Thesis B [CEIC4003]
Session 2, 2018
22nd October
Determining the Thermodynamic and Economic Feasibility of
Direct Air Capture Technologies
Rohan Badethalav – z5020503
Supervisor: Peter Neal
Abstract
As climate change becomes an increasingly widespread issue, a number of technologies are
being developed to mitigate and reduce the impacts. Direct air capture (DAC) is one such
technique, and is classified as a negative emissions technology. It has profound significance
in the broader context of climate change, because it decreases the concentration of CO 2 in the
atmosphere, rather than simple mitigation. However, DAC faces significant headwind given
the novelty of the technology and the associated high costs per tonne captured. At this current
point in time, DAC cannot compete economically with mitigation alternatives.
Within DAC, numerous processes exist, albeit with varying technology readiness levels. This
has implications for the applicability of the process. To aid in decision-making, a
multicriteria analysis was conducted using AHP-VIKOR. The processes were ranked by
following this methodology, underlining causticisation as the most economically viable
process.
Causticisation involves four steps: contacting, pelletising, calcining and slaking. The most
appropriate equipment was selected for each stage, considering capital cost, energy
requirements and future development to optimise the process for the costing model. The
associated costing model assumed a project life of 25 years, and evaluated DAC at scales
ranging from 1t-CO2/day to 1Mt-CO2/year; that is, pilot scale to commercial scale, in order to
give a more detailed estimate of economic feasibility.
The results clearly demonstrated that the capture cost per tonne of CO 2 was remarkably high,
ranging from $6339 (pilot) to $545 (commercial). Whilst existing plants and reference
systems quote capture costs of approximately $600/t-CO2 down to $94-232/t-CO2, the current
market price of CO2 cannot match the cost. Alternative configurations including the
substitution of equipment, power generation sources, prices of electricity and operating
labour, showed varying results. Nonetheless, no option reduced the capture cost into a
feasible range for the near future.
As such, cost reductions are the primary focus of technological advancement. These may take
the form of a change in materials of construction, further design optimisation by adapting
existing technology, incorporate renewables to reduce operating expenditure and financial
incentivisation. It can be concluded that both innovation and iteration are necessary to ensure
the feasibility of DAC in the long-term, but at present, may lose out to alternative strategies.
Table of Contents
Chapter 1: Introduction ..................................................................................................................... 1
Chapter 2: Literature Review ............................................................................................................ 4
2.1 Background ............................................................................................................................... 4
2.1.1 Climate Change .................................................................................................................. 4
2.1.2 Negative Emissions and the role of Direct Air Capture .................................................. 5
2.2 Direct Air Capture .................................................................................................................... 7
2.2.1 Aqueous Hydroxide Sorbents - Causticisation ................................................................. 7
2.2.2 Solid Inorganic Chemisorbents ......................................................................................... 8
2.2.3 Amine Sorption .................................................................................................................. 8
2.2.4 Membranes ....................................................................................................................... 12
2.2.5 Cryogenics ........................................................................................................................ 13
2.3 Reutilisation of Carbon .......................................................................................................... 14
2.3.1 Enhanced Oil Recovery ................................................................................................... 14
2.3.2 Fuel and Chemical Feedstock .......................................................................................... 15
2.3.3 Mineralisation .................................................................................................................. 16
2.4 Policy Objectives ..................................................................................................................... 17
2.4.1 Political Economy ............................................................................................................. 17
2.4.2 Technological Insights ..................................................................................................... 18
2.5 Gaps in Knowledge ................................................................................................................. 20
2.5.1 Net Carbon ....................................................................................................................... 20
2.5.2 Geographical Location..................................................................................................... 20
2.5.3 Costing .............................................................................................................................. 21
2.5.4 Storage .............................................................................................................................. 21
2.5.5 Policy ................................................................................................................................. 22
2.6 Alternative Strategies ............................................................................................................. 24
2.6.1 Afforestation ..................................................................................................................... 24
2.6.2 Biomass Energy with CCS ............................................................................................... 25
2.6.3 Ocean-based CDR ............................................................................................................ 27
Chapter 3: Process Selection ............................................................................................................ 28
3.1 An Introduction to Multicriteria Analysis ............................................................................ 28
3.2 Assumptions ............................................................................................................................ 29
3.3 Criteria Selection .................................................................................................................... 29
3.3.1 Capital Cost ...................................................................................................................... 29
3.3.2 Market Price ..................................................................................................................... 29
3.3.3 Operating and Overhead Cost ........................................................................................ 30
3.3.4 Energy requirement ......................................................................................................... 30
3.3.5 Overhead cost ................................................................................................................... 30
3.3.6 Geographical Location and Footprint ............................................................................ 31
3.3.7 Transportation and Storage ............................................................................................ 31
3.3.8 Waste Pollution ................................................................................................................ 31
3.3.9 Technology Readiness Level ............................................................................................ 31
3.3.10 Subsidisation and Financial Incentives ......................................................................... 34
3.3.11 Public Acceptance .......................................................................................................... 34
3.4 Categorising the Criteria ........................................................................................................ 34
3.5 Elimination of correlated criteria .......................................................................................... 35
3.6 Assigning Weightings and Ratings ........................................................................................ 35
3.7 Discussion of Results – AHP & Ratings Method .................................................................. 39
3.8 Analysis of AHP ...................................................................................................................... 39
3.9 Potential Pitfalls in Weighting ............................................................................................... 40
3.10 VIKOR ................................................................................................................................... 40
3.10.1 Normalisation ................................................................................................................. 41
3.10.2 Ranking ........................................................................................................................... 42
3.11 Weight Sensitivity ................................................................................................................. 44
3.12 Conclusion of Process Selection ........................................................................................... 45
Chapter 4: Methodology and Process Model .................................................................................. 46
4.1 Assumptions ............................................................................................................................ 46
4.2 Sorbent Selection ..................................................................................................................... 46
4.3 Process Description ................................................................................................................. 48
4.4 Air Contactor Design .............................................................................................................. 49
4.4.1 General Specifications ..................................................................................................... 49
4.4.2 Packing.............................................................................................................................. 50
4.4.3 Driving Force for Air ....................................................................................................... 52
4.4.4 Cycling .............................................................................................................................. 53
4.4.5 Sorbent Geometry ............................................................................................................ 55
4.4.6 Accommodating the optimised model ............................................................................. 55
4.5 Pellet Reactor .......................................................................................................................... 59
4.6 Calcination............................................................................................................................... 62
4.7 Slaking ..................................................................................................................................... 66
4.8 Compression of CO2................................................................................................................ 67
4.9 Oxy-firing – CFB versus Pulverised Coal and Air versus Oxygen ...................................... 68
4.10 Other Auxiliaries ................................................................................................................... 71
4.11 Alternative Configurations ................................................................................................... 71
Chapter 5: Costing and Sensitivity Analysis ................................................................................... 72
5.1 Equipment Sizing and Purchased Equipment Cost .............................................................. 72
5.2 Capital Cost and Operating Cost .......................................................................................... 74
5.2.1 Components of CAPEX ................................................................................................... 74
5.2.2 Components of OPEX ...................................................................................................... 78
5.3 Total Cost of Capture ............................................................................................................. 82
5.3.1 The Result – Cost per tonne of CO2 Captured ............................................................... 84
5.4 Commercialisation – A Cash Flow Analysis ......................................................................... 85
5.5 Sensitivity Analysis ................................................................................................................. 90
5.5.1 Compressor Price ............................................................................................................. 90
5.5.2 Sorbent Selection .............................................................................................................. 91
5.5.3 Combustion Preference.................................................................................................... 93
5.5.4 Sources of Power .............................................................................................................. 94
5.5.5 Cost of Electricity and Operating Labour ...................................................................... 99
5.5.6 The Parameters in Relation to Capture Cost ................................................................. 99
5.6 A Comparison of Capture Cost Estimates and Optimisation ............................................ 101
5.6.1 The Market Price of CO2 ............................................................................................... 101
5.6.2 Design Optimisation and Costing Model Discrepancies .............................................. 102
5.6.3 Improvements ................................................................................................................. 106
Conclusion ....................................................................................................................................... 107
List of Figures
Figure 1- Sources of Emissions ................................................................................................. 5
Figure 2 - Amine Sorption Process............................................................................................ 9
Figure 3 - Comparing Adsorption Capacities ......................................................................... 12
Figure 4 - Comparison of RCP 4.5 and RCP 8.5 .................................................................... 24
Figure 5 - MCA Process Steps ................................................................................................. 28
Figure 6 - VIKOR Flowchart ................................................................................................... 42
Figure 7 - Process Flowchart .................................................................................................. 48
Figure 8 - Decay from Cycling ................................................................................................ 53
Figure 9 - Open versus Closed Contactor Systems ................................................................. 58
Figure 10 - Gains in Cryogenic Air Separation ...................................................................... 69
Figure 11 - Breakdown of Operating Costs – The Effect of Scale .......................................... 81
Figure 12 - Comparison of Capture Cost Composition........................................................... 82
Figure 13 - An Extreme Case – Composition of Cost............................................................. 83
Figure 14 - Sample of Cash Flow Analysis – 1t-CO2/day....................................................... 86
Figure 15 - Equipment Cost Sensitivity – Adjusting the Compressor ..................................... 90
Figure 16 - Sorbent Sensitivity ................................................................................................ 92
Figure 17 - Combustion Preference Sensitivity ....................................................................... 94
Figure 18 - Total Cost of Power Generation at Varying Scales.............................................. 96
Figure 19 - Spider Plot – Sensitivity of Significant Costs ..................................................... 100
List of Tables
Table 1 - Tests performed on efficiency of chemisorbents ...............................................................................8
Table 2 - Technology Readiness Levels ..........................................................................................................33
Table 3 - Pearson Products for Correlation ..................................................................................................35
Table 4 - Scoring scale for AHP .....................................................................................................................36
Table 5 - Results of Weighting Calculation – Geometric Mean Method .......................................................36
Table 6 – Weightings derived by AHP............................................................................................................37
Table 7 - Outcome of AHP Process Selection ................................................................................................38
Table 8 - VIKOR Ratings ................................................................................................................................43
Table 9 - Initial VIKOR Ranking Results .......................................................................................................44
Table 10 - Sensitivity Analysis Rankings ........................................................................................................45
Table 11 - Advantages and Disadvantages of Sorbent Types ........................................................................47
Table 12 - A Comparison of Packing Structures ............................................................................................50
Table 13 - Classification of Risks ...................................................................................................................57
Table 14 - Operation of the Pellet Reactor ....................................................................................................60
Table 15 - Circulating Fluidised Bed Advantages ........................................................................................68
Table 16 - Oxyfuel Combustion Analysis .......................................................................................................70
Table 17 - Purchased Equipment Cost Results ..............................................................................................72
Table 18 - Capital Costing Weighting Assumptions ......................................................................................74
Table 19 - CAPEX Results at 1t-CO2/day ......................................................................................................76
Table 20 - Capital Power Factors .................................................................................................................76
Table 21 - CAPEX Results at Varying Scales.................................................................................................77
Table 22 - Operating Cost Weighting Assumptions .......................................................................................78
Table 23 - OPEX Power Factors ....................................................................................................................79
Table 24 - OPEX Results at Varying Scales ...................................................................................................80
Table 25 - Capture Cost Results ($/t-CO2) at Varying Scales .......................................................................84
Table 26 - Cash Flow Analysis Assumptions .................................................................................................85
Table 27 - Loan Case – Adjusted Break-even Prices .....................................................................................87
Table 28 - Comparison of Financial Metrics at Varying Scales ....................................................................88
Table 29 - Break-even Price of CO2 with a 5-year Payback Period .............................................................89
Table 30 - Results of System Remodelling - Compressor...............................................................................91
Table 31 - Results of System Remodelling – Sorbent .....................................................................................91
Table 32 - Results of System Remodelling – Combustion Method .................................................................93
Table 33 - Assessment of Feasibility of Power Generation Techniques ........................................................95
Table 34 - Results of System Remodelling – Source of Power .......................................................................97
Table 35 - Notable Issues with Proposed Sources of Power ..........................................................................98
Table 36 - Comparing Design and Model Specifications ............................................................................105
Chapter 1: Introduction
Despite the realisation that carbon dioxide emissions are significantly impacting the climate,
society has continued to employ fossil fuels at an increasing pace. The IPCC highlighted the
need for swift and direct reductions in fossil fuel use in 1990, however, anthropogenic CO 2
emissions have continued to inflate rapidly with no effective change [1]. Mitigating CO2
emissions has become a major focus in industry, as regulatory bodies enforce reduction
targets from both point and distribution sources. Most recently, the Paris Agreement outlined
robust accountability and transparency rules, ensuring countries adapt to climate change with
an overarching aim of limiting global warming to a 1.5-2°C temperature increase [2].
