Engineering (2016), 4 (8), 4156-4165CODEN: ASCECG; ISSN:2168-0485. (American Chemical Society)
Power-to-Gas enables the integration of renewable electricity and carbon into the chem. industry. The electricity is used to produce hydrogen, which is subsequently converted with CO2 as the renewable carbon source. The resulting products can be used as feedstock for the chem. industry replacing current fossil-based feedstock. Because the integration of renewable electricity and carbon into the chem. industry is mainly environmentally motivated, we identify the conditions under which Power-to-Gas pathways are environmentally beneficial. The conditions are expressed as environmental threshold values for electricity supply. The threshold values are derived by a comparative life cycle assessment (LCA) of Power-to-Gas pathways to fossil-based processes. We analyze Power-to-Gas pathways to synthetic natural gas (Power-to-SNG) and to syngas (Power-to-Syngas). SNG is produced by the Sabatier reaction; syngas by reverse water gas shift (rWGS) and dry reforming of methane (DRM). The threshold values for electricity supply allow us to compare the environmental benefit of Power-to-SNG and Power-to-Syngas on an equal basis: how well they utilize the currently limited renewable electricity. Syngas prodn. by the DRM process has the largest environmental potential. Both Power-to-Syngas pathways lead to larger environmental benefits than Power-to-SNG making syngas the more desirable product than methane as long as renewable electricity is limited.
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Van-Dal, E. S.; Bouallou, C. Design and Simulation of a Methanol Production Plant from CO2 Hydrogenation. J. Cleaner Prod. 2013, 57, 38– 45, DOI: 10.1016/j.jclepro.2013.06.008
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Design and simulation of a methanol production plant from CO2 hydrogenation
Van-Dal, Everton Simoes; Bouallou, Chakib
Journal of Cleaner Production (2013), 57 (), 38-45CODEN: JCROE8; ISSN:0959-6526. (Elsevier Ltd.)
There has been a large increase in anthropogenic emissions of CO2 over the past century. The use of captured CO2 can become a profitable business, in addn. to controlling CO2 concn. in the atm. A process for producing fuel grade methanol from captured CO2 is proposed in this paper. The process is designed and simulated with Aspen Plus. The CO2 is captured by chem. absorption from the flue gases of a thermal power plant. The hydrogen is produced by water electrolysis using carbon-free electricity. The methanol plant provides 36% of the thermal energy required for CO2 capture, reducing considerably the costs of the capture. The CO2 balance of the process showed that it is possible to abate 1.6 t of CO2 per tonne of methanol produced if oxygen byproduct is sold, or 1.2 t if it is not.
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33
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Rashidi, R.; Dincer, I.; Naterer, G. F.; Berg, P. Performance Evaluation of Direct Methanol Fuel Cells for Portable Applications. J. Power Sources 2009, 187 (2), 509– 516, DOI: 10.1016/j.jpowsour.2008.11.044
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Performance evaluation of direct methanol fuel cells for portable applications
Rashidi, R.; Dincer, I.; Naterer, G. F.; Berg, P.
Journal of Power Sources (2009), 187 (2), 509-516CODEN: JPSODZ; ISSN:0378-7753. (Elsevier B.V.)
This study examines the feasibility of powering a range of portable devices with a direct MeOH fuel cell (DMFC). The anal. includes a comparison between a Li-ion battery and DMFC to supply the power for a lap-top, cam-corder and a cell phone. A parametric study of the systems for an operational period of 4 years is performed. Under the assumptions made for both the Li-ion battery and DMFC system, the battery cost is lower than the DMFC during the 1st year of operation. However, by the end of 4 years of operational time, the DMFC system would cost less. The wt. and cost comparisons show that the fuel cell system occupies less space than the battery to store a higher amt. of energy. The wt. of both systems is almost identical. Finally, the CO2 emissions can be decreased by a higher exergetic efficiency of the DMFC, which leads to improved sustenance.
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International Journal of Hydrogen Energy (1988), 13 (12), 761-73CODEN: IJHEDX; ISSN:0360-3199.
A review, with 39 refs., of the background and developmental status of H and NH3 as motor vehicle fuels, NH3 and H engine design and performance, safety, H and NH3 costs, H storage as compressed ,as, metal hydride, and liq. H, and comparative properties of potential transportation fuels.
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Peters, R.; Deja, R.; Engelbracht, M.; Frank, M.; Nguyen, V. N.; Blum, L.; Stolten, D. Efficiency Analysis of a Hydrogen-Fueled Solid Oxide Fuel Cell System with Anode off-Gas Recirculation. J. Power Sources 2016, 328, 105– 113, DOI: 10.1016/j.jpowsour.2016.08.002
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Efficiency analysis of a hydrogen-fueled solid oxide fuel cell system with anode off-gas recirculation
Peters, Roland; Deja, Robert; Engelbracht, Maximilian; Frank, Matthias; Nguyen, Van Nhu; Blum, Ludger; Stolten, Detlef
Journal of Power Sources (2016), 328 (), 105-113CODEN: JPSODZ; ISSN:0378-7753. (Elsevier B.V.)
This study analyzes different H-fueled solid oxide fuel cell (SOFC) system layouts. It begins with a simple system layout without any anode off-gas recirculation, continues with a configuration equipped with off-gas recirculation, including steam condensation and then considers a layout with a dead-end anode off-gas loop. Operational parameters such as stack fuel use, as well as the recirculation rate, are modified, with the aim of achieving the highest efficiency values. Drawing on expts. and the accumulated experience of the SOFC group at the Forschungszentrum Julich, a set of operational parameters were defined and applied to the simulations. Anode off-gas recirculation, including steam condensation, improves elec. efficiency by up to 11.9 percentage-points compared to a layout without recirculation of the same stack fuel use. A system layout with a dead-end anode off-gas loop also is capable of reaching elec. efficiencies of >61%.
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U.S. Department of Energy: Office of Energy Efficiency & Renewable Energy. Comparison of Fuel Cell Technologies; U.S. Department of Energy: Office of Energy Efficiency & Renewable Energy: Washington D.C., 2016.
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Air separation and liquefaction: recent developments and prospects for the beginning of the new millennium
Castle, W. F.
International Journal of Refrigeration (2002), 25 (1), 158-172CODEN: IJRFDI; ISSN:0140-7007. (Elsevier Science Ltd.)
A review. This paper reviews modern developments in air sepn. and liquefaction and attempts in this context to suggest features that might be expected to arise in the early part of the third millennium. Recent developments in cryogenic air sepn., pressure-swing adsorption, other methods of air sepn., and process integration are described.
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Müller, B.; Müller, K.; Teichmann, D.; Arlt, W. Energiespeicherung mittels Methan und energietragenden Stoffen Ein thermodynamischer Vergleich. Chem. Ing. Tech. 2011, 83 (11), 2002– 2013, DOI: 10.1002/cite.201100113
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Energy Storage by CO2 Methanation and Energy-Providing Compounds: A Thermodynamic Comparison
Mueller, Benjamin; Mueller, Karsten; Teichmann, Daniel; Arlt, Wolfgang
Chemie Ingenieur Technik (2011), 83 (11), 2002-2013CODEN: CITEAH; ISSN:0009-286X. (Wiley-VCH Verlag GmbH & Co. KGaA)
Reconstructing current energy infrastructures dominated by fossil fuels towards a high share of renewable energy requires a drastic extension of energy storage capacities. Common storage technologies like compressed air or pumped water are either limited in capacity or have low efficiencies. A promising alternative is proposed with the use of energy carrying compds. for hydrogen storage. This route is shown to offer the possibility to combine high process chain efficiency with lossless energy storage for stationary and mobile applications. In this article, efficiencies for energy storage by methane and N-ethylcarbazole, and energy transport substances are calcd. and compared to each other.
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Colella, W. G.; James, B. D.; Moton, J. M.; Saur, G.; Ramsden, T. Techno-Economic Analysis of PEM Electrolysis for Hydrogen Production. In Electrolytic Hydrogen Production Workshop; NREL: Golden, CO, 2014.
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Koenigsmann, C.; Wong, S. S. One-Dimensional Noble Metal Electrocatalysts: A Promising Structural Paradigm for Direct Methanolfuelcells. Energy Environ. Sci. 2011, 4 (4), 1161– 1176, DOI: 10.1039/C0EE00197J
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Koenigsmann, Christopher; Wong, Stanislaus S.