Nonetheless, global greenhouse gas emissions, measured in CO 2-eq, are expected to increase
by 25-90% between 2000 and 2030 [2].
Accordingly, decarbonised systems are being adopted in a wide range of industries to meet
these regulations and achieve ‘green’ targets [3]. However, its utilisation is unable to match
the energy demands of a growing population [3], and consequently, there remains a small
probability of substantially curbing CO2 emissions in the short-term [3]. Recent talks in Paris
have identified the requirement of ‘negative carbon technologies’ [3], which remove carbon
dioxide directly from the atmosphere. The National Research Council (NRC) reports on
climate intervention confirm this account [3], suggesting that overshooting reduction targets
and subsequently approaching climate change from a negative emissions perspective, is the
most suitable long-term strategy.
Direct air capture (DAC) is one such technology that has the potential to stabilise
atmospheric CO2 concentrations, aiding in countries’ endeavours to counteract climate
change. This is in stark contrast to currently employed carbon capture and storage (CCS)
operations, which have a marginal effect on emissions reduction; instead slowing the rate of
increase. A key advantage of DAC lies in its ability to reduce emissions from both point and
distribution sources, from which 50% of anthropogenic CO2 arises. Furthermore, techniques
within DAC are simplified – the removal of SOx and NOx, contaminants commonly
eliminated in CCS, need not be considered.
However, DAC is not without its own challenges. To effectively control atmospheric CO2
concentrations, DAC technologies must be scaled up. This requires the consideration of
financially viable operation methods. Moreover, long-term and environmentally sustainable
storage techniques must be applied [3]. A variety of promising processes, ranging from amine
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sorption to cryogenics, are being researched and modelled to satisfy these requirements [4].
In developing such processes, additional impediments to commercialisation must also be
considered; these include footprint, storage, regulations and public acceptance, all of which
necessitate further testing. For DAC to be an effective mechanism in a negative emissions
context, it must be introduced slowly. Consequently, it cannot react quickly to current
reduction needs.
Terrestrial biological alternatives may be able to fulfil this role in the short-term; their
operation is currently less costly and time consuming. Strategies such as reforestation store
additional carbon on the land, whilst enhancing natural carbon sinks reduce emissions by up
to 15 giga-tonnes per year [1]. DAC could be employed in conjunction with these strategies,
but is not practicable as a stand-alone compensation technique. Accordingly, there exists a
necessity to vigorously investigate and identify processes that scale effectively and present
the most viable economic solution.
This literature review compares and analyses a variety of DAC methods for future
applicability in the context of mitigating climate change. In doing so, the review will shed
light on gaps in knowledge and demand, which have discouraged the commercial
implementation of these processes. Factors such as chemical and material utilisation, plant
footprint, energy requirements, environmental waste and carbon storage options, will be
examined and deconstructed. A sensitivity analysis for each process, considering both
technology readiness level and costing, will then be explored to provide a fundamental
decision basis for the project deliverable – a multi-criteria analysis (MCA). This aims to
highlight the most economically feasible process for DAC, should operations begin
immediately. Each criterion will be determined and justified based on information from this
review. To construct and effective MCA, forming the foundation for further investigation, the
following objectives have been set:
•
Identify five specific technologies that have been employed at a pilot scale level;
preferably with industrial capture counterparts.
•
Analyse each process, and detail specifics that can be directly translated to justifiable
criterion and weightings within an MCA.
•
Identify notable gaps in knowledge for each process that could be explored,
particularly in the commercial realisation of the process.
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The second portion of this Thesis will consist of a techno-economic analysis for the chosen
process, with the aim of developing a feasible financial model for its commercialisation.
Chapter 4 details the methodology, from operating assumptions to equipment selection and
material and energy balance calculations. These design configurations have profound
implications for the resulting capture cost, and are carefully selected to ensure the most
optimal process. Chapter 5 develops a costing model to determine an estimate for the capture
cost per tonne of CO2, and thereby demonstrate the economic feasibility of the system. A
cash flow analysis has also been included given the necessity in examining the break-even
price of this technology; that is, at what market price of CO2 will DAC generate a profit.
Alternative configurations, optimisations and future improvements are also highlighted and
analysed in this section, in light of the discussed barriers to implementation. By the end of
this Thesis, I hope to conclude on whether DAC is viable in the broad context of climate
change, at this present point in time.
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Chapter 2: Literature Review
The implementation of DAC must be assessed in the context of both short-term and longterm impact on climate change. These two periods vastly change the feasibility of such a
process; its ability to efficiently reduce emissions, footprint, sequestration requirements and
in turn costing are heavily dependent on the need for short or long-term gain. This section
will provide contextual information on the present issue, the relevance of DAC and potential
alternatives under investigation.
2.1 Background
2.1.1 Climate Change
Currently employed energy and infrastructure systems rely primarily on fossil fuels.
Significant anthropogenic CO2 emissions accompany the burning of these fossil fuels at a rate
quicker than the natural carbon cycle. The increasing concentration of greenhouse gases has
given rise to a host of issues including rising sea levels, ocean acidification, fluctuating
climate extremes and unpredictable changes in biodiversity [5]. Although a certain degree of
greenhouse gases are required to maintain a suitable surface temperature, the growing
concentration has caused an increase of 0.8°C in the past 100 years, with 0.6°C in the last
three decades alone [5]. Researchers have further suggested a 5-6°C increase by YEAR,
should action not be taken [5].
The concentration of carbon dioxide in the atmosphere is approximately 400ppm. This value
is significantly higher than the pre-industrial level of 270ppm, which defined a stable period
for the Earth’s atmosphere [1,5]. The annual release of 30 giga-tonnes of CO2 has
substantially contributed to this rise, with deforestation for commercial purposes adding
another 4 giga-tonnes [1,5]. Consequently, the radiative forcing of CO2 itself – defined as the
radiative energy flux over the Earth’s surface – has increased to 1.7 W/m2, markedly raising
surface temperatures. As a response, the International Energy Agency (IEA) released a
proposal in 2009, suggesting a 50% reduction in emissions by 2050 to keep atmospheric
CO2 concentration in a manageable range [6]. Furthermore, the Paris Agreement stated that
partied countries must set mitigation targets from 2020 and review these every 5 years [2].
However, countries including Australia have steered off-course, with government data
indicating a 30% - 140 million tonne - overshoot of the 2030 target based on current growth
[2].
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Figure 1- Sources of Emissions [2]
2.1.2 Negative Emissions and the role of Direct Air Capture
Ensuring these results are achieved requires heavy investment in mitigation technologies.
Whilst CCS may prove apt in reducing abatement costs and centralised emissions, the drawnout change toward a low carbon energy portfolio has solidified the path toward overshooting
climate change targets. Decentralised energy uses in vehicles, buildings, and small industrial
facilities warrant decentralised capture [6]. Accordingly, there is now an inherent appeal of
the possibility of going negative; reversing society’s contribution to increased atmospheric
CO2 concentration.
DAC generates further options as a negative emissions technology; reducing the quantity of
CO2 presently in the atmosphere. All 1.5°C and 2°C containment scenarios rely on the
application of these negative emissions technologies (NETs). However, the universal
potential of NETs under development remains relatively unknown [7]. Modest and safe
climate stabilisation targets must be met through sustainable practices, but the costs
associated can only be estimated at this point in time. Furthermore, much remains unknown
about the carbon-climate feedbacks in introducing a carbon-negative system, as well as the
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socio-institutional barriers to the large-scale deployment of NETs, particularly concerning
governance and public acceptance. Five research priorities have been identified:
1. Quantification of footprint and land requirements for NETs, in particular DAC and
biomass energy with carbon capture and storage, as well as alternative mitigation
techniques including afforestation – use spatially explicit models [7].
2. Strict adherence to the UN Sustainable development goals; sustainability by
maximising the co-benefits of direct CO2 capture and sequestration or reuse and
efficient energy usage, whilst minimising harm done on land and aquatic ecosystems;
preserving biodiversity [7].
3. Develop contingency plans for the future, given that carbon cycle responses to
negative emissions will cause an increase in CO2 emissions – a slow-down in the
growth of emissions means an increase in the future to equilibrate [7].
4. Conduct further research into governance and policies, as it maintains a large influence
on the uptake and implementation of DAC strategies [8].
5. Cross-cutting research opportunities include developing new metrics and examining
issues of public acceptance and siting [7].
In this way, DAC would be able to complement existing technologies that help decrease the
content of atmospheric CO2. At the point where capture and sequestration balance the level of
emissions, the deployment of NETs will decrease atmospheric concentrations – an overshoot
would be impossible without their utilisation. Nonetheless, only a full-scale decarbonisation
of all economic activity, within a maximum of one generation, could possibly lead to
achieving the 1.5°C target [2]. Given that one generation equates to two to three decades, it is
entirely implausible to assume that technology could be scaled up to the extent required;
removal necessitates 10-20 Gt/year, with eventual cumulative volumes of 450-1000 Gt [1].
Therefore, only economically attractive – either through process equipment cost reductions,
policy instruments or financial incentives – or environmentally sound strategies for DAC will
facilitate their large-scale deployment in the near future.
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2.2 Direct Air Capture
The specific objective of CO2 capture from ambient air is its concentration from 400ppm to
purities > 90%, allowing its use in sequestration or recycling [9]. Studies have suggested that
the minimum thermodynamic requirement for extraction is relatively low – 1.6 GJ per tonne
of CO2 [9]. In comparison to industrial capture processes, the minimum energy required is
only marginally greater; the level of dilution is logarithmically related to energy.
Theoretically, this demonstrates that DAC is thermodynamically feasible, though it should be
noted that practical values will be considerably larger.
Nonetheless, CO2 capture directly from the air is considerably more problematic. As a
consequence of its ultra-dilute nature in the atmosphere, the high moisture content and the
necessity for standard operating conditions, the adaptation of several CCS strategies can be
eliminated [10]. Physical adsorbents, including zeolites and activated carbon, are irrelevant as
they maintain low selectivity for CO2, a very low heat of adsorption and therefore low
adsorption capacities [10]. This is particularly so in the presence of moisture and at
atmospheric pressure. Furthermore, the Selexol process at relatively high pressures cannot be
applied [10]. MEA based sorbents are highly reactive upon contact with air, and suffer from
evaporative losses when large volumes of gas are involved. However, this system is the most
commonly utilised [9].
2.2.1 Aqueous Hydroxide Sorbents - Causticisation
Since atmospheric concentrations of CO2 are significantly lower than localised industrial
emissions, sorbents with strong binding affinities are required for direct air capture. A
typically employed sorbent is calcium hydroxide in passive or agitated pools. This maintains
a high binding energy with CO2 and results in the precipitation and accumulation of calcium
carbonate [11]. Subsequent separation and drying is exceptionally energy intensive however,
with calcination – producing calcium oxide - requiring temperatures reaching 700°C; CO2 is
released as a concentrated stream. Through a process known as slaking, calcium hydroxide
can be regenerated and reused in successive cycles. A significant proportion of the energy
input is diverted to this regeneration step, representing the principal trade-off for capturing
and binding dilute CO2 [11]. Moreover, the theoretical thermodynamic minimum required for
the conversion of calcium carbonate to oxide is 109.4 kJ/mol; substantially less than the
actual value of 179 kJ/mol of CO2. The use of calcium hydroxide is further limited by its low
solubility in water, decreasing the quantity of hydroxide present to bind the CO 2 [11].
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Another notable causticisation strategy is the Kraft process, which implements sodium
hydroxide as the sorbent. Whilst its binding affinity is marginally lower, it is indeed sufficient
for adequate capture and has the advantage of high solubility in water – sodium carbonate [1].
Reacting this species with calcium hydroxide regenerates the sodium hydroxide, with the
exchange of ions typically occurring at an efficiency > 95% [1]. However, the issue of energy
usage is still prevalent, derived from the regeneration component.
2.2.2 Solid Inorganic Chemisorbents
The utilisation of solid inorganic bases, rather than solutions, has been recently investigated.
Analysis of thermochemical cycles were conducted for both calcium and sodium, pertaining
to thermodynamics, kinetics and thermogravimetries [12].
Sodium
Calcium
25°C carbonation of sodium hydroxide, air
Carbonation of calcium oxide and
containing 500ppm CO2; slow kinetics –
hydroxide; favourable kinetics and catalysed
reaching concentration of 9% after 4 hours.
in present of water-saturated air; up to 80%
could be carbonated.
Carbonation of solid sodium bicarbonate in
water-saturated air; 3.5% conversion after 2
hours.
Table 1 - Tests performed on efficiency of chemisorbents [12]
A number of disadvantages are associated with the implementation of these processes,
requiring further research and development. In this sense, the technology readiness level is
markedly below that of alkali metal hydroxides and aqueous sorbents [12].
•
Sodium cycles – low carbonation rate, and accordingly high mass flow rate result in
large equipment costs and kinetic inefficiencies.