Energy & Environmental Science (2011), 4 (4), 1161-1176CODEN: EESNBY; ISSN:1754-5706. (Royal Society of Chemistry)
In this perspective, the catalytic shortfalls of contemporary DMFCs are discussed in the context of the materials that are currently being employed as electrocatalysts in both the anode and cathode. In light of these shortfalls, the inherent advantages of one-dimensional (1D) nanostructures are highlighted so as to demonstrate their potential as efficient, robust, and active replacements for contemporary nanoparticulate electrocatalysts. Finally, we review in detail the recent applications of 1D nanostructured electrocatalysts as both anodes and cathodes, and explore their potentially promising results towards improving DMFC efficiency and cost-effectiveness. In the case of cathode electrocatalysts, our group has recently prepd. both 200 nm platinum nanotubes and ultrathin 2 nm platinum nanowires, which evinced two-fold and seven-fold enhancements in area specific ORR activity, resp., as compared with contemporary com. Pt nanoparticles. Similarly, the development of one-dimensional anodic electrocatalysts such as alloyed PtRu and PtCo nanowires, hierarchical Pt∼Pd nanowires, and segmented PtRu systems have yielded promising enhancements towards methanol oxidn.
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Curran, S. J.; Wagner, R. M.; Graves, R. L.; Keller, M.; Green, J. B. Well-to-Wheel Analysis of Direct and Indirect Use of Natural Gas in Passenger Vehicles. Energy 2014, 75, 194– 203, DOI: 10.1016/j.energy.2014.07.035
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NETL. Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity; NETL: Pittsburgh, PA, 2010.
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Muñoz, J.; Abánades, A.; Martínez-Val, J. M. A Conceptual Design of Solar Boiler. Sol. Energy 2009, 83 (9), 1713– 1722, DOI: 10.1016/j.solener.2009.06.009
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A conceptual design of solar boiler
Munoz, Javier; Abanades, Alberto; Martinez-Val, Jose M.
Solar Energy (2009), 83 (9), 1713-1722CODEN: SRENA4; ISSN:0038-092X. (Elsevier Ltd.)
State-of-the-art concepts for solar thermal power systems are based on parabolic trough, tower or parabolic disks either heating molten salts, mineral oil, air or generating steam. We propose in this paper, a conceptual design of a solar boiler. This concept comes from the conventional thermal power plants boiler, with the difference that the heat comes from mirrors that conc. the solar radiation on wall-type array of solar collectors, instead of coming from fuel flames and hot gases. In our preliminary performance, anal. of this innovative solar boiler applied to electricity prodn., we have found that overall efficiency of the conversion from direct solar irradn. energy to electricity is above 20%, which is comparable to the value of parabolic trough and central tower technologies. Besides that, the concept seems very robust and could overcome some drawbacks derived from pressure losses, control complexity and material thermo-mech. stress.
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Schakel, W.; Meerman, H.; Talaei, A.; Ramírez, A.; Faaij, A. Comparative Life Cycle Assessment of Biomass Co-Firing Plants with Carbon Capture and Storage. Appl. Energy 2014, 131, 441, DOI: 10.1016/j.apenergy.2014.06.045
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Comparative life cycle assessment of biomass co-firing plants with carbon capture and storage
Schakel, Wouter; Meerman, Hans; Talaei, Alireza; Ramirez, Andrea; Faaij, Andre
Applied Energy (2014), 131 (), 441-467CODEN: APENDX; ISSN:0306-2619. (Elsevier Ltd.)
Combining co-firing biomass and carbon capture and storage (CCS) in power plants offers attractive potential for net removal of carbon dioxide (CO2) from the atm. In this study, the impact of co-firing biomass (wood pellets and straw pellets) on the emission profile of power plants with carbon capture and storage has been assessed for two types of coal-fired power plants: a supercrit. pulverised coal power plant (SCPC) and an integrated gasification combined cycle plant (IGCC). Besides, comparative life cycle assessments have been performed to examine the environmental impacts of the combination of co-firing biomass and CCS. Detailed calcns. on mass balances of the inputs and outputs of the power plants illustrate the effect of the different content of pollutants in biomass on the capture unit. Life cycle assessment results reveal that 30% co-firing biomass and applying CCS net neg. CO2 emissions in the order of 67-85 g/kWh are obtained. The impact in all other environmental categories is increased by 20-200%. However, aggregation into endpoint levels shows that the decrease in CO2 emissions more than offsets the increase in the other categories. Sensitivity analyses illustrate that results are most sensitive to parameters that affect the amt. of fuel required, such as the efficiency of the power plant and assumptions regarding the supply chains of coal and biomass. Esp., assumptions regarding land use allocation and carbon debt of biomass significantly influence the environmental performance of BioCCS.
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Van Vliet, O.; Brouwer, A. S.; Kuramochi, T.; Van Den Broek, M.; Faaij, A. Energy Use, Cost and CO2 Emissions of Electric Cars. J. Power Sources 2011, 196 (4), 2298– 2310, DOI: 10.1016/j.jpowsour.2010.09.119
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Energy use, cost and CO2 emissions of electric cars
van Vliet, Oscar; Brouwer, Anne Sjoerd; Kuramochi, Takeshi; van den Broek, Machteld; Faaij, Andre
Journal of Power Sources (2011), 196 (4), 2298-2310CODEN: JPSODZ; ISSN:0378-7753. (Elsevier B.V.)
The authors examine efficiency, costs and greenhouse gas emissions of current and future elec. cars (EV), including the impact from charging EV on electricity demand and infrastructure for generation and distribution. Uncoordinated charging would increase national peak load by 7% at 30% penetration rate of EV and household peak load by 54%, which may exceed the capacity of existing electricity distribution infrastructure. At 30% penetration of EV, off-peak charging would result in a 20% higher, more stable base load and no addnl. peak load at the national level and up to 7% higher peak load at the household level. Therefore, if off-peak charging is successfully introduced, elec. driving need not require addnl. generation capacity, even in case of 100% switch to elec. vehicles. GHG emissions from elec. driving depend most on the fuel type (coal or natural gas) used in the generation of electricity for charging, and range between 0 g/km (using renewables) and 155 g/km (using electricity from an old coal-based plant). Based on the generation capacity projected for the Netherlands in 2015, electricity for EV charging would largely be generated using natural gas, emitting 35-77 g CO2eq/km. Total cost of ownership (TCO) of current EV are uncompetitive with regular cars and series hybrid cars by >800 euro/yr. TCO of future wheel motor PHEV may become competitive when batteries cost 400 euro/kW-h, even without tax incentives, as long as one battery pack can last for the lifespan of the vehicle. However, TCO of future battery powered cars is ≥25% higher than of series hybrid or regular cars. This cost gap remains unless cost of batteries drops to 150 euro/kW-h in the future. Variations in driving cost from charging patterns have negligible influence on TCO. GHG abatement costs using plug-in hybrid cars are currently 400-1400 euro/ton CO2eq and may come down to -100 to 300 euro/ton. Abatement cost using battery powered cars are currently >1900 euro/ton and are not projected to drop <300-800 euro/ton.
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Pellegrino, G.; Vagati, A.; Guglielmi, P.; Boazzo, B. Performance Comparison between Surface-Mounted and Interior PM Motor Drives for Electric Vehicle Application. IEEE Trans. Ind. Electron. 2012, 59 (2), 803– 811, DOI: 10.1109/TIE.2011.2151825
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Stangeland, K.; Kalai, D.; Li, H.; Yu, Z. CO 2 Methanation: The Effect of Catalysts and Reaction Conditions. Energy Procedia 2017, 105, 2022– 2027, DOI: 10.1016/j.egypro.2017.03.577
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CO2 Methanation: The Effect of Catalysts and Reaction Conditions
Stangeland, Kristian; Kalai, Dori; Li, Hailong; Yu, Zhixin
Energy Procedia (2017), 105 (), 2022-2027CODEN: EPNRCV; ISSN:1876-6102. (Elsevier Ltd.)