•
Calcium cycles – reaction temperature in the range of 300 - 450°C – a noticeably
higher amount than sodium and therefore large heating requirements.
2.2.3 Amine Sorption
Amine-based carbon capture in solid sorbents is the most commercially proposed for DAC.
The bulk of research has been focussed on the utilisation of solid-supported amine materials.
These allow for significant uptake of CO2 even at low partial pressures and concentrations
through bond formation inherent to the chemical reaction [13].
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Therefore, the selectivity toward CO2 and heat of adsorption are higher than physical sorbents
[14], making these hybrid materials effective for DAC purposes.
The principal benefit associated with physical adsorption is the non-occurrence of chemical
reactions. For this reason, the majority of reactive species can be efficiently loaded into the
pores of a material or onto its surface [15]. Nonetheless, nature of the amine contributes
significantly to the adsorption capacity of the material. It has been suggested that primary
amines are the most effective under DAC conditions; however, Olah et. al (2016) suggested
that secondary amines have the most favourable trade-off between reactivity and energy
requirements.
A diverse range of amine compounds have been tested for their suitability, and undergo TSA
– the most commonly applied for DAC processes. PSA is not considered a viable option for
DAC due to the energy intensive compression of the inlet air. Research has also been
conducted into temperature-vacuum swing absorption (TVSA), giving rise to concentrated
CO2 streams. The current challenge with this process is that the actual capacity of CO2
captured is significantly lower; however, this may be offset by the increased purity.
Naturally, this has inferences for DAC, predominantly in relation to CO 2 utilisation or storage
options. Purity heavily influences the environmental safety of geological storage, and
determines its efficacy in prominent reuse strategies, including enhanced oil recovery.
Figure 2 - Amine Sorption Process [14]
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Amines Physically Adsorbed on Oxide Supports
Monomeric or polymeric amines adsorbed onto support materials are typically silica or
nanocellulose. Relatively low volatility compounds have been utilised to limit the
regeneration losses and sorbent degradation that plague this functional group within the
identified adsorption methods [14]. Poly(ethylenimine) (PEI) has been the implemented most
frequently as it maintains advantages over smaller amines, particularly MEA. These include –
high density and high stability under TSA, something smaller amines are unable to uphold.
[14] MEA suffers large evaporative losses under reasonable temperatures and amine loss
during regeneration. The hydrogen bonds formed between PEI and silica supports gives rise
to the property of high stability and resistance to degradation in contact with air and water.
This, in congruence with favourable kinetics and loading capacities makes it the most feasible
for DAC purposes, and justifies its current employment [15].
The operating temperature for sorption has implications for the efficiency of CO 2 capture.
Song et. al (2010) conducted research suggesting that the optimal uptake of CO2 transpired at
elevated temperatures. The same result was achieved by a multitude of additional
experiments, demonstrating effects contrary to theoretical propositions. This was attributed to
competing thermodynamic and kinetic factors; sorption increases at lower temperatures, but
diffusion significantly increases at high temperatures, and therefore reaction rates [16].
The moisture content, more specifically the humid conditions under which the process may
take place – in reference to Background on DAC location (2.2.4) – also maintains a heavy
influence over capture efficiency. A considerable increase – almost double – was recorded
upon changing conditions from dry to humid when 33% PEI was used as a sorbent. However,
an opposing effect was noted in the case of 50% PEI; CO2 uptake decreased by relatively
notable margin [18]. The discrepancy between the two can be ascribed to the arrangement of
sorbent particles within the material space:
•
Low loading – generates well-dispersed particles on the surface of the silica
framework, allowing access to the majority of amine groups [18].
•
High loading – decreased capacity to diffuse and therefore reduces the capture
efficiency [18].
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Amines Supported on Solid Organic Materials
Additional support materials have been considered and developed for DAC technologies.
Prior to the necessity for reductions in anthropogenic emissions, removing CO 2 was primarily
used in space and submarines [19]. Employing activated carbon, ion exchange resins and
polymers including poly(methyl-methacrylate), all of which are heavily loaded with amines,
proved successful in these ventures. However, concentrations were significantly higher than
the atmospheric concentration of CO2; 5000ppm – 20000ppm, in comparison to 400ppm [20].
Nonetheless, further research has been conducted to commercialise this process, yielding
favourable results with respect to uptake capacities [20]. Such pathways include:
1. Funtionalisation of polymers with amines – the polymers must contain high-surface
areas and facilitate efficient reactions in terms of both thermodynamics and kinetics.
The results obtained through the use of diethylenetriamine and porous polymer
networks were indicative of high selectivity and sorption capacities [20].
2. Functionalisation of carbon black using atom transfer radical polymerisation (ATRP)
– consists of two potential routes.
a. Nitrene chemistry – humidity swing process utilising hyperbranched
polymers, subsequently transformed into quaternary ammonium hydroxide
groups; these are preferred for CO2 sorption [20].
b. Acid oxidation – formation of polymer shell on the surface of the carbon
black, thereby stimulating the site and strengthening ATRP ability [20].
Metal Organic Frameworks
Despite the substantial emphasis on employing chemisorbents (amine groups impregnated or
tethered within oxide supports and polymers), physisorbents have been thoroughly
investigated of late, gaining many proponents [21]. These maintain a markedly lower energy
usage, specifically in the regeneration step; chemisorbents require elevated temperatures,
typically greater than 100°C [21]. Even so, determining the applicability of physisorbents in a
DAC context – ultra-dilute concentrations – has proven challenging. Metal organic
frameworks (MOFS) possess latent versatility, due to their composition of metal clusters as
nodes, bridged by organic moieties [21]. As such, they have been favoured to overcome the
characteristic obstacles faced by the majority of physisorbents. Both the surface area and the
functionality of pores can be manipulated to give desired results, justifying their application
in various experiments; though not at a viable technology readiness level as of yet.
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Figure 3 - Comparing Adsorption Capacities [22]
However, humidity plays an important role in determining the overall feasibility of MOFs.
Studies that altered conditions from dry to humid highlighted several associated shortfalls,
including regeneration and recyclability [22]. Moreover, the quantity of binding sites readily
available severely diminishes in the presence of water; these contend with CO 2 for the openmetal sites, and occurs in comparable fashion to commonly used physisorbents including
zeolites [22]. In this way, strategies must be devised to resolve stability and selectivity issues
in such unfavourable conditions, which are entirely plausible and likely to happen.
2.2.4 Membranes
Membrane technology has been successfully implemented at lab-scale levels, providing a
low-cost means of separating gases when high purity streams are not vital. CO 2 recovery is
strictly governed by the properties of the membrane, specifically selectivity and permeance.
With pressure being the driving force for permeability, much like in CCC, energy costs make
up a substantial proportion of total cost. Most polymeric membranes pertaining to CO 2/N2
separation show selectivity in the range of 5-50 [23]. However, the utilisation of 6% PEI
impregnated membranes demonstrated a selectivity of 300; a significantly higher value and
proof of potential application in the future. Nonetheless, compression of ultra-dilute gases
will only increase the energy requirement, and thus adsorption processes provide higher
levels of performance [23].
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2.2.5 Cryogenics
Little trials have been undertaken to determine the feasibility of cryogenics in direct air
capture in the context of reducing anthropogenic emissions. It was employed commercially in
the 1930’s to remove CO2 from the atmosphere for the purpose of mitigating equipment
fouling [24]. This took place in cryogenic air separation plants, targeting N2, O2 and Ar
specifically, and at a much smaller scale than what is currently being suggested. However, it
is an important consideration for the future of DAC, due to its ability to efficiently separate
impurities – liquefying gases eases the separation process and saves on energy by limiting
compression requirements [24]. Furthermore, its ability to be retrofitted on existing structures
reduces the already enormous footprint requirement for DAC facilities [24].
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2.3 Reutilisation of Carbon
A myriad of pathways exist for the reuse and storage of CO2; however, these are not without
challenges. Most utilisation opportunities require high-purity CO2 as a feedstock – the
number of opportunities decreasing the lower the purity. As a consequence of DAC’s nature
as a new technology, the potential to obtain a sufficient purity for reuse is severely limited.
2.3.1 Enhanced Oil Recovery
Enhanced oil recovery (EOR) is the only well-established and economically feasible
opportunity for the reuse of captured CO2. A study conducted by the Global CCS Institute
revealed that the cumulative global demand for CO2 in this process may exceed 500Mt by
2020 [25], indicating its current and future applicability as a salvage strategy. Mixtures are
injected into a reservoir to re-pressurise rock formations and release any trapped oil. This
occurs through the mechanism of miscibility, changing the viscosity and permitting oil to
travel liberally toward the production well [25]. CO2 flooding using the water-alternate gas
method has proven to be the most efficient, yielding more per barrel than traditional oil
recovery processes; the stream is pumped to the surface with a fraction of CO 2 separated and
recycled.
Dilute CO2 for EOR, consisting of a gaseous mixture of N2 and CO2, recovers between 80
and 85% as much as pure CO2. However, residence times are considerably quicker, which
may result in decreased operational costs. For every tonne of CO2 utilised in oil recovery, on
average, 0.51 tonnes of CO2 are emitted [26]. Recovery can be further increased upon the
addition of intermediate hydrocarbons, typically propane, which improves both the
displacement efficiency and diffusion coefficient [26]. However, not all CO2 is permanently
sequestered. The quantity that remains underground is heavily contingent on reservoir
properties such as permeability and size, whilst overall process efficiency largely depends on
temperature and pressure. Optimising conditions generate greater viscosity decreases and
higher oil swelling, all of which lead to more sound process [26].
In the case of DAC, additional separation processes are required to remove the presence of
oxygen. Analysis by the IPCC have shown an increase in the minimum work by
approximately 10% when removing O2 from a stream of 50% purity with respect to CO2 [27].
Despite its commercial applicability, the reuse for EOR faces some challenges:
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•
The heterogeneity of the rock formation, fluid properties and capillary pressure
reduce the effectiveness of flooding.
•
A large number of parameters need to be taken into consideration and optimised;
these include fluid production rates, compensated neutron log, production log.
•
It only contributes to 3% of CO2 utilisation – largely due to the price of CO2 but
its use is not limited to major reservoirs [28].
2.3.2 Fuel and Chemical Feedstock
Fuels are considered to be the best route for CO2 utilisation. The main compounds produced
consist of methane, methanol, syngas and alkanes; these are principally implemented in fuel
cells, power plants and the transportation industry. Since CO2 is a thermodynamically stable
molecule, generating a worthwhile reaction requires large amounts of energy and the
presence of a catalyst. The two most common methods for this are hydrogenation and the dry
reforming of methane.
Sourcing hydrogen from fossil fuels appears to be a challenge itself, as it leads to increased
CO2 emissions. Hydrogenation provides the possibility of recycling CO2, storing hydrogen
gas, and solving the issue of electrical energy storage through the implementation of
renewable technology. One such successful example is Audi’s employment of this process to
produce 1000 Mt/year of methane, [29]. However, activating the C-H bond over a current is
difficult; the catalysts previously and currently being tested are not economically viable. The
endothermic nature of the reaction and low conversion at moderate temperatures bottleneck
production at a large scale. As such, there is a necessity for active catalysts that maximise
yield and hasten reaction kinetics.
Methane has proven to be ineffective, particularly in the transport industry due to its low
volumetric gas density. It also maintains a global warming potential of 30 (units), and as a
consequence, the production of methane will not be environmentally sound as a reutilisation
option for captured carbon [30]. As a result of its common availability in the market, methane
prices are significantly lower than alternatives. In this sense, production would generate
losses; quantity produced will not recuperate the initial investment and operating expenses
[30]. The dry reforming of methane is primarily used to produce methanol and liquid fuels
through the Fischer-Tropsch process, generating purities greater than partial oxidation and
steam reforming. The amount of methane unreacted is only 2%; makes it possible to apply
DRM at remote natural gas sites for the production of liquid fuels, which are easier to
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transport. Methanol has many applications in paints, plastics, combustion engines and organic
solvents; but production only reduces emissions by 0.1% [30].
Chemical formation primarily produces urea (160 Mt/year), inorganic carbonates (60
Mt/year), polyurethane (18 Mt/year), acrylates (10 Mt/year). Urea has major use as fertiliser
and feedstock for polymer synthesis, pharmaceuticals, fine chemicals and inorganic
chemicals such as melamine and urea resins. Although there exists a profitable and flexible
market for the production of chemicals and fuels from CO2, the proposed methods cannot be
recognised at a commercial scale. This is largely due to the following:
•
Materials investigated are expensive to make, yet not chemically stable [31];
•
CO2 conversion rates and overall yields of the main products are low and thus do not
meet the requirements for large-scale deployment [31]; and
•
Limited understanding of the reaction mechanisms involved in the chemical
transformations of CO2.