A review. Great attention has been paid to develop non-fossil fuel energy sources to reduce carbon emissions and create a sustainable energy system for the future. Storing the intermittent energy is one of the challenges related to electricity prodn. from renewable energy resources. The Sabatier reaction produces methane from carbon dioxide and hydrogen, with the latter produced by electrolysis. Methane could be stored and transported through the natural gas infrastructure already in place, and be a viable option for renewable energy storage. Current technol. for biogas upgrading focuses on removing carbon dioxide from the biogas. However, the biogas could potentially be used directly as feed gas for the Sabatier reaction, thereby removing the cost assocd. with carbon dioxide removal and increasing the methane yield and carbon utilization from biol. sources. Carbon dioxide methanation requires a catalyst to be active at relatively low temps. and selective towards methane. Nickel based catalyst are most widely investigated, and com. catalysts are typically nickel on alumina support. Focus on catalyst development for carbon dioxide methanation is predominantly related to support modification, promoter addn., as well as utilizing new class of materials such as hydrotalcite-derived catalysts.
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Figure 1
Figure 1. Representation of possible technology chains yielding linear or circular economies, in a net-positive, net-zero, or net-negative CO₂-emission system. (16,23) The representation includes fossil-based systems, CCU-fuel-based systems, and bioenergy-based systems. Process units include conventional postcombustion CO₂ capture; direct capture of CO₂ from air (DAC, requiring C-free renewable energy to operate); biomass conversion plants; CO₂ conversion, including an electrolyzer for H₂ generation and a collector of C-free renewable electricity (the stylized yellow spark). Arrows represent material fluxes (equipped with storage capacity) of fossil (from the subsurface, red), synthetic (from a conversion plant, blue), biogenic (from biomass, green), or oxidized (CO₂, dark gray) carbon. The ultimate CO₂ fate can be either release to the atmosphere (light gray cloud) or storage in the subsurface (stylized anticline aquifer).
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Figure 2
Figure 2. Block diagram of the power–fuel–power systems investigated: (a) hydrogen, (b) methane, (c) methanol, and (d) ammonia. The blocks include their corresponding pressure levels, energy efficiency, and second-law (exergy) efficiency, and CO₂ capture rate in the case of the power plants. The systems’ cyclic efficiency is given in the upper left corners. The supply of electricity to the fuel synthesis and to the DAC/N₂-separation units is not represented in the figure for the sake of clarity. For methanol, the source of the CO₂ and H₂O emissions is the combustion of a purge stream containing CO₂ and CO. In the case of methane, the water is a byproduct of the Sabatier reaction and the CO₂ is part of the unreacted feed. These are minor streams but are included in the figure for completeness. The abbreviated fuel-to-power conversion plants are hydrogen solid oxide fuel cell (H₂SOFC) and gas turbine combined cycle (GTCC). See Figure 3 for the corresponding power–fuel–propulsion chains.
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Figure 3
Figure 3. Block diagram of the four power–fuel–propulsion systems investigated: (a) hydrogen, (b) methane, (c) methanol, and (d) ammonia. The blocks include their corresponding pressure levels, energy efficiency, and second-law (exergy) efficiency and CO₂ capture rate in the case of the power plants. The systems’ cyclic efficiency is given in the upper left corners. The supply of electricity to the fuel synthesis and to the DAC/N₂-separation units is not represented in the figure for the sake of clarity. The pressure indicated in the final conversion blocks represents the vehicle’s tank. For methanol, the source of the CO₂ and H₂O emissions is the combustion of a purge stream containing CO₂ and CO. In the case of methane, the water is a byproduct of the Sabatier reaction and the CO₂ is part of the unreacted feed. These are minor streams but are included in the figure for completeness. The abbreviated fuel-to-propulsion technologies are hydrogen polymer electrolyte membrane fuel cell (H₂PEMFC), internal combustion engine (ICE), and direct methanol fuel cell (DMFC).
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Figure 4
Figure 4. Waterfall diagrams of power–methane–power (a) and power–methanol–propulsion (b).
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Figure 5
Figure 5. Breakdown of primary renewable power losses and resulting cycle efficiencies to produce 1 GW of power and/or propulsion (using DAC for the CCU fuel systems). The darkest color represents the relative energy output of each chain. H₂ compression occurs only in the hydrogen for propulsion chain, where additional compression is required after electrolysis. “Air separation” indicates the efficiency loss related to DAC for the CCU fuels and to N₂ separation for ammonia. “Air separation” and “fuel synthesis” do not occur in the hydrogen chains. Of the chemical energy carriers, hydrogen has the highest cycle efficiency, especially when providing propulsion in a transport application. The biggest losses are incurred in all systems in the electrolysis and fuel combustion steps, not in the fuel synthesis step. For the CCU propulsion cases, these losses are complemented with a large loss for direct air capture of CO₂.
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Figure 6
Figure 6. Comparison of the second-law efficiency of each system block and of its contribution to the efficiency loss for the power–fuel–power systems. The graph shows that the synthesis step of the synthetic fuels is already highly efficient, as shown by the high second-law efficiency. Fuel synthesis however has only a small impact on the cyclic efficiency loss over the overall system. Electrolysis and fuel combustion in a GTCC (with or without CCS) contribute much more to the overall cyclic efficiency loss, and they still exhibit quite some room for efficiency improvement, especially fuel combustion. DAC shows the highest potential for second-law improvement but has the lowest contribution to the cyclic efficiency loss.
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Figure 7
Figure 7. Sensitivity of net system efficiency to changes in electrolysis, DAC/ASU, fuel synthesis, and fuel conversion. The second column from the left indicates how the input parameters were varied, represented on a 0–100% scale where possible. The resulting range of chain efficiencies is reported on the right with the middle line representing the base case. The input parameter assumptions are given as efficiency for electrolysis and final conversion and as an energy requirement for DAC/ASU. For fuel synthesis, see the corresponding text.
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  Journal of CO2 Utilization (2016), 16 (), 138-149CODEN: JCUOAJ; ISSN:2212-9839. (Elsevier Ltd.)
  CO2 utilization is gaining attention as a greenhouse gas abatement strategy complementary to CO2 storage. This study explores the techno-environmental performance of CO2 utilization trough dry reforming of methane into syngas for the prodn. of di-Me ether (DME). The CO2 source is a hydrogen prodn. unit at a refinery, where solvent based CO2 capture is applied. Aspen+ modeling and hybrid life cycle assessment (LCA) is used to assess the techno-environmental performance of this utilization option compared to a ref. case without CO2 capture and a case with CO2 capture and storage. Results of the tech. assessment show that although 94% of the captured CO2 can be utilized for DME prodn., only 9% of CO2 is avoided in the entire process as a result of direct CO2 formation during DME synthesis and the combustion of syngas to provide the heat demanded by the dry reforming process. Besides, a substantial amt. of electricity is required for syngas compression. Consequently, the LCA results indicate that climate change potential (CCP) is reduced by 8% while it is 37% higher than CCP when CO2 is stored and DME is produced conventionally. Sensitivity analyses are performed on various process conditions. Overall, this study indicates that this utilization route lowers the CCP although the redn. is limited compared to CCS. While the techno-environmental anal. is a useful tool to gain better insights in the performance of CO2 utilization options, the complex environmental trade-offs make it difficult to draw robust conclusions on the performance.
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12. 12
  Zhang, X.; Bauer, C.; Mutel, C. L.; Volkart, K. Life Cycle Assessment of Power-to-Gas: Approaches, System Variations and Their Environmental Implications. Appl. Energy 2017, 190, 326– 338, DOI: 10.1016/j.apenergy.2016.12.098
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  12
  Life Cycle Assessment of Power-to-Gas: Approaches, system variations and their environmental implications
  Zhang, Xiaojin; Bauer, Christian; Mutel, Christopher L.; Volkart, Kathrin
  Applied Energy (2017), 190 (), 326-338CODEN: APENDX; ISSN:0306-2619. (Elsevier Ltd.)
  Electricity generation from intermittent renewable sources is expected to increase rapidly in the next decades. Integrating renewable energy requires energy storage during low-demand periods and potential conversion of surplus electricity into other energy carriers. Power-to-Gas (P2G) is a promising technol. due to its potential to provide large-scale and long-term energy storage. However, this technol. has many system variations, and their environmental performances need to be evaluated and compared with conventional technologies before large-scale deployment. In this paper, we investigate the environmental performance of P2G using Life Cycle Assessment (LCA), and mainly focus on the following three aspects: (1) discussion of differences as consequence of the approach applied for CO2 Capture and Utilization (CCU); (2) evaluation of technol. variations including supply of electricity, alternative system processes (electrolysis technologies and CO2 sources), product gases (hydrogen and methane), and comparison of these P2G systems with conventional technologies, and (3) investigation of further environmental impacts of P2G in addn. to the impact of global warming potential. We argue that in case of P2M, system expansion provides more meaningful results than subdivision for CCU, since it reflects the added value of CO2 utilization providing electricity or cement with low GHG intensity. The results of system variations show that P2G can, depending on electricity supply and CO2 source, reduce GHG emission compared to conventional gas prodn. technologies, and that P2H has higher potential of emission redn. than P2M. Concerning other impact categories, P2H can have lower impacts than conventional hydrogen prodn., while P2M most often has higher impacts than using conventional natural gas.
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13. 13
  van der Giesen, C.; Kleijn, R.; Kramer, G. J. Energy and Climate Impacts of Producing Synthetic Hydrocarbon Fuels from CO2. Environ. Sci. Technol. 2014, 48 (12), 7111– 7121, DOI: 10.1021/es500191g
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  13
  Energy and climate impacts of producing synthetic hydrocarbon fuels from carbon dioxide
  van der Giesen, Coen; Kleijn, Rene; Kramer, Gert Jan
  Environmental Science & Technology (2014), 48 (12), 7111-7121CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
  A review. Within the context of carbon dioxide (CO2) utilization there is an increasing interest in using CO2 as a resource to produce sustainable liq. hydrocarbon fuels. When these fuels are produced by solely using solar energy they are labeled as solar fuels. In the recent discourse on solar fuels intuitive arguments are used to support the prospects of these fuels. This paper takes a quant. approach to investigate some of the claims made in this discussion. We analyze the life cycle performance of various classes of solar fuel processes using different primary energy and CO2 sources. We compare their efficacy with respect to carbon mitigation with ubiquitous fossil-based fuels and conclude that producing liq. hydrocarbon fuels starting from CO2 by using existing technologies requires much more energy than existing fuels. An improvement in life cycle CO2 emissions is only found when solar energy and atm. CO2 are used. Producing fuels from CO2 is a very long-term niche at best, not the panacea suggested in the recent public discourse.
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14. 14
  Fernández-Dacosta, C.; Van Der Spek, M.; Hung, C. R.; Oregionni, G. D.; Skagestad, R.; Parihar, P.; Gokak, D. T.; Strømman, A. H.; Ramirez, A. Prospective Techno-Economic and Environmental Assessment of Carbon Capture at a Refinery and CO2 Utilisation in Polyol Synthesis. J. CO2 Util. 2017, 21, 405– 422, DOI: 10.1016/j.jcou.2017.08.005
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  14
  Prospective techno-economic and environmental assessment of carbon capture at a refinery and CO2 utilisation in polyol synthesis
  Fernandez-Dacosta, Cora; van der Spek, Mijndert; Hung, Christine Roxanne; Oregionni, Gabriel David; Skagestad, Ragnhild; Parihar, Prashant; Gokak, D. T.; Stroemman, Anders Hammer; Ramirez, Andrea
  Journal of CO2 Utilization (2017), 21 (), 405-422CODEN: JCUOAJ; ISSN:2212-9839. (Elsevier Ltd.)
  CO2 utilization is gaining interest as a potential element towards a sustainable economy. CO2 can be used as feedstock in the synthesis of fuels, chems. and polymers. This study presents a prospective assessment of carbon capture from a hydrogen unit at a refinery, where the CO2 is either stored, or partly stored and partly utilized for polyols prodn. A methodol. integrating tech., economic and environmental models with uncertainty anal. is used to assess the performance of carbon capture and storage or utilization at the refinery. Results show that only 10% of the CO2 captured from an industrial hydrogen unit can be utilized in a com.-scale polyol plant. This option has limited potential for large scale CO2 mitigation from industrial sources. However, CO2 capture from a hydrogen unit and its utilization for the synthesis of polyols provides an interesting alternative from an economic perspective. The costs of CO2-based polyol are estd. at 1200 euro/t polyol, 16% lower than those of conventional polyol. Furthermore, the costs of storing the remaining CO2 are offset by the benefits of cheaper polyol prodn. Therefore, the combination of CO2 capture and partial utilization provides an improved business case over capture and storage alone. The environmental assessment shows that the climate change potential of this CO2 utilization system is 23% lower compared to a ref. case in which no CO2 is captured at the refinery. Five other environmental impact categories included in this study present slightly better performance for the utilization case than for the ref. case.
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15. 15
  Dimitriou, I.; García-Gutiérrez, P.; Elder, R. H.; Cuéllar-Franca, R. M.; Azapagic, A.; Allen, R. W. K. Carbon Dioxide Utilisation for Production of Transport Fuels: Process and Economic Analysis. Energy Environ. Sci. 2015, 8 (6), 1775– 1789, DOI: 10.1039/C4EE04117H
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  15
  Carbon dioxide utilisation for production of transport fuels: process and economic analysis
  Dimitriou, Ioanna; Garcia-Gutierrez, Pelayo; Elder, Rachael H.; Cuellar-Franca, Rosa M.; Azapagic, Adisa; Allen, Ray W. K.
  Energy & Environmental Science (2015), 8 (6), 1775-1789CODEN: EESNBY; ISSN:1754-5706. (Royal Society of Chemistry)
  Utilizing CO2 as a feedstock for chems. and fuels could help mitigate climate change and reduce dependence on fossil fuels. For this reason, there is an increasing world-wide interest in carbon capture and utilization (CCU). As part of a broader project to identify key tech. advances required for sustainable CCU, this work considers different process designs, each at a high level of technol. readiness and suitable for large-scale conversion of CO2 into liq. hydrocarbon fuels, using biogas from sewage sludge as a source of CO2. The main objective of the paper is to est. fuel prodn. yields and costs of different CCU process configurations in order to establish whether the prodn. of hydrocarbon fuels from com. proven technologies is economically viable. Four process concepts are examd., developed and modelled using the process simulation software Aspen Plus to det. raw materials, energy and utility requirements. Three design cases are based on typical biogas applications: (1) biogas upgrading using a monoethanolamine (MEA) unit to remove CO2, (2) combustion of raw biogas in a combined heat and power (CHP) plant and (3) combustion of upgraded biogas in a CHP plant which represents a combination of the first two options. The fourth case examines a post-combustion CO2 capture and utilization system where the CO2 removal unit is placed right after the CHP plant to remove the excess air with the aim of improving the energy efficiency of the plant. All four concepts include conversion of CO2 to CO via a reverse water-gas-shift reaction process and subsequent conversion to diesel and gasoline via Fischer-Tropsch synthesis. The studied CCU options are compared in terms of liq. fuel yields, energy requirements, energy efficiencies, capital investment and prodn. costs. The overall plant energy efficiency and prodn. costs range from 12-17% and £15.8-29.6 per L of liq. fuels, resp. A sensitivity anal. is also carried out to examine the effect of different economic and tech. parameters on the prodn. costs of liq. fuels. The results indicate that the prodn. of liq. hydrocarbon fuels using the existing CCU technol. is not economically feasible mainly because of the low CO2 sepn. and conversion efficiencies as well as the high energy requirements. Therefore, future research in this area should aim at developing novel CCU technologies which should primarily focus on optimizing the CO2 conversion rate and minimising the energy consumption of the plant.
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16. 16
  Schlögl, R.; Abanades, C.; Aresta, M.; Azapagic, A.; Blekkan, E. A.; Cantat, T.; Centi, G.; Duic, N.; El Khamlichi, A.; Hutchings, G.; Mazzotti, M.; Olsbye, U.; Mikulcic, H. Novel Carbon Capture and Utilisation Technologies. Research and Climate Impacts; SAPEA: Brussels, 2018; DOI: 10.26356/CARBONCAPTURE .
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17. 17