2.3.3 Mineralisation
The stable production of mineral carbonates by treating CO2 with metal oxides, such as
calcium and magnesium, presents an alternative to typical storage options. Considering
calcium and magnesium are naturally abundant in the form of mineral silicates, the
carbonation of CO2 is a thermodynamically favourable and naturally occurring process at
standard temperature and pressure. Given ambient operating conditions however, the process
is tremendously time-consuming. Modifications to offset slower reactions include injecting
fluids with higher concentrations of CO2 and increasing the temperature, the first of which is
problematic in a DAC context as a result of its dilution in air [28]. However, mineralisation
has several substantial shortcomings:
1. It requires the extraction, processing and transportation of rocks as well as high
pressures (100-150 bar) for superior efficiency (> 80%) [28];
2. The duration of reactions are in the range of 6-24 hours, despite the adjustments; and
3. Maintains a large footprint, and additives are needed to extract reactive species and
separate products, giving rise to high penalty costs [28].
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2.4 Policy Objectives
Thermodynamics and economics are not the only facets of mitigation techniques that must be
considered. The policy surrounding, and public reception of these processes have proven
instrumental in determining the success of their application. Despite the goals outlined in the
2016 Paris Agreement – maintaining no more than a 1.5°C - 2°C increase in global mean
temperature – international policy instruments that mobilise negative emissions schemes are
non-existent.
2.4.1 Political Economy
Key stakeholders and the public have criticised NETs since its conception. The current stance
perceives mitigation processes such as DAC and BECCS as a ‘Plan B’ or back-stop
technology [32], severely diminishing the likelihood of financial backing from venture
capitalists or government subsidisation. In comparison to CCS, the technology readiness level
of options such as BECCS or DAC are significantly inferior. As such, the main criticisms of
NETs concern their social, environmental and political possibilities, emphasising the limited
contribution of NETs [32]. The potential for implementation strictly depends on the ability
for research and development to overcome associated difficulties, notably:
1. Development – ensuring the processes are thermodynamically efficient;
2. Costs – large initial capital expenses and operating expenses; and
3. Resource conflicts – crowding out funds from other alternatives that may indeed be
more viable both short and long-term.
Nevertheless, there has been a shift away from their primarily negative framing as an
ineffective large-scale technology. In particular, the success of the CarbFix2 project in
Iceland, where 10kT CO2 is capture and stored annually, has helped facilitate the introduction
of DAC to the public [33]. A number of companies have since taken interest in such ventures,
culminating in the construction of a commercially successful plant in Switzerland
(Climeworks) [33]. The success of future endeavours will seemingly be based on allocated
funding to research and development. Considering the lack of prior attention to NETs, any
funding could have significant social payoffs.
Nonetheless, a number of interest groups continue to maintain an opposing position to the
operation of mitigating strategies. The power sector has provided stiff opposition to the
implementation of BECCS, primarily due to costs imposed on existing facilities by
regulations. If NETs demonstrate a potential to efficiently reach emissions reduction targets,
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industry will more readily consider their employment and compensate for energy losses
through additional means [34]. Furthermore, adapting such technologies to economies of
scale might persuade interest groups to change their position, and cease opposition to their
implementation. On the other end of the spectrum, NGOs will detail environmental and social
concerns, the most prominent being sequestration; close to residential areas and may have the
greatest impact on local ecosystems [35].
2.4.2 Technological Insights
The state of the political economy CCS faced upon introduction, both domestically and
internationally, has lasting implications for the acceptability and large-scale deployment of
DAC, as it forms the foundation for these technologies. Accordingly, the design of policy
instruments must consider the challenges faced as a result of perceptions and resource
competition [32].
Prior to the first policy discussions, the theoretical necessity of CCS was firmly advocated.
Despite initial assessments highlighting that deployment involved a doubling of global costs,
in an attempt to achieve the 450ppm reduction target, overlooking its implementation would
prove to be far costlier [32]. CCS technologies can be installed in pre-existing plants,
demonstrating its versatility in reducing emissions, furthered by an absence of viable
alternatives in the same market. However, introduction was slackened due to lacking policy
frameworks and funding; there exists a need for comprehensive and transparent decisionmaking processes to reduce interest group opposition [36]. Additionally, early projects began
to depend on (to differing degrees) enhanced oil recovery, which provides revenue on
recovery. Incentivising projects rather than voluntarily committing to climate change
mitigation dominated their utilisation. As a consequence, the quantity of processes currently
under development and those underway have halved due to political opposition, cost overruns
from local protests prolonging already rigorous planning processes and technological
problems. Finding such early failures could irreparably damage the standing of DAC if not
taken into consideration.
The biofuel industry faced similar political challenges. Concerns arose over market
competition with agricultural cropland, as a result of an increased uptake in biofuel
production. Consequently, environmentalists began to question the sustainability of
harvesting biomass during the Global Financial Crisis in 2008 (GFC)as global food prices
peaked; perpetuating deforestation and thus endangering species [37]. Continued support for
their utilisation occurred in countries with large reserves of biomass and where food security
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could be sustained, for example Brazil. However, countries including China with onerous
schemes slowed rollouts. The alteration of present ecosystems to crop-based biofuels were
reported to release 17 to 420 times more CO2 annually than the reductions obtained from
their implementation [38]. Strategies involving the conversion to crops grown on small
parcels of land proved unprofitable and of little interest for poorer nations, whilst government
agencies, agribusiness and sovereign wealth funds diminished the reputation of biofuels
amidst growing apprehensions of land grabs.
As a consequence, EU called a five-year moratorium on expanding biofuels [38]. The
European Parliament voted to decrease the proportion of biofuels in the transport industry
from 10 to 5% but this never eventuated. They were however, able to limit the use of
conventional land-based biofuels in transport fuel mix to 6% in 2013 with stringent 2020
targets being removed altogether; practically preventing a biofuel contribution toward the
2030 target as a mitigating factor. In this sense, the power of policy to influence the
technological development of biofuels and how governments may receive its implementation,
could very well be applied to DAC.
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2.5 Gaps in Knowledge
Although research and development is continually being undertaken, the subject of carbon
dioxide removal (particularly from ambient air) is still relatively novel. The technology
readiness level of the majority of proposed processes are exceptionally low, with little past
the lab-scale [3]. The gaps aps associated with these potential DAC technologies are assessed
in Chapter 3 – Process Selection. However, it should be mentioned that these predominantly
consist of high energy requirements and the cost of materials and equipment. Efforts designed
to reduce anthropogenic emissions through DAC have been, and should continue to be, based
upon experiences gained from similar industries [7] – most notably CCC. Whilst some
processes proved to be inapplicable, the insights regarding net carbon, location, costing,
storage concerns, regulations and public acceptance were profound.
2.5.1 Net Carbon
In the process of capturing and storing CO2, additional CO2 may be released into the
atmosphere from supplementary sources – this must be accounted for. Typical energy
utilisation for DAC is markedly high, with the primary source being fossil fuels; systems
currently sourcing energy by this means are therefore severely compromised [1].
Several strategies have been identified in an attempt to combat this issue:
•
Generate heat and work from fossil fuels and capture the CO2 at the site itself [1].
•
Develop a unified system to transport and store CO2 from both the plant and the
system [1].
•
Utilise a decarbonised energy source – nuclear power, construction of a geothermal
plant, solar-thermal plant in congruence with hydropower storage [1].
At the current level of technology, only one of these options is commercially feasible. It
should also be noted that such plants necessitate a sizeable initial capital investment and
working capital, in addition to maintaining high operating costs. Intermittent power such as
solar or wind may not be efficient unless a fundamental energy source also exists [1]. This
represents the main gap in knowledge that must be addressed.
2.5.2 Geographical Location
It is prohibitively expensive to either cool, heat, dry, moisten or remove impurities from large
quantities of inlet air, heavily dependent on the direct capture system. Therefore, finding the
most suitable surrounding conditions for the plant itself is essential for the efficiency
operation of the system [18]. The presence of moisture greatly influences the system design.
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For example in sorbents, greater water content means competition for reactive sites and
therefore decreased capture performance [18]. In addition, it adds to the thermal mass of the
sorption system during regeneration, which increase costs.
Further concerns involve the heightened presence of oxygen, which has several implications:
•
It shortens the commercial lifetime of some chemicals [1];
•
Contaminants that oxidise may erode the surface of equipment [1]; and
•
It may lead to plugged passages within the contactor [1].
Certain regions are more favourable, as they exhibit relative seasonable and diurnal stability
such as the tropics [39]. However, this runs into challenges itself, given the amount of
clearing required to construct a facility or convert land.
2.5.3 Costing
The primary resource in a DAC facility is electricity, providing an energy input to the system
for all facets of the process [1]. Additional costs are accrued through the operation of utilities
streams, including cooling water, steam and hot air. Finding alternative supplies through the
use of low-grade waste energy, biomass and renewables proves to be challenging, as it is site
specific. The full benefit from establishing such a facility will only in incurred if the
production does not generate GHGs [1]; high carbon-power may actually result in a regional
increase in emissions, rather than the intended negative. Further costs that must be considered
include:
•
Air capture and infrastructure itself; and
•
Transport and storage – kept low if plants can sequester carbon nearby and renewable
energy is available onsite.
Compared to alternative mitigation options, costs are exceptionally high given the huge
volume of inlet air per unit of CO2 actually extracted. The potential for cost reduction at this
point in time appears to be limited, and therefore presents a gap in knowledge [1].
2.5.4 Storage
There remain gaps in knowledge pertaining to specific regional storage capacities in many
parts of the world. In this light, a number of considerations must be made:
•
More appropriate estimation and quantification of leakage rates [28];
•
Better understanding the mechanisms by which fundamental sequestration occurs – in
particular the kinetics of trapping and the long-term influence of CO2 on reservoirs;
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•
Improving cost data for establishing storage spaces, especially those outside the
bounds of EOR and those pertaining to regulations [28];
•
Establishment of liability and responsibility frameworks, specifically with respect to
monitoring and operating the sites [28];
•
Betterment of remediation and intervention options; and
•
Increased development of pilot-scale projects [28].
All of these recommendations point to improvements in technology and policy in order to
provide greater transparency for the public, as well as decrease industrial uncertainty.
However, there seem to be no insurmountable barriers to the increased uptake of geological
storage as an effective mitigation option [40].
2.5.5 Policy
Various means exist to ease the implementation and further the development of DAC and
NETs more generally. These serve as suggestions to fill the gaps in knowledge and flaws
associated with policy.
Firstly, industrialised countries must take the lead in funding DAC. A preliminary financial
stimulus package may be announced to generate interest and begin preparations for
mobilisation. In the meantime, disadvantaged countries can profit from direct transfers or the
sale of ‘carbon credits’. As these countries gain access to funding, they can then increase
carbon prices and build on this over time, though this requires the continual support of
developed nations. However, the public is extremely reactive to the rewards arising from
sustainable practices or the harm caused as a consequence of these transactions between
governments [35]. As such, current programs consist only of the most reputable activities.
Maintaining competitiveness within the current market will therefore require a sharp decline
in the cost of DAC, as well as a steep increase in the demand for ‘carbon credits’.
Secondly, there remains a heavy dependence on large and constant payments for capture and
storage. Private sector companies are unlikely to provide capital without the support of
government policy. At a national level, such policies involve:
1. Initiatives such as a carbon tax, which provide carbon pricing;
2. Emissions trading schemes; and
3. Establishment of subsidies or technological mandates.
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Emissions under direct pricing schemes maintain prices of approximately $10/t CO2
equivalent, whilst in the Nordic countries, prices exceed $50/t CO 2 equivalent [39]. This
research by the World Bank suggests that the operation of efficient pilot-scale DAC
technologies is hypothetically feasible, although limited.
Nonetheless, current market prices are not sufficient to warrant the implementation and
accordingly, policies that further support growth in price or the development of mitigation
technologies will not come to fruition. For DAC deployment and operation to reach a
impactful level, policies that provide financial incentives will prove to be vital.
Finally, international collaboration diminishes the cost disparities between countries, in turn
increasing the efficiency of mitigation efforts on a global scale – it decreases overall costs
and generates greater interest. Market mechanisms allow carbon prices to serve as
encouragement for the global achievement of emissions reduction, regardless of the explicit
existence of a scheme. Two such mechanisms are outlined in the Kyoto Protocol [41]:
1. Article 12 – assist parties in achieving sustainable development and in contributing to
the ultimate objective of the convention; real, measurable and long-term benefits from
mitigation efforts in developing nations through the production of emissions credits,
to be utilised by industrialised nations.
2. Article 6 and 17 – parties may transfer to, or acquire from (any other such party),
emissions reduction units resulting from projects aimed at reducing anthropogenic
emissions by sources or enhancing anthropogenic removals by sinks of greenhouse
gases in any sector for the economy.