  Walsh, B.; Ciais, P.; Janssens, I. A.; Peñuelas, J.; Riahi, K.; Rydzak, F.; Van Vuuren, D. P.; Obersteiner, M. Pathways for Balancing CO2 Emissions and Sinks. Nat. Commun. 2017, 8, 14856, DOI: 10.1038/ncomms14856
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  Pathways for balancing CO2 emissions and sinks
  Walsh, Brian; Ciais, Philippe; Janssens, Ivan A.; Penuelas, Josep; Riahi, Keywan; Rydzak, Felicjan; van Vuuren, Detlef P.; Obersteiner, Michael
  Nature Communications (2017), 8 (), 14856CODEN: NCAOBW; ISSN:2041-1723. (Nature Publishing Group)
  In Dec. 2015 in Paris, leaders committed to achieve global, net decarbonization of human activities before 2100. This achievement would halt and even reverse anthropogenic climate change through the net removal of carbon from the atm. However, the Paris documents contain few specific prescriptions for emissions mitigation, leaving various countries to pursue their own agendas. In this anal., we project energy and land-use emissions mitigation pathways through 2100, subject to best-available parameterization of carbon-climate feedbacks and interdependencies. We find that, barring unforeseen and transformative technol. advancement, anthropogenic emissions need to peak within the next 10 years, to maintain realistic pathways to meeting the COP21 emissions and warming targets. Fossil fuel consumption will probably need to be reduced below a quarter of primary energy supply by 2100 and the allowable consumption rate drops even further if neg. emissions technologies remain technol. or economically unfeasible at the global scale.
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18. 18
  van Soest, H. L.; de Boer, H. S.; Roelfsema, M.; den Elzen, M. G. J.; Admiraal, A.; van Vuuren, D. P.; Hof, A. F.; van den Berg, M.; Harmsen, M. J. H. M.; Gernaat, D. E. H. J.; Forsell, N. Early Action on Paris Agreement Allows for More Time to Change Energy Systems. Clim. Change 2017, 144 (2), 165– 179, DOI: 10.1007/s10584-017-2027-8
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  Early action on Paris Agreement allows for more time to change energy systems
  van Soest, Heleen L.; Sytze de Boer, Harmen; Roelfsema, Mark; den Elzen, Michel G. J.; Admiraal, Annemiek; van Vuuren, Detlef P.; Hof, Andries F.; van den Berg, Maarten; Harmsen, Mathijs J. H. M.; Gernaat, David E. H. J.; Forsell, Nicklas
  Climatic Change (2017), 144 (2), 165-179CODEN: CLCHDX; ISSN:0165-0009. (Springer)
  The IMAGE integrated assessment model was used to develop a set of scenarios to evaluate the Nationally Detd. Contributions (NDCs) submitted by Parties under the Paris Agreement. The scenarios project emissions and energy system changes under (i) current policies, (ii) implementation of the NDCs, and (iii) various trajectories to a radiative forcing level of 2.8 W/m2 in 2100, which gives a probability of about two thirds to limit warming to below 2 °C. The scenarios show that a cost-optimal pathway from 2020 onwards towards 2.8 W/m2 leads to a global greenhouse gas emission level of 38 gigatonne CO2 equivalent (GtCO2eq) by 2030, equal to a redn. of 20% compared to the 2010 level. The NDCs are projected to lead to 2030 emission levels of 50 GtCO2eq, which is still an increase compared to the 2010 level. A scenario that achieves the 2.8 W/m2 forcing level in 2100 from the 2030 NDC level requires more rapid transitions after 2030 to meet the forcing target. It shows an annual redn. rate in greenhouse gas emissions of 4.7% between 2030 and 2050, rapidly phasing out unabated coal-fired power plant capacity, more rapid scale-up of low-carbon energy, and higher mitigation costs. A bridge scenario shows that enhancing the ambition level of NDCs before 2030 allows for a smoother energy system transition, with av. annual emission redn. rates of 4.5% between 2030 and 2050, and more time to phase out coal capacity.
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19. 19
  Millar, R. J.; Fuglestvedt, J. S.; Friedlingstein, P.; Rogelj, J.; Grubb, M. J.; Matthews, H. D.; Skeie, R. B.; Forster, P. M.; Frame, D. J.; Allen, M. R. Emission Budgets and Pathways Consistent with Limiting Warming to 1.5 °C. Nat. Geosci. 2017, 10, 741– 748, DOI: 10.1038/ngeo3031
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  Emission budgets and pathways consistent with limiting warming to 1.5°C
  Millar, Richard J.; Fuglestvedt, Jan S.; Friedlingstein, Pierre; Rogelj, Joeri; Grubb, Michael J.; Matthews, H. Damon; Skeie, Ragnhild B.; Forster, Piers M.; Frame, David J.; Allen, Myles R.
  Nature Geoscience (2017), 10 (10), 741-747CODEN: NGAEBU; ISSN:1752-0894. (Nature Research)
  The Paris Agreement has opened debate on whether limiting warming to 1.5°C is compatible with current emission pledges and warming of about 0.9°C from the mid-nineteenth century to the present decade. We show that limiting cumulative post-2015 CO2 emissions to about 200 GtC would limit post-2015 warming to less than 0.6°C in 66% of Earth system model members of the CMIP5 ensemble with no mitigation of other climate drivers, increasing to 240 GtC with ambitious non-CO2 mitigation. Assuming emissions peak and decline to below current levels by 2030, and continue thereafter on a much steeper decline, which would be historically unprecedented but consistent with a std. ambitious mitigation scenario (RCP2.6), results in a likely range of peak warming of 1.2-2.0°C above the mid-nineteenth century. If CO2 emissions are continuously adjusted over time to limit 2100 warming to 1.5°C, with ambitious non-CO2 mitigation, net future cumulative CO2 emissions are unlikely to prove less than 250 GtC and unlikely greater than 540 GtC. Hence, limiting warming to 1.5°C is not yet a geophys. impossibility, but is likely to require delivery on strengthened pledges for 2030 followed by challengingly deep and rapid mitigation. Strengthening near-term emissions redns. would hedge against a high climate response or subsequent redn. rates proving economically, tech. or politically unfeasible.
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20. 20
  IPCC. Summary for Policy Makers. In Climate change 2014: Synthesis Report. Contribution of Working Groups I, II and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change; Pachauri, R. K., Meyer, L. A., Eds.; IPCC: Geneva, Switzerland, 2014; p 151.
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21. 21
  Davis, S. J.; Lewis, N. S.; Shaner, M.; Aggarwal, S.; Arent, D.; Azevedo, I. L.; Benson, S. M.; Bradley, T.; Brouwer, J.; Chiang, Y.-M.; Clack, C. T. M.; Cohen, A.; Doig, S.; Edmonds, J.; Fennell, P.; Field, C. B.; Hannegan, B.; Hodge, B.-M.; Hoffert, M. I.; Ingersoll, E.; Jaramillo, P.; Lackner, K. S.; Mach, K. J.; Mastrandrea, M.; Ogden, J.; Peterson, F.; Sanchez, D. L.; Sperling, D.; Stagner, J.; Trancik, J. E.; Yang, C. J.; Caldeira, K. Net-Zero Emissions Energy Systems. Science 2018, 360 (6396), eaas9793, DOI: 10.1126/science.aas9793
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22. 22
  IPCC. Summary for Policymakers. In Global warming of 1.5°C. An IPCC Special Report on the impacts of global warming of 1.5°C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change; Masson-Delmotte, V., Zhai, P., Pörtner, H. O., Roberts, D., Skea, J., Shukla, P.R., Pirani, A., Moufouma-Okia, W., Péan, C., Pidcock, R., Connors, S., Matthews, J. B. R., Chen, Y., Zhou, X., Gomis, M. I., Lonnoy, E., Maycock, T., Tignor, M., W, T., Eds.; IPCC: Geneva, Switzerland, 2018; p 32.
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23. 23
  van der Spek, M.; Sutter, D.; Antonini, C.; Mazzotti, M. The Role of Direct Air Capture and Bioenergy in Net Zero CCU Fuel Loops. In International Conference on Negative CO2 Emissions , May 22–24, 2018, Göteborg, Sweden; pp 1– 7.
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24. 24
  Sternberg, A.; Jens, C. M.; Bardow, A. Life Cycle Assessment of CO2-Based C1-Chemicals. Green Chem. 2017, 19, 2244– 2259, DOI: 10.1039/C6GC02852G
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  Life cycle assessment of CO2-based C1-chemicals
  Sternberg, Andre; Jens, Christian M.; Bardow, Andre
  Green Chemistry (2017), 19 (9), 2244-2259CODEN: GRCHFJ; ISSN:1463-9262. (Royal Society of Chemistry)
  Carbon dioxide (CO2) and hydrogen are promising feedstocks for a sustainable chem. industry. Currently, the conversions of CO2 and hydrogen are most advanced for chems. with 1 carbon atom, the so-called C1-chems., with the first pilot plants in operation. For formic acid, carbon monoxide, methanol, and methane, CO2-based C1-chems. can reduce the impacts of fossil depletion and global warming through the substitution of fossil-based processes. Existing life cycle assessment (LCA) studies for carbon monoxide, methanol, and methane show that a redn. in environmental impacts is achieved if hydrogen is supplied by water electrolysis with renewable electricity. However, in the foreseeable future, renewable electricity will be limited. Thus, from an environmental point of view, renewable electricity should be employed for chem. processes in the order of highest environmental impact redns. Environmental impact redns. are the difference in environmental impacts of fossil-based processes and CO2-based processes. In this study, we compared the CO2-based prodn. of formic acid, carbon monoxide, methanol, and methane. We detd. the redn. of global warming and fossil depletion impacts using 1 kg of hydrogen. Our results show that the CO2-based prodn. of formic acid achieves the highest environmental impact redns., followed by carbon monoxide and methanol. The lowest environmental impact redns. are achieved for CO2-based methane prodn. Our anal. reveals that the CO2-based prodn. of formic acid can reduce environmental impacts, compared to the fossil-based process, even if hydrogen is supplied by fossil-based steam-methane-reforming.
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25. 25
  Schüth, F.; Palkovits, R.; Schlögl, R.; Su, D. S. Ammonia as a Possible Element in an Energy Infrastructure: Catalysts for Ammonia Decomposition. Energy Environ. Sci. 2012, 5 (4), 6278– 6289, DOI: 10.1039/C2EE02865D
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  Ammonia as a possible element in an energy infrastructure: catalysts for ammonia decomposition
  Schueth, F.; Palkovits, R.; Schloegl, R.; Su, D. S.
  Energy & Environmental Science (2012), 5 (4), 6278-6289CODEN: EESNBY; ISSN:1754-5706. (Royal Society of Chemistry)
  A review. The possible role of ammonia in a future energy infrastructure is discussed. The review is focused on the catalytic decompn. of ammonia as a key step. Other aspects, such as the catalytic removal of ammonia from gasification product gas or direct ammonia fuel cells, are highlighted as well. The more general question of the integration of ammonia in an infrastructure is also covered.
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26. 26
  Grinberg Dana, A.; Elishav, O.; Bardow, A.; Shter, G. E.; Grader, G. S. Nitrogen-Based Fuels: A Power-to-Fuel-to-Power Analysis. Angew. Chem., Int. Ed. 2016, 55 (31), 8798– 8805, DOI: 10.1002/anie.201510618
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  Nitrogen-Based Fuels: A Power-to-Fuel-to-Power Analysis
  Grinberg Dana, Alon; Elishav, Oren; Bardow, Andre; Shter, Gennady E.; Grader, Gideon S.
  Angewandte Chemie, International Edition (2016), 55 (31), 8798-8805CODEN: ACIEF5; ISSN:1433-7851. (Wiley-VCH Verlag GmbH & Co. KGaA)
  This paper discussed about nitrogen-based fuels and power-to-fuel-to-power anal.
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27. 27
  Götz, M.; Lefebvre, J.; Mörs, F.; McDaniel Koch, A.; Graf, F.; Bajohr, S.; Reimert, R.; Kolb, T. Renewable Power-to-Gas: A Technological and Economic Review. Renew. Renewable Energy 2016, 85, 1371– 1390, DOI: 10.1016/j.renene.2015.07.066
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28. 28
  Sternberg, A.; Bardow, A. Life Cycle Assessment of Power-to-Gas: Syngas vs Methane. ACS Sustainable Chem. Eng. 2016, 4 (8), 4156– 4165, DOI: 10.1021/acssuschemeng.6b00644
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  Life Cycle Assessment of Power-to-Gas: Syngas vs Methane
  Sternberg, Andre; Bardow, Andre
  ACS Sustainable Chemistry & Engineering (2016), 4 (8), 4156-4165CODEN: ASCECG; ISSN:2168-0485. (American Chemical Society)
  Power-to-Gas enables the integration of renewable electricity and carbon into the chem. industry. The electricity is used to produce hydrogen, which is subsequently converted with CO2 as the renewable carbon source. The resulting products can be used as feedstock for the chem. industry replacing current fossil-based feedstock. Because the integration of renewable electricity and carbon into the chem. industry is mainly environmentally motivated, we identify the conditions under which Power-to-Gas pathways are environmentally beneficial. The conditions are expressed as environmental threshold values for electricity supply. The threshold values are derived by a comparative life cycle assessment (LCA) of Power-to-Gas pathways to fossil-based processes. We analyze Power-to-Gas pathways to synthetic natural gas (Power-to-SNG) and to syngas (Power-to-Syngas). SNG is produced by the Sabatier reaction; syngas by reverse water gas shift (rWGS) and dry reforming of methane (DRM). The threshold values for electricity supply allow us to compare the environmental benefit of Power-to-SNG and Power-to-Syngas on an equal basis: how well they utilize the currently limited renewable electricity. Syngas prodn. by the DRM process has the largest environmental potential. Both Power-to-Syngas pathways lead to larger environmental benefits than Power-to-SNG making syngas the more desirable product than methane as long as renewable electricity is limited.
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29. 29
  IEAGHG. CO2 Capture at Gas Fired Power Plants, 2012/8; IEAGHG: Cheltenham, 2012.
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  Wohland, J.; Witthaut, D.; Schleussner, C. F. Negative Emission Potential of Direct Air Capture Powered by Renewable Excess Electricity in Europe. Earth's Future 2018, 6 (10), 1380– 1384, DOI: 10.1029/2018EF000954
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  US Office of Energy Efficiency & Renewable Energy. Fuel Cells. In Fuel Cell Technologies Office Multi-Year Research, Development, and Demonstration Plan; US Office of Energy Efficiency & Renewable Energy: Washington D.C., 2017; pp 3.4.1– 3.4.58.
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  Van-Dal, E. S.; Bouallou, C. Design and Simulation of a Methanol Production Plant from CO2 Hydrogenation. J. Cleaner Prod. 2013, 57, 38– 45, DOI: 10.1016/j.jclepro.2013.06.008
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  Design and simulation of a methanol production plant from CO2 hydrogenation
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  There has been a large increase in anthropogenic emissions of CO2 over the past century. The use of captured CO2 can become a profitable business, in addn. to controlling CO2 concn. in the atm. A process for producing fuel grade methanol from captured CO2 is proposed in this paper. The process is designed and simulated with Aspen Plus. The CO2 is captured by chem. absorption from the flue gases of a thermal power plant. The hydrogen is produced by water electrolysis using carbon-free electricity. The methanol plant provides 36% of the thermal energy required for CO2 capture, reducing considerably the costs of the capture. The CO2 balance of the process showed that it is possible to abate 1.6 t of CO2 per tonne of methanol produced if oxygen byproduct is sold, or 1.2 t if it is not.
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  In this perspective, the catalytic shortfalls of contemporary DMFCs are discussed in the context of the materials that are currently being employed as electrocatalysts in both the anode and cathode. In light of these shortfalls, the inherent advantages of one-dimensional (1D) nanostructures are highlighted so as to demonstrate their potential as efficient, robust, and active replacements for contemporary nanoparticulate electrocatalysts. Finally, we review in detail the recent applications of 1D nanostructured electrocatalysts as both anodes and cathodes, and explore their potentially promising results towards improving DMFC efficiency and cost-effectiveness. In the case of cathode electrocatalysts, our group has recently prepd. both 200 nm platinum nanotubes and ultrathin 2 nm platinum nanowires, which evinced two-fold and seven-fold enhancements in area specific ORR activity, resp., as compared with contemporary com. Pt nanoparticles. Similarly, the development of one-dimensional anodic electrocatalysts such as alloyed PtRu and PtCo nanowires, hierarchical Pt∼Pd nanowires, and segmented PtRu systems have yielded promising enhancements towards methanol oxidn.
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  State-of-the-art concepts for solar thermal power systems are based on parabolic trough, tower or parabolic disks either heating molten salts, mineral oil, air or generating steam. We propose in this paper, a conceptual design of a solar boiler. This concept comes from the conventional thermal power plants boiler, with the difference that the heat comes from mirrors that conc. the solar radiation on wall-type array of solar collectors, instead of coming from fuel flames and hot gases. In our preliminary performance, anal. of this innovative solar boiler applied to electricity prodn., we have found that overall efficiency of the conversion from direct solar irradn. energy to electricity is above 20%, which is comparable to the value of parabolic trough and central tower technologies. Besides that, the concept seems very robust and could overcome some drawbacks derived from pressure losses, control complexity and material thermo-mech. stress.