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2.6 Alternative Strategies
2.6.1 Afforestation
The primary objective of afforestation is to increase the stock of terrestrial biomass on the
land. This can be achieved by growing the density of plantations or through the addition of
environmentally inert biocarbon to the soil [42]. Such strategies are conceivably in progress,
particularly in circumstances where the large-scale plantation of trees explicitly act to reduce
CO2 emissions. For each hectare of land, approximately 500 tonnes of CO2 can be removed
from the atmosphere as these plantations mature. Furthermore, Boysen et. al (2016)
employed a ‘spatially explicit biosphere model’, which sought to evaluate the efficacy and
trade-offs for a giga-hectare plantation of biomass. Its implementation was shown to remove,
assuming maximum efficiency, up to 649 Pg of carbon cumulatively over this century. As a
result, the predicted emissions outlined in ‘Representative Concentration Pathways (RCP)
4.5’ – a trajectory adopted by the IPCC in 2014 – are delayed by 73 years, indicative of the
applicability of this strategy. Furthermore, it concludes that the maximum permittable
emissions to stay under the 2°C target can be contained by the end of this century, should this
be realised. Despite the promise this simulation demonstrates, it falls apart under RCP 8.5,
which details unabated emissions [43].
Figure 4 - Comparison of RCP 4.5 and RCP 8.5 [42]
The figure implies that balancing emissions would require a vast quantity of available land
for biomass plantation; an amount simply infeasible with the current state of technology.
Considering the extreme nature of these scenarios, equivalently large trade-offs are also
experienced, specifically with respect to food production and biodiversity [42]. Additionally,
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there are impacts on the extent of forests in relation to biogeochemical cycles and biophysical
properties.
For example, temperate and tropical regions in Asia will provide the greatest benefit, with the
smallest relative impact on food prices and albedo [1]. However, native forests will face
immense replacements, resulting in substantial ecological damage and roll-on social effects.
Extensive conversion of cropland to biomass plantations would diminish the potential for
global mean temperature reductions as a result of local warming, induced by positive
radiative forcing [1]. Caloric losses from lessened food production on this agricultural land
range from 43% – 73% for scaling scenarios. In 2016, Kreidenweiss et al. devised a partialequilibrium land model, which assessed the potential and impact of afforestation, assuming a
global incentive for carbon storage [43]. Their results demonstrated that pasture conversion
may drive food prices up by 80% come 2050, and > 300% come 2100, as a consequence of
land competition. Policies and economic incentives are therefore necessary to ensure the
solidity of the plantations, to stimulate higher crop yields, and to reallocate income to sectors
of society most susceptible to changes in the price of food.
If the optimal region is chosen however, numerous environmental benefits can be shaped.
These include water management and purification, new habitats for wildlife and protection.
Upon converting natural vegetation to biomass plantations, reflectivity due to augmented
moisture flux could generate substantial cooling effects through evaporation. This results in
longer growing seasons and higher vegetation density. However, this does not solve the
principal issue of land intensiveness. 800 million hectares of new forest would be required to
reduce atmospheric concentration by 50ppm, assuming a length of 1 century.
Reducing rate of deforestation is also a ‘removal strategy’ – tropical deforestation is
shrinking forest land area by 30 million hectares per year and introducing CO 2 into the
atmosphere by 4 giga tonnes of CO2, 12.5% of the rate of emissions released via burning.
2.6.2 Biomass Energy with CCS
Biomass energy conversion with CCS is able to generate net CO2 removal from the
atmosphere. Energy crops such as eucalyptus and sugar cane grow rapidly on dedicated
plantations, aiming to capture CO2 produced at the facility and sequester it deep underground
[44]. Provided that the harvesting rate is not unsustainable, this process can be classified as a
negative emissions technology (NET).
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Initial capture occurs through the mechanism of photosynthesis, and a secondary capture
takes place at the conversion facility [1]. Simultaneously, useful heat, power, fuels and
synthetic gas for chemicals and fertilisers are produced, without the need for fossil fuels. The
‘rapid growth’ nature of these crops means that significantly greater proportions of carbon
can be removed from the atmosphere per unit area, when compared to afforestation
plantations [1]. Subsequently, land requirements are substantially reduced for equivalent
quantities of CO2 removed.
The co-firing of biomass with coal offers a variation of BECCS in fuel production plants or
power plants, with storage of the CO2 produced from both operations. The higher the fraction
of biomass in the input fuel, the more carbon-negative the fuel and power. All negative
emissions technologies involve the successful development and commercialisation of
geological storage options. As such, BECCS with or without coal and DAC compete for the
same storage space, whereas afforestation achieves its own carbon storage.
The cost effectiveness of BECCS is examined in Muratori et al (2016). Circumstances
requiring the implementation of CCS see mitigation costs decrease by 50%, and the price of
carbon decline substantially – assuming adherence to the Paris Agreement target [45].
Discrepancies in the sources of biomass and storage options across the globe would
noticeably change the associated costs. Two distinct outcomes are prevalent:
1. Low cost – biomass waste obtained from forests, agricultural or industrial process
despite being restricted in terms of extent accessible.
2. High cost – dedicated cropland, which may have flow-on effects regarding food
production.
Additionally, transport and sequestration requires the accessibility of appropriate geological
formations and is strictly reliant on the purity of CO2, which is inextricably linked to the
biomass input [45]. Under theoretically optimal conditions, the cost of capture and storage
from sugarcane bagasse is approximately $50/tCO2 [46]; however, the majority of alternative
BECCS feedstocks are far more expensive. The operating cost ranges from $50 - $150/tCO2
and it has been estimated that carbon prices in well in excess of these costs are required to
equip 90% of new bioenergy plants with CCS technologies [46]. It can therefore be seen that
two economic drivers exist:
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1. Economies of scale – mass production will decrease the total cost of initial capital
expenditure on purchase of equipment and erection, working capital, operating costs
(including transport and storage) and overhead costs.
2. Resource scarcity – greater demand for biomass implementation will cause a direct
increase in operating costs, as supply is unable to shift to meet the demand.
Employment of BECCS projects on this scale would have noteworthy influences on food
prices, in an opposing manner to afforestation. In attempting to achieve the global mean
temperature target, a reduction in the upward pressure on crop prices is effectuated. This
occurs through decreased carbon prices and associated decreases in demand for biomass in
‘climate mitigation scenarios’ – compared to afforestation, significantly less biomass is
required, presenting a more rapid and suitable alternative. Nonetheless, technological and
institutional challenges related to large-scale bioenergy and CCS deployment must be
overcome before such situations can be accomplished [47]. A number of questions still
remain on the long-term viability of biomass energy strategies: What potential exists to
prolong the generation of high yields for decades? What protection measures can be
implemented for biodiversity when new species are introduced as a result of plantations?
Nonetheless, the co-benefits of BECCS such as improving the quality of natural habitats,
cultivating soil productivity and producing useful energy, seem to warrant the development
and implementation of terrestrial biological strategies before DAC.
2.6.3 Ocean-based CDR
Natural sinks such as oceans and plants (through photosynthesis) absorb 56% of atmospheric
CO2. Respective sinks maintain a removal capacity of 2.6 and 3.6 Gt per year [1]. Enhancing
the ocean’s natural biological pump through ocean fertilisation is another alternative strategy,
though not well-established as yet. Organisms at the surface of the ocean extract CO2 from
the atmosphere and release it at much greater depths [1]. The process has only been tried at a
local level and has therefore been unable to give insight into larger scale employment. A
secondary process, whereby alkaline components (derived from soda ash or limestone) are
added to the ocean has shown more promise as an emissions reduction strategy [1]. However,
CO2 dissolved in the ocean will eventually be released as concentrations fall – a new
equilibrium between the atmosphere and ocean will be reached. This has large implications
for the effectiveness of NETs, and does indeed increase the current deployment quantity
needed to achieve the global mean temperature target [1].
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Chapter 3: Process Selection
3.1 An Introduction to Multicriteria Analysis
A variety of processes have been established to demonstrate the potential of negative
emissions, and have been in direct competition with one another for funding. Venture
capitalists and governments must therefore decide on the most commercially applicable
strategy for the present and future. This selection is heavily influenced by a variety of factors,
ranging from costing to technology readiness level to policy and public acceptance; such
factors form the criteria for the decision-making process. Nonetheless, there is often
contradiction within the criteria themselves. One example of a trade-off in development is the
need for more efficient binding of CO2 in capture processes, which comes at the expense of
higher capital and operating costs. It is possible to combine the two criteria to enact single
criterion selection, by placing it in the form of cost per unit of CO2 removed, which is
prominently employed in project decisions. However, additional criteria that cannot be
combined nor neglected warrant the use of multi-criteria analysis (MCA). Some criterion
may prove to be partial functions of another. Despite introducing marginal bias, the integrity
of the result will remain in-tact by removing highly correlated criteria based on the
derivation. The following figure demonstrates the typical steps in carrying out an MCA.
Figure 5 - MCA Process Steps [47]
28 | P a g e
3.2 Assumptions
A variety of simplifying assumptions have been made in this Thesis. These assumptions help
justify certain criterion and warrant the removal of others, as well as reduce the complexity of
calculations. These have been chosen with care so as not to introduce further bias into the
ranking system; but rather, to standardise each process with respect to fixed parameters.
•
Project life - 25 years (a typical value pertaining to the useful life of equipment);
•
Heat recycling – Each process incorporates an efficient heat recovery mechanism;
•
Location – All processes are assumed to be set within the same environment; and
•
Purity – Each process is assumed to produce the same purity.
3.3 Criteria Selection
3.3.1 Capital Cost
The capital costs associated have serious implications for the construction of direct air
capture facilities. Without a feasible method to recuperate the initial investment cost, the
processes ability to be commercialised significantly diminishes. The more complex the
process, the greater the number of operating units and therefore the higher the cost,
particularly in relation to purchase of equipment and installation costs [1]. As such, the
potential substitution or removal of operating units that prove high costly or unnecessary in
achieving the desired concentration of CO2 must be considered with respect to future
application. The lower the cost, the higher the rating given; this is preferred specifically
because it reduces the risks associated with investment and strengthens the going concern for
the project.
3.3.2 Market Price
The higher the market price for CO2, the higher the rating. Given the current market price –
approximately $10/tonne – carbon prices would need to increase in proportion to close the
differential between revenue and total expense, and thus generate a positive NPV [40]. Since
reutilisation techniques such as enhanced oil recovery are typically founded on CO2 from
capture facilities, a higher sale price would result in larger profits, and therefore provide more
incentive to pursue the project. The price of carbon is heavily correlated with the outlet
stream purity, which is distinct in each process; however, this has been assumed to be
constant between DAC strategies and will therefore not be considered.
29 | P a g e
3.3.3 Operating and Overhead Cost
Should operating costs be excessively high, there will be no profits from the sale of carbon
dioxide. With greater complexity in the process, the expenditure required for maintenance
and repair, in order to ensure safe operation to standards and regulations, will markedly
increase. If no reasonable profit can be made from the capture of CO2, then companies will
lack the incentive to continually operate the facility. Currently, the notion of commercialising
direct air capture is far removed, since alternatives mentioned in Section 2.6 are far more cost
effective [1]. The lower the operating costs, the higher the rating.
3.3.4 Energy requirement
Each process suggested does indeed maintain high energy requirement as a result of
compression for transportation, or regeneration steps for the sorbents. Additionally, the
thermodynamic minimums of the processes are significantly lower than the actual energy
usage, because units do not operate under ideal conditions. By substituting either equipment
or chemicals – particularly the sorbents – greater process efficiency can be achieved without
increasing the complexity or the energy requirement. This does have implications for costing,
given that energy is currently sourced from the grid. However, the ability to employ
renewable sources within the process to reduce operating costs itself warrants investigation.
Whilst concepts such as wind energy are heavily dependent on location (constant), and solar
energy potentially infeasible as constant uptime may be needed, the ability to successfully
bind CO2 is distinct in each process [11]. Should changes be made with respect to energy
consumption, the efficiency of binding to reactive sites may fluctuate. Therefore, energy
requirement is separated from operating costs as a criterion.
3.3.5 Overhead cost
In addition, labour for monitoring and control purposes may increase the more complex the
process. Whilst these costs are miniscule in comparison to the initial capital investment, wage
increases with little change in carbon prices (for the foreseeable future) will result in greater
losses for companies. The ability to reduce the labour requirement and still ensure strict
monitoring and control schemes for the process must be taken into consideration when
assessing the feasibility of each strategy. Similarly, the lower the overhead cost, the higher
the rating given.
30 | P a g e
3.3.6 Geographical Location and Footprint
The lower the amount of land clearing, the smaller the footprint and higher the rating. As a
result of the dilute concentration in ambient air, when compared to industrial capture, DAC
facilities necessitate larger footprints. Two options exist in mitigating the impact this could
have, being: have a smaller number of operating units to minimise footprint or choose a
suitable location. However, it should be noted that in theory, the choice of location is driven
by several variables including the climate conditions, potential for storage on site, and
proximity to populated areas. As per the assumption stated, location for all processes are
assumed to be the same since investigation into climate conditions for this section
overcomplicate the ranking scenario, and is beyond the scope. It does not change the concern
for footprint, as each process requires a different number of operating units.
3.3.7 Transportation and Storage
Once a suitable geographical location has been chosen, transportation of CO2 through
pipelines to storage sites must be considered. Alternatively, CO2 can be sequestered below
the site itself (in the case of geological storage). Transportation and storage are indeed
dependent on the specific method as each generates a different purity; it determines the
reutilisation and storage capacity of CO2, as it changes the nature of reactions in geological
storage and changes the nature of the transportation to offsite storage (leakage of additional
impurities requires stricter control) [5]. Again, with the simplifying assumption of constant
purity across processes, the need to investigate both transportation and storage can be
neglected for standardised ranking purposes only. This will be considered however, once a
specific process has been chosen for further analysis.
3.3.8 Waste Pollution
The lower the level of pollution, the higher the rating. Each process employs a variety of
chemicals for capture purposes, increasing the reactivity of sites and regeneration. However,
loss of chemicals is a typical occurrence as a result of degradation and through these
regeneration steps. Waste management therefore becomes a primary concern, particularly if
located in a thriving ecosystem.
3.3.9 Technology Readiness Level
The technology readiness level (TRL) is essential in ranking the landscape of currently
available DAC technologies; the higher the rating given to this criterion, the more developed
the process. In order to develop a suitable TRL scheme for the purpose of assessing DAC
methods, modelling and simulation has been undertaken with respect to matching objectives,
these being more rapid commercialisation and deployment [47]. Typically, there are two
31 | P a g e
approaches to creating an appropriate scale; one that investigates consumer perceptions and
acceptance levels, and one that highlights technological modernisation, ease of
implementation and consistency [47]. This also includes factors determining its commercial
applicability, including incentivisation and the existence of more viable alternatives. As such,
the definition of each level within this scale is based on fundamental knowledge regarding
chemical and physical principles of the processes, the respective mass and energy balances,
and the associated socio-economic factors. The scheme can thus be divided into three distinct
segments: 1. Levels 1 to 3 – research and proof-of-concept phase [47]; 2. Levels 4 to 6 –
development and near prototype phase [47]; and 3. Levels 6 to 9 – demonstration to full-scale
operational phase [47]. The following table details the levels separately, in addition to
potential characteristics for a DAC with sizing based on power consumption [47].
32 | P a g e
TRL
Scale
Characteristics
•
1
reporting observations on the chemical or physical
N/A
2
Initial concept – determining the underlying principles and
properties of the system.
Paper and
•
Extremely low cost for research.
•
Establishing a practical application – design has reached a
preliminary stage, founded on a number of simplifying
computational
analysis
3
assumptions that require further investigation.
•
Very low cost for research
•
Attempting to demonstrate the proof-of-concept notion.
•
Research and development is being undertaken on a lab
scale with analysis verifying the aforementioned
simplifying assumptions.
4
Laboratory and
•
Low cost for research and testing
•
Validating the necessary components within a lab-scale
environment – concentration of CO2 may be slightly
bench-scale testing
higher to determine the actual feasibility of application
before further testing is done.
5
•
Low to moderate cost for testing.
•
Simulating the actual operating environment to ensure
components maintain efficacy.
6
•
Moderate cost for investment and testing.
•
Prototyping with components that function in a highly
Small-scale
similar fashion to the eventual full-scale plant. Further
operations
component integration is not required at this stage.
7
•
Moderate cost for development of the prototype
•
Increasing the capacity of the prototype, inching it toward
a suitable size to demonstrate the potential for scale-up.
25 MWe
•
All components and control schemes match the design for
the full-scale plant.
8
9
150 MWe
500 MWe
•
High cost for construction and operation of the prototype.
•
Successful operation of a pilot-scale plant.
•
Very high CAPEX and OPEX.
•
Commercialisation of the technology.
•
Extremely high CAPEX and OPEX.
Table 2 - Technology Readiness Levels [47]
33 | P a g e
3.3.10 Subsidisation and Financial Incentives
Presently, there is little to no government effort pertaining to the subsidisation of DAC
facilities. Governments are dissuaded from doing so, given that the TRL for the majority of
processes is rather low. Moreover, the choice to subsidise a particular process over another
may only depend on the harmfulness of the chemicals employed. However, carbon pricing
schemes vary internationally, and significantly change the price of CO2. In countries such as
Norway, prices reach values of up to $USD 50/tonne [40], a value significant enough to
warrant the mobilisation of DAC technologies, in stark comparison to the average market
price of $USD 10/tonne. This is a direct result of stringent regulations on the quantity of
emissions produced by facilities. Since location is assumed to be the same, this will not be
considered.
3.3.11 Public Acceptance
The public acceptance of DAC methods can be determined through the analysis of carbon
capture and storage cases, as well as commercially implemented distribution source
mitigation strategies such as biofuel. Two potential impacts are of major concern:
•
Does the facility, including associated pipelines, intersect with populated areas – this
has both visual implications and may present hazards in the form of pipeline leakages.
•
Does the facility, including associated pipelines, cause harm to diverse ecosystems,
specifically in public access areas such as national parks.
The lower the risk of public protest, the higher the rating given.
3.4 Categorising the Criteria
For simplification, the chosen criteria can be categorised into four major segments: cost, size,
risk and policy. When change occurs, the criterion within each category is likely to shift in
the same direction. In this sense, analysis becomes far easier particularly when ranking DAC
processes using more complex methodology. As such, we have the following:
•
Cost – capital cost, operating cost, energy requirement and overhead cost;
•
Size – footprint;
•
Risk – waste pollution, technology readiness level; and
•
Policy – public acceptance.
34 | P a g e
3.5 Elimination of correlated criteria
The R-values (Pearson products) of the criterion have been calculated and detailed in the
table below to justify the inclusion of all criterion. The larger the R-value, the more
correlated the criterion. It is indeed expected that energy requirements and operating cost will
produce the largest R-value; the difficulty then becomes establishing a universally accepted
maximum correlation. On this matter, various pieces of literature suggest that a correlation
less than 0.8 is acceptable [48]. The following table demonstrates the calculation of the Rvalue using equation 3.1 highlighting a correlation of 0.54 – significantly less than that
required for elimination.
𝑛(∑ 𝑥𝑦) − (∑ 𝑥)(∑ 𝑦)
𝑅=
2
(3.1)
2
√[𝑛 ∑ 𝑥 2 − (∑ 𝑥) ] [ 𝑛 ∑ 𝑦 2 − (∑ 𝑦) ]
X
Y
XY
X2
Y2
1
2
Energy
(GJ/tonne
captured)
17
15
Operating Cost
($/tonne
captured)
76
68
1292
1020
289
225
5776
4624
3
10.6
44
466.4
112.36
1936
4
5
0.94
10.5
54.04
36
104
328
33.84
1092
3904
0.8836
110.25
737.6
1296
10816
24448
Pearson
Product
Example
Subject
Causticisation
Amine
Absorption
Physical
Adsorption
Membranes
Cryogenics
Total
R-value
0.5356
Table 3 - Pearson Products for Correlation
3.6 Assigning Weightings and Ratings
The next step in the MCA is assigning weightings to respective criterion; the higher the
weighting, the more influential the criterion. Arbitrary values given would only reduce the
accuracy of the decision-making process, and thus, a legitimate model will be used. The
Analytica Hierarchy Process (AHP) functions as a pairwise comparison, allowing alternatives
to be ranked according to their importance relative to other options, in light of the objectives
for this paper. Responses to this question of importance are obtained in a linguistic form,
demonstrated in the following table and based on intensity [48]. It should also be noted that
placing these scores in a matrix results in the swapping of criteria, with respect to position.
As such, the score given must be the reciprocal (i.e. a score of 5 will become 1/5).
35 | P a g e
Linguistic founded on importance
Intensity
Equally important
1
Moderately more important
3
Strongly more important
5
Very strongly more important
7
Overwhelmingly more important
9
Table 4 - Scoring scale for AHP [48]
Subsequent steps involve calculating the weight most consistent with the relations indicated
in the matrix. The simplest method for doing so involves establishing the geometric mean for
each row. By dividing that geometric mean by the sum of all means, a normalised weighting
can be established and utilised in the MCA scoring table.
Criteria
Weighting
Capital Cost
28.2%
Operating Cost
17.9%
Energy Requirement
12.2%
Overhead Cost
3.74%
Footprint
9.72%
Waste Pollution
4.44%
Technology Readiness Level
17.9%
Public Acceptance
5.9%
Table 5 - Results of Weighting Calculation – Geometric Mean Method
The final step before calculating final scores is determining a rating for each process. This
rating is indicative of how each alternative satisfies the respective criterion; the scale utilised
in this paper is 1-5, with 5 being excellent and 1 being poor. Multiplying the weightings
determined by the ratings given, and subsequently summing the scores will highlight the most
feasible process. The choice of rating will be based on the literature review and associated
sources.
36 | P a g e
Capital
Operating
Energy
Overhead
Cost
Cost
Requirement Cost
Capital Cost
1
2
3
5
Operating
1/2
1
2
1/3
1/2
1/5
Footprint
Waste
Footprint
Waste
Technology Public
Geometric
Pollution
Readiness
Acceptance Mean
3
5
2
4
2.78
4
2
4
1
3
1.77
1
3
2
3
1/2
3
1.20
1/4
1/3
1
1/3
1/2
1/4
1/2
0.37
1/3
1/2
1/2
3
1
3
1/2
2
0.96
1/5
1/4
1/3
2
1/3
1
1/4
1/2
0.44
1/2
1
2
4
2
4
1
3
1.77
1/4
1/3
1/3
2
1/2
2
1/4
1
0.58
Cost
Energy
Requirement
Overhead
Cost
Pollution
Technology
Readiness
Public
Acceptance
Total
9.87
Table 6 – Weightings derived by AHP
37 | P a g e
Criteria
Weighting (%)
Capture Processes
Causticization
Inorganics
Amine Sorption
Membranes
Cryogenics
28.2
3
4
3
4
4
17.9
3
3
4
3
2
12.2
2
3
3
2
2
3.74
4
4
5
4
4
Footprint
9.72
2
4
3
4
5
Waste
4.44
3
3
2
4
5
17.9
5
1
4
1
1
5.90
2
3
2
5
5
100
3.12
3.05
3.33
3.09
3.06
Capital
Cost
Operating
Cost
Energy
Requirement
Overhead
Cost
Pollution
Technology
Readiness Level
Public
Acceptance
Total
Table 7 - Outcome of AHP Process Selection
38 | P a g e
3.7 Discussion of Results – AHP & Ratings Method
The selection of amine adsorption was heavily influenced by its operating cost, technology
readiness level and marginally more efficient energy scheme. Only causticization and amine
adsorption are commercially utilised processes, and therefore maintain the highest technology
readiness levels. The energy used in regeneration, with respect to the minimum
thermodynamic requirement, is slightly higher for causticization due to the nature of the
chemicals. Calcination necessitates temperatures of 700°C [11], whereas regeneration of
amine sorbents operates at temperatures near 100°C [20].
It should be noted however, that the non-commercialised processes notably fall short in the
technology readiness level criterion. The most influential criterion of capital cost is won out
by all three lab-scale processes, boasting considerably lower initial investments due to the
minimal purchased equipment costs. As a result, footprints score higher, particularly in the
case of cryogenics; retrofitting means the process can be added to existing facilities. Had
these smaller criteria weighted higher, the result may have varied considerably. Nonetheless,
with a project life of 25 years and assuming an immediate or urgent need for DAC
implementation., research and development into such strategies are far from
commercialisation.
3.8 Analysis of AHP
The importance of each criterion with respect to another is majorly based on literature, and a
general understanding of DAC processes. The largest weight has been given to capital cost,
which is the primary impediment to DAC’s implementation. Given an ambient air
concentration of 400ppm for CO2, industrial equipment must first be scalable and
commercially available at the size required; that is, approximately 300x larger than CCS to
remove the same quantity of CO2. Without access to government subsidisation, companies
lack the financial incentive to pursue DAC, despite the necessity to reduce the quantity of
CO2 in the atmosphere. Means for reutilisation and storage including enhanced oil recovery
and biofuels have the market but cannot match the price required for these projects to be
economically viable. As such, capital cost – typically comprising 60-70% of total cost – is
given the greatest weight.