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  Combining co-firing biomass and carbon capture and storage (CCS) in power plants offers attractive potential for net removal of carbon dioxide (CO2) from the atm. In this study, the impact of co-firing biomass (wood pellets and straw pellets) on the emission profile of power plants with carbon capture and storage has been assessed for two types of coal-fired power plants: a supercrit. pulverised coal power plant (SCPC) and an integrated gasification combined cycle plant (IGCC). Besides, comparative life cycle assessments have been performed to examine the environmental impacts of the combination of co-firing biomass and CCS. Detailed calcns. on mass balances of the inputs and outputs of the power plants illustrate the effect of the different content of pollutants in biomass on the capture unit. Life cycle assessment results reveal that 30% co-firing biomass and applying CCS net neg. CO2 emissions in the order of 67-85 g/kWh are obtained. The impact in all other environmental categories is increased by 20-200%. However, aggregation into endpoint levels shows that the decrease in CO2 emissions more than offsets the increase in the other categories. Sensitivity analyses illustrate that results are most sensitive to parameters that affect the amt. of fuel required, such as the efficiency of the power plant and assumptions regarding the supply chains of coal and biomass. Esp., assumptions regarding land use allocation and carbon debt of biomass significantly influence the environmental performance of BioCCS.
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  The authors examine efficiency, costs and greenhouse gas emissions of current and future elec. cars (EV), including the impact from charging EV on electricity demand and infrastructure for generation and distribution. Uncoordinated charging would increase national peak load by 7% at 30% penetration rate of EV and household peak load by 54%, which may exceed the capacity of existing electricity distribution infrastructure. At 30% penetration of EV, off-peak charging would result in a 20% higher, more stable base load and no addnl. peak load at the national level and up to 7% higher peak load at the household level. Therefore, if off-peak charging is successfully introduced, elec. driving need not require addnl. generation capacity, even in case of 100% switch to elec. vehicles. GHG emissions from elec. driving depend most on the fuel type (coal or natural gas) used in the generation of electricity for charging, and range between 0 g/km (using renewables) and 155 g/km (using electricity from an old coal-based plant). Based on the generation capacity projected for the Netherlands in 2015, electricity for EV charging would largely be generated using natural gas, emitting 35-77 g CO2eq/km. Total cost of ownership (TCO) of current EV are uncompetitive with regular cars and series hybrid cars by >800 euro/yr. TCO of future wheel motor PHEV may become competitive when batteries cost 400 euro/kW-h, even without tax incentives, as long as one battery pack can last for the lifespan of the vehicle. However, TCO of future battery powered cars is ≥25% higher than of series hybrid or regular cars. This cost gap remains unless cost of batteries drops to 150 euro/kW-h in the future. Variations in driving cost from charging patterns have negligible influence on TCO. GHG abatement costs using plug-in hybrid cars are currently 400-1400 euro/ton CO2eq and may come down to -100 to 300 euro/ton. Abatement cost using battery powered cars are currently >1900 euro/ton and are not projected to drop <300-800 euro/ton.
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  A review. Great attention has been paid to develop non-fossil fuel energy sources to reduce carbon emissions and create a sustainable energy system for the future. Storing the intermittent energy is one of the challenges related to electricity prodn. from renewable energy resources. The Sabatier reaction produces methane from carbon dioxide and hydrogen, with the latter produced by electrolysis. Methane could be stored and transported through the natural gas infrastructure already in place, and be a viable option for renewable energy storage. Current technol. for biogas upgrading focuses on removing carbon dioxide from the biogas. However, the biogas could potentially be used directly as feed gas for the Sabatier reaction, thereby removing the cost assocd. with carbon dioxide removal and increasing the methane yield and carbon utilization from biol. sources. Carbon dioxide methanation requires a catalyst to be active at relatively low temps. and selective towards methane. Nickel based catalyst are most widely investigated, and com. catalysts are typically nickel on alumina support. Focus on catalyst development for carbon dioxide methanation is predominantly related to support modification, promoter addn., as well as utilizing new class of materials such as hydrotalcite-derived catalysts.
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  In this study, ammonia is identified as a sustainable fuel for mobile and remote applications. Similar to hydrogen, ammonia is a synthetic product that can be obtained either from fossil fuels, biomass, or other renewable sources. Some advantages of ammonia with respect to hydrogen are less expensive cost per unit of stored energy, higher volumetric energy d. that is comparable with that of gasoline, easier prodn., handling and distribution with the existent infrastructure, and better com. viability. Here, the possible ways to use ammonia as a sustainable fuel in internal combustion engines and fuel-cells are discussed and analyzed based on some thermodn. performance models through efficiency and effectiveness parameters. The refrigeration effect of ammonia, which is another advantage, is also included in the efficiency calcns. The study suggests that the most efficient system is based on fuel-cells which provide simultaneously power, heating and cooling and its only exhaust consists of water and nitrogen. If the cooling effect is taken into consideration, the system's effectiveness reaches 46% implying that a medium size car ranges over 500 km with 50 l fuel at a cost below 2 per 100 km. The cooling power represents about 7.2% from the engine power, being thus a valuable side benefit of ammonia's presence on-board.
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  The design of a future hydrogen supply chain (HSC) network is challenging due to the: (1) involvement of many echelons in the supply chain network, (2) high level of interactions between the supply chain components and sub-systems, and (3) uncertainty in hydrogen demand. Most of the early attempts to design the future HSC failed to incorporate all these challenges in a single generic optimization framework using math. modeling approach. Building on our previous multiperiod MILP model, the model presented in this paper is expanded to take into account uncertainty arising from long-term variation in hydrogen demand using a scenario-based approach. The model also adds another echelon: fueling stations and local distribution of hydrogen. Our results show that the future HSC network is somewhat similar to the existing petroleum infrastructure in terms of prodn., distribution, and storage. In both situations, the most feasible soln. is centralized prodn. plants with truck and rail delivery and small-to-large storage facilities. The main difference is that the future hydrogen supply has the benefits of using distributed forecourt prodn. of hydrogen at local fueling stations via several prodn. technologies. Finally, the performance of the studied models was evaluated using sensitivity and risk analyses.
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  Cumulative exergy consumption and cumulative degree of perfection of chemical processes
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  The cumulative exergy consumption (CExC) index rj (rj = Bj/Pj, related to the unit of the jth product, expresses the ratio of the sum Bj of the exergies of natural resources delivered to the system in all steps of the chain of prodn. processes leading to the product under consideration to the net prodn. Pj of this product in the system under consideration. The definition of the system boundary is very important, because it affects the value of the net prodn. The anal. of CExC provides broader application than the cumulative energy consumption, for it takes into account not only the energy resources but also the nonenergetic raw materials. The anal. of CExC permits the evaluation of the degree of thermodn. perfection of the entire chain of the prodn. process leading to the material under consideration. In many cases, very small values of the cumulative degree of perfection appear, which indicate the possibility of improvement of particular prodn. steps or should stimulate the search for new prodn. methods. The anal. of CExC can provide interesting information for ecol. if only unrenewable natural resources are taken into account. CExC indexes of unrenewable natural resources can be used for the selection of prodn. methods having the smallest impact on the natural environment.
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- Additional remarks about the second-law efficiency analysis; waterfall diagrams of the power–methanol–power, power–ammonia–power, power–methane–propulsion, and power–ammonia–propulsion systems (PDF)
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110th Anniversary: Evaluation of CO2-Based and CO2-Free Synthetic Fuel Systems Using a Net-Zero-CO2-Emission Framework

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Abstract

1. Introduction

2. Net-Zero-CO2 World and Net-Zero-CO2 CCU Fuel Systems

Figure 1

Figure 2

3. Methods

3.1. Technology Assessment Using a Net-Zero-CO2-Emission Framework

3.2. Case Studies

3.3. System Design and Infrastructure Requirements

Figure 3

3.4. Thermodynamic Analysis Assumptions

3.4.1. Building Blocks

3.4.2. Pressure Levels

3.5. Efficiency Analysis

3.6. Second-Law Analysis

3.7. Sensitivity Analysis

4. Results and Discussion

4.1. Primary Energy Loss over the Power–Fuel–Power Chains

Figure 4

Figure 5

4.2. Primary Energy Loss over the Power–Fuel–Propulsion Chains

4.3. Analysis of Efficiency Improvement Potential by Exergy Analysis

Figure 6

4.4. Discussion

Figure 7

5. Conclusions

Supporting Information

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Abstract

Figure 1

Figure 2

Figure 3

Figure 4

Figure 5

Figure 6

Figure 7

References

Supporting Information

Supporting Information

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STEP 1:

STEP 2:

110th Anniversary: Evaluation of CO₂-Based and CO₂-Free Synthetic Fuel Systems Using a Net-Zero-CO₂-Emission Framework

2. Net-Zero-CO₂ World and Net-Zero-CO₂ CCU Fuel Systems

3.1. Technology Assessment Using a Net-Zero-CO₂-Emission Framework