Issues such as policy, that is public acceptance, may have varying weights. In regions such as
Europe, regulations have strictly prohibited research and development in biofuels, reducing
the market for CO2 use (see Section 2.5.5). Naturally, this impacts the ability to pursue direct
air capture projects in the region, and accordingly, the weighting for public acceptance would
39 | P a g e
be considerably greater. Furthermore, DAC poses risk to the environment, despite the fact
that its location may be the most suitable. In areas where farmer’s agricultural land may be
compromised (e.g. the Otway Basin in Victoria) or deforestation is required for ease of
storage, public acceptance will undoubtedly play a large role in the project’s initiation and
survivability. The same delay and cancellation issues faced by CCS must be considered for
DAC, particularly because the facility will have a greater footprint. The weighting of public
acceptance in parts of Australia vary themselves, and this can be extended to regions in the
world; it is dependent on the influence of public opinion on government decision-making.
3.9 Potential Pitfalls in Weighting
The factors used for weighting in AHP are subject to variance, simply because they rely on
the opinion of ‘expert’ assessors. Even if deemed an expert, human decision-making is
always afflicted by bias – the linguistic approach is not enough to remove this entirely. A
sensitivity analysis on the weightings themselves must therefore be conducted – this may
indeed affect the result. It can be assumed that the rankings will only change significantly if
capital cost, operating cost and technology readiness level are altered, given they hold the
greatest weighting. A reduction in costing is the most likely occurrence; this would be
distributed to the remaining criteria based on their relative weights. It should be noted that
risk (see Section 3.4) would in theory, receive the majority – with lower costs, sizing would
also decrease, and policy would remain unchanged. To reduce capital costs, the process must
either be made more efficient or materials of construction substituted, thus reducing the
footprint and energy requirements. However, technology readiness would consequently
increase; if the process is more efficient, technology must have advanced notably.
3.10 VIKOR
Perhaps a more valid method for evaluating the feasibility of these processes – as it reduces
subjectivity – is the VIKOR method. This was implemented to resolve a discrete decisionmaking issue with differing units for each criteria and potentially overlapping criteria – those
that may minorly be contingent on another. VIKOR aims to generate a list of ranks from a set
of alternatives by aggregating the criteria based on their performance or scores, based on
criteria weight. These alternatives are ranked according to their proximity or closeness to an
‘ideal case’. A flowchart of the process and calculations necessary is shown in figure [49] and
is comprised of two specific steps: normalisation and ranking.
40 | P a g e
3.10.1 Normalisation
Normalisation features in this selection method, converting scores from each criterion to a
linear result in the range of (0,1). In effect, this establishes a standard for comparison of
criterion, with respect to their contribution and importance. Each criterion can be labelled as
either a ‘cost’ or ‘benefit’ and come with respective formulae. Taking cost as an example, the
decision-maker is interested in minimising the value i.e. the smaller the better. Equation 3.2
relates to benefit, whilst 3.3 relates to cost [49]. Within each classification, the least ideal
solution receives a value of 0, whilst the most receives 1 – the rest are linearly mapped
through the aforementioned range. Its use indeed impacts the result, particularly when a new
alternative arises – existing scores will be rearranged. Additionally, normalisation permits
negative value, which are typically classified as the costs associated.
𝑓𝑗 ∗ − 𝑓𝑖𝑗
𝑓𝑗 ∗ − 𝑓𝑖𝑗 −
(3.2)
𝑓𝑖𝑗 − 𝑓𝑗 −
𝑣𝑖𝑗 =
𝑓𝑗 ∗ − 𝑓𝑗 −
(3.3)
𝑣𝑖𝑗 =
Where f* represents the max value for an associated criterion, and f- is the minimum.
There are a few notable issues with both VIKOR generally and normalisation, but the most
prominent arises from the fact that magnitude is irrelevant. With performance being
translated to scores in a range of 0 to 1, the value ascribed to each alternative is lost – the
magnitude demonstrates how the chosen criterion sit relative to one another. This effect is
amplified for smaller data sizes but even for larger quantities of data, the values near both 0
and 1 display such neglect. The number of alternatives existing in this Thesis sits somewhere
between small and large. Nonetheless, VIKOR proves to be the most suitable method for
ranking the suitability of DAC processes.
41 | P a g e
Figure 6 - VIKOR Flowchart [50]
3.10.2 Ranking
The ranking calculations produce a single value for each alternative, the largest being the
most highly ranked. Maximum group utility – otherwise known as the majority rule – is
defined by ‘S’, whilst the minimum ‘individual regret of the opponent’ is defined by ‘R’.
These two values signify the average gap and maximum gap respectively, where the ‘gap’ is
the Euclidean distance between the ideal case and the alternative. The equations seen in the
above figure are used to calculate these values. S – sum of the product of the normalised
42 | P a g e
value and its respective weight; R – maximum of normalised value multiplied by the
corresponding weight.
From these two values, we can then determine ‘Q’; this represents the ranking score of each
process. Two parts constitute this formula and correlate to ‘v’ – a weight lying between
maximum group utility and the majority of criteria. The value can therefore be a maximum of
1 but is typically assigned the highest criterion weight for a given process. This does however
introduce a bias; processes with a strong performance in one criterion may outweigh those
with strong performances in many [50].
For the purposes of this VIKOR analysis, only cost and risk will be considered as they are the
largest determining criteria of feasibility. The cost values for ‘f’ have been taken from a
variety of recent journal publications; typically given in a range, the most conservative
estimate has been used. The risk values for ‘f’ are undeniably subjective, and based on
literature. However, literature does give a reasonable indication of both the technology
readiness level of the process, and the quantity of resultant pollution (from chemical waste,
heat and noise). As such, the scores given from the previous ranking method will be scaled to
100 and adjusted to give a more accurate representation of their ability. The following table
details the total cost and the adjusted scores in the risk category. Note that total risk is
calculated by taking the ratio of technology readiness to waste pollution and weighting the
scores accordingly.
Criteria
Total Cost
Process
Causticisation
Inorganics
Amine Sorption
Membranes Cryogenics
232
220
140
110
330
85
20
75
15
12
67
72
43
81
87
81.4
30.4
68.6
28.2
27.0
($/tonne CO2)
Technology
Readiness
Waste
Pollution
Total Risk
(TR + WP)
Table 8 - VIKOR Ratings
The next step requires the calculation of ‘v’ for the cost and benefit criteria, using equations
3.2 and 3.3. From this, we are able to calculate the values of S and R for each process.
43 | P a g e
The results are shown in the table below:
Weighting Criteria
62.04% Total
Cost
17.90% TRL
4.44% WP
22.34% Total
Risk
Cost 'v' value
Risk 'v' value
Process 'S' Value
Process 'R' Value
Q Value
RANK
Process
Causticisation Inorganics Amine
Membranes Cryogenics
Sorption
232
220
140
110
330
85
67
81.4
20
72
30.3
75
43
68.6
15
81
28.1
12
87
26.9
0.45
1.00
0.59
0.33
0.58
3
0.50
0.06
0.38
0.37
0.48
4
0.86
0.77
0.84
0.63
0.93
2
1.00
0.02
0.74
0.74
0.94
1
0.00
0.00
0.00
0.00
0.00
5
Table 9 - Initial VIKOR Ranking Results
Given the dominant weighting of ‘cost’, it is no surprise that membrane capture receives the
highest ranking. Compared to the majority of alternatives, membrane capture has a
significantly lower cost as it lacks the need for chemicals, and therefore a regeneration step
[50]. However, amine sorption comes markedly close in this respect, with a marginally higher
cost but a significantly higher technology readiness level. It therefore stands to reason that if
cost reduces, the order of ranking will drastically change; this has been tested in a sensitivity
analysis.
3.11 Weight Sensitivity
Process efficiency comes at the hands of technological advancement. The associated
reductions in cost, particularly with scale, could be on the order of 20-50% [50]. Taking the
most conservative value, a change of 20% is assumed. As mentioned in Section 3.9, the 20%
reduction will translate to approximately a 20% increase in the technology readiness level – it
is assumed to be the full amount for ease of analysis.
The sensitivity analysis could have also been approached in a more detailed manner, if the
information available was quantitative, rather than qualitative. With DAC being a relatively
new concept, the estimates for the effects of changes have large ranges, and assumptions are
exceptionally broad. For this reason, this paper only investigates the most obvious relation.
44 | P a g e
The table below details the results of the sensitivity analysis:
Assume a 20% reduction in total cost, which goes toward TRL
Weighting
Criteria
42.04%
Total Cost
232
220
140
110
41.90%
TRL
85
20
75
15
4.44%
WP
67
72
43
81
46.34%
Total Risk
83.3
25.0
71.9
21.3
Cost 'v' value
0.45
0.50
0.86
1.00
Risk 'v' value
1.00
0.09
0.82
0.03
Process 'S' Value
0.74
0.29
0.84
0.49
Process 'R' Value
0.52
0.24
0.43
0.48
Q Value
0.94
0.40
0.91
0.75
RANK
1
4
2
3
330
12
87
19.2
0.00
0.00
0.00
0.00
0.00
5
Table 10 - Sensitivity Analysis Rankings
As seen in the rankings, the value for causticisation increased dramatically, while amine
sorption remained relatively unchanged and membranes decreased notably. The utilisation of
caustic sorbents occurs at the highest technology readiness level, employed by the majority of
commercial plants [1]. While amine sorption is indeed the most common for CCS strategies
and has a noticeably lower cost, the incentive for commercialisation is undeniably dependent
on the current level of technology. A 20% change in technology readiness resulted in a 172%
increase in the Q-value of the causticisation process.
3.12 Conclusion of Process Selection
With VIKOR, in combination with AHP, being the most accurate multi-criteria decisionmaking method, the process selected will be causticisation. Despite the high energy
requirements and therefore operating cost, as well as large capital costs, there are several
foreseeable areas for improvement [9]. In comparison to amine sorption, causticisation
maintains a few noteworthy advantages:
•
The ability to adapt existing equipment to increase the efficiency of causticisation is
greater [9];
•
The scope for economies of scale is larger, due to the contacting method [9]; and
•
Thorough research and development is being undertaken in causticisation [9].
The next chapter details and discusses the process model, and divulges how these advantages
impact the feasibility of DAC.
45 | P a g e
Chapter 4: Methodology and Process Model
Having chosen an appropriate process for the proposed quantity of CO2 removal, the next
step is to provide a detailed explanation of the design choices. The ensuing plant design
accommodates for 1 tonne of CO2 captured per day – a rate reasonable for a pilot-scale plant.
Most commercial plants, for example Carbon Engineering, operate on a scale of 1 million
tonnes per year, a significantly higher quantity than that investigated here [1]. However, this
process follows a similar methodology, with modifications in design to reduce the initial
capital investment, footprint and energy requirements.
4.1 Assumptions
Whilst assumptions are stated in the majority of following sections, the primary design
assumptions are listed here.
•
Air considered to have oxygen and nitrogen components in addition to CO 2;
•
Air has a relative humidity of 30% - this is significantly lower than the average
humidity in Australia [22], but from the Literature Review (see Section 2 ), humidity
plays an important role in establishing high purity CO 2 for reutilisation or storage;
•
Air is assumed to enter the system at 1-3m/s (see Section 4.4.3 for justification);
•
The saturated steam used for regeneration is pure and that this is provided from the
mains system, for simplification of the design [51];
•
The non-condensable components follow the ideal gas law and ideal mixtures [51];
•
Typical operating conditions are assumed at every stage of the process;
•
The suction of air occurs via the use of an electric fan [52];
4.2 Sorbent Selection
The choice of sorbent is imperative as it determines the CO2 loading rate, and thus the
quantity captured per cycle. Both solid and aqueous sorbents are utilisable, each maintaining
specific advantages over the other.
Solid
Advantages
Aqueous
•
Low energy input
•
Continuous
•
Low operating cost
•
Adaptable unit
•
Scaling
operation
•
Long contactor
lifetime
46 | P a g e
Disadvantages
•
Batch process
•
Not high performance
requirement for
at low operating cost
regeneration
range
•
•
High energy
Water loss in a dry
environment
Table 11 - Advantages and Disadvantages of Sorbent Types [10]
Nearly all systems capitalise on acid-base chemistry. As stated in Section 2.2.1 of the
Literature Review, both sodium and calcium hydroxides were initially employed. The most
notable method in early stages of development, introduced by Lackner [10], implemented
sodium hydroxide as the primary sorbent at a concentration of 2M. Further studies were
undertaken by Bacchioci et. al (2006), who conducted an energetic and economic assessment
of this process, concluding that calcination energy is excessively large – limiting its
feasibility. To put it into context, the heat of combustion of coal is approximately 9GJ/tonne
CO2, whilst the real energy demand of this process is 17GJ/tonne CO2 – double the energy is
required per unit of coal [29]. Specific studies to increase the viability of such a process have
shown that energy required for calcination can indeed be reduced [29], but the step itself is
only replaceable through the use of solid sorbents. Lackner then designed a process,
substituting hydroxide for an anionic exchange resin – a quaternary ammonium ion; however,
the strength of this base is effectively reduced because of partial carbonation [10].
Despite the fact that solid sorbents significantly reduce the energy requirement in the
regeneration step – calcination – the disadvantages associated with batch operation and
untested performance at scale, prohibit its implementation. Continuity is essential in such an
application, with operating expenditure already constituting 30% of total cost. The main
advantage of aqueous sorbents is their ability to do exactly this – run continuously;
temperature, pressure and humidity need not be cycled whilst the contactor is sealed from
incoming air.
Sorbents are typically hydroxide based, containing relatively dilute concentrations of sodium
or potassium as alkali. Again, a decision must be made between the two cations; whilst
sodium has been applied for longer periods of time, potassium is currently being researched
as a more efficient alternative. As previously mentioned, the drawback in causticization is the
regeneration energy – potassium requires significantly less. In a study conducted by
Mahmoudkhani et al. (2009), it was found that KOH indeed captured 27% more CO2 in the
contacting process, and consumed 125kWh of energy per tonne captured [53]. Using a
47 | P a g e
sodium solution resulted in a 68% decrease in concentration across the length of the packed
tower. Note that in this particular experiment, the air speed and flow through the packing
were fixed, as was the concentration of the sorbents. However, industrial KOH is currently
1.5 times more expensive than NaOH [53] and has a greater decay rate . In spite of the
supplementary benefits through energy savings and higher CO2 loading rates, the use of
potassium cannot be justified until more conclusive research is provided. Therefore, this
investigation uses a benchmark 1-2M NaOH, fixing the uptake rate on the surface of the
solution.
A common issue associated with both aqueous hydroxides is water loss. This can be
mitigated by increasing the concentration of the sorbent, at the expense of higher operating
costs. Traditionally, more concentrated NaOH or KOH could simply be purchased, but the
manipulation of temperature and the humidity of the incoming air has proven more cost
effective [53]. For example, lab-scale testing conducted by Stolaroff et. al showed that 7.2M
NaOH at standard temperature and 65% humidity (similar to the Australian average of 70%
[54]), entirely eliminated water loss.
4.3 Process Description
The process can be broken into four distinct stages: air contacting, pelletising, calcining and
slaking [1]. These stages remain consistent at all technology levels, but differ vastly in the
operating conditions of the units; the result, a substantially varied total capture cost.
The following figure demonstrates a typical flow diagram for the caustic capture of CO 2,
including the chemical equations and the associated enthalpy. After forming an alkali
carbonate upon contact with KOH (NaOH is used in this paper), the solution is reacted with
calcium hydroxide pellets of high surface area, forming lime mud and the restoring the
sorbent. The calciner extracts the CO2 whilst the slaker regenerates the Ca(OH)2.
Figure 7 - Process Flowchart [52]
48 | P a g e
Given the assumption of typical operating conditions, NaOH in solution has a CO2 uptake of
20g per kg of solution, or 4.43 moles of NaOH per mole CO2 [10]. Consequently, the
required volumetric flowrate of liquid to gas is considerably smaller than industry, allowing
the system to operate in a low flow regime [53] (the benefits of which are further explained in
Sections 4.4.3 and 4.4.4).
4.4 Air Contactor Design
A number of variables must be considered to design both a thermodynamically and
economically efficient contactor, and is therefore the most difficult unit to design. This
section details the design parameters, whilst Chapter 5 deals with the cost optimisation of the
unit, and therefore any costing calculations.
4.4.1 General Specifications
The volumetric flowrate of air that allows for a capture rate of 1t-CO2/day must first be
ascertained. With a concentration of 0.04% in air - corresponding to 0.06% by weight – we
first convert tonnes to kilograms and divide this value by the percentage weight, giving
1.67 x 106 kg-air/day. Further dividing by the density of air at standard temperature and
pressure – 1.184 kg/m3 – gives the necessary value: 16.3 m3/s.
Using the volumetric flowrate of air, and assuming an air velocity of 2 m/s (the average of the
stated range), an inlet area of 10.2m2 would be required given a suitable capture efficiency of
0.8. Generic packed columns are easily employable for this purpose, with commercially
available designs maintaining inlet areas up to 100m2 . However, scaling this process to levels
that warrant DAC – for example, 1Mt-CO2/year – demands inlet areas four orders of
magnitude higher; the number of packed columns would be economically infeasible.
Adapting and testing existing technology to better suit the needs of future implementation is
therefore imperative; cooling towers are appropriate to this end, but hold technical risk [51].
A packed column can be constructed in cylindrical or slab geometry; no significant difference
can be identified at such low flowrates. With manufacturers more commonly producing
cylindrical columns, a competitive purchase cost can be obtained, and capital costs reduced.
Air flows through the top of the column, whilst solution is pumped in through the sides. A
surface area of 10.2m2 can be achieved with an internal diameter of 1.8m. One disadvantage
of packed columns is they lack an inherent mechanism to recycle low-CO2 content air; this
paper does not further examine the process, assuming that air is practically cleaned [55].
49 | P a g e
4.4.2 Packing
The purpose of packing is to evenly distribute the sorbent solution over the contactor, thereby
maximising the surface area in contact with the incoming air. In this way, a greater
proportion of CO2 can be captured whilst maintaining a suitable pressure drop [56]. Another
characteristic essential to efficient contact is an open structure, defined as a low resistance to
gas flow.
Selecting an appropriate packing material has implications not only for the economic cost,
but also the efficacy of capture. In most scenarios, industry utilise structured packing as the
majority of their properties prove beneficial in comparison to random packing. The following
table highlights notable advantages and disadvantages [56].
Structure Packing
•
•
Manufactured in modular form,
Random Packing
•
Available as a ceramic, plastic or
allowing material to be stacked at
steel, allowing greater flexibility in
varied heights;
application.
Maintains a high surface area and
•
therefore higher efficiency;
Exceptionally cheaper than structured
packing.
•
Maintain low pressure drops;
•
•
Expensive to purchase; and
geometry to suit a particular purpose
•
Faces difficulty during transport, as
e.g. greater liquid distribution or
shape must remain in-tact.
wettability.
Ability to modify existing packing
Table 12 - A Comparison of Packing Structures [57]
Typically, the chemical industry – ranging from wastewater treatment, to cooling towers to
distillation – employ structured packings. Despite the table above implying the contrary,
structured packings may indeed be established from thermoplastics. Analysis by Keith et. al
has revealed a structured PVC-based packing that demonstrates [51]:
•
High capacity;
•
Cost effectiveness in comparison to steels (approximately 6 times cheaper);
•
Resistance to high concentrations of NaOH;
•
A long useful lifetime; and
•
Debris management.
Consequently, it would stand to reason that thermoplastics are more than suitable for the
purposes of DAC; however, commercially available products do not maintain the most
50 | P a g e
optimal geometry – transfer properties necessary for air contact markedly diverge from
typical applications. Nonetheless, the technology readiness level is certain to increase with
research and development by leading manufacturers [56].
Accordingly, a thermoplastic devised by Sulzer Pty. Ltd has been selected for this model –
Mellapak 250.X/Y. This packing material is derived from PVC-C and has the benefit of:
•
Reducing column diameter and therefore capital costs;
•
Providing 25-30% higher capacities than conventional structured packings;
•
Maintaining small pressure drops per metre of packed height throughout the unit;
•
Operating efficiently under high pressures and temperatures up to 110°C; and
•
Being primarily applied in absorption/desorption systems and flue gas cleaning
columns – air contact is an extension of this.
Other notable properties include pressure drops per theoretical stage of 0.3 - 1 mbar and a
liquid load ranging from 0.2 m3/m2h – 200 m3/m2h [58]. Sulzer also states that specific
surface areas can range from 125 m2/m3 – 1700m3 for any of their structured packings,
designed to suit the particular process. A conservative value of 250 m2/m3 is taken, as
specific surface area correlates positively with capital cost. It should be noted however, that
packing used in cooling towers maintain specific surface areas of 50 – 150 m2/m3, adding to
the technical risk upon scaling.
The final variable required is packing depth, determined using the power law equation below
𝐷=
∆𝑃
7.4𝑉 2.14
(4.1)
Where ΔP represents the packing depth, and V the velocity of air at the inlet. Using the
established values of 100Pa and 2 m/s respectively, we ascertain that the packing depth must
be at least 3.06m.
This equation suggests that depth is a function of pressure drop and velocity; however, this
brings to question its validity. If this process were to be scaled, yet the same pressure drop
and air velocity desired, then the same packing depth would eventuate from this calculation.
Consider Carbon Engineering’s contactor – 20m wide x 8m deep x 200 long – would a 3.06m
depth be sufficient to capture their target quantity? It is assumed that for the purposes of this
investigation, the equation is indeed valid.
51 | P a g e
4.4.3 Driving Force for Air
A physical structure is needed to pump the air, bringing it in contact with sorbent surface.
This can occur via machinery or ambient flow, for example: natural wind, wind farms,
thermal convection or pressure-driven gradients. One further option, which this paper
investigates, is the use of fanning. Whilst this produces significantly lower velocities, it does
not necessarily reduce the efficacy of the capture system [52]. Lower inlet flowrates prove
less impactful on overall efficiency than one would generally consider.
Furthermore, a low flow regime correlates to a small pressure drop – a value on the order of
100 Pa [1]. To maintain this, 6.2kJ/mol of CO2 (in air) is required; air moving at a velocity of
10m/s carries a kinetic energy of approximately 3.6kJ/mol. Attaining this level of energy
necessitates a maximum velocity of 15m/s. Larger pressure drops render the entire DAC
process void, simply because the amount of CO2 released as a consequence is inherently
unsustainable. Taking a pressure drop of 2000Pa, characteristic of air velocities generated by
more powerful equipment, APS reports that 9 molecules of CO2 are released for every 10
moles captured [1]. This trade-off does not consider the emissions associated with the
transportation or sequestration of the captured CO2, meaning the value would only increase.
The only feasible implementation of DAC, particularly in a net carbon framework, would
therefore consist of small pressure drops and low-carbon power sources [1]. Therefore, the
assumption of air velocity = 1-3m/s, maintaining both the low flow regime and low pressure
drop, is validated.
Selecting the most appropriate fan is relatively simple as a variety of manufacturers produce
them commercially. The notable variables that must be assessed are:
•
The volumetric flowrate of air – 16.3 m3/s;
•
The velocity of air at the inlet – 2 m/s; and
•
The uptime on the fan’s operation – 85%.
The chosen fan produced by Airtight Solutions [59] – an Australian company - has an
operating efficiency of approximately 70% whilst air moves through the contactor within the
stated range. It accommodates volumetric air flows of 300 m3/hr to 180,000 m3/hr with
pressure capabilities far exceeding the necessary amount.
Using this value for efficiency, we can then calculate the energy requirement for the fan in
Joules per m2 per year, where Foperating is the number of seconds in a year and η is the
efficiency.
52 | P a g e
𝐸=
𝐹𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 ∆𝑃𝑉
𝜂𝑓𝑎𝑛
(4.2)
The result is an energy value of 7.7 x 109 J/m2yr. We can then divide this value by the capture
rate at the inlet per unit of area, assumed to be a value of 22t-CO2/m2year [51]. By
eliminating these parameters, the conversion to energy in kWh per tonne of CO 2 captured
becomes significantly simpler – this value allows for ease of comparison. The final value
obtained is 96.7 kWh/t-CO2, which is certainly reasonable.
4.4.4 Cycling
Low-flow regimes do however, detriment the system operation; it typically results in the
uneven wetting of the packing. With an unevenly distributed coverage of the packing, the
surface area for contact decreases and less CO2 can be captured per unit of solution.
Naturally, no system will have perfect wetting – an efficiency factor ‘ε’ exists for this
purpose. Industrial wetting efficiencies typically range from 0.5 to 0.8 [53], but methods to
keep this value higher in range are commonly employed. One such method is known as
cycling; that is, a controlled rotation between short periods of high flowrates and ensuing
long periods of low flowrates. These pulses work have vastly differing effects, but work in
congruence to maintain both energy and capture efficiency – the pump does less work and
channel blockages are avoided. The aim of a high flowrate cycle is to remove any debris and
dust travelling with the incoming air, thereby flushing the surface of the packing.
Subsequently, the aim of a low flowrate cycle is to continually wet the surface packing; as
solution distributes over the surface (albeit unevenly), CO2 is partially absorbed.
Experimentation conducted by Mahmoudkhani et al. demonstrates the effect of cycling.
Throughout these low flowrate periods, fluid is being retained by the packing – the quantity
of CO2 captured was 80% of typical values [53]. Indeed, the efficiency reduces as the solution
diminishes; however, such results provide evidence for the assumption that ε = 0.8.
Figure 8 - Decay from Cycling [53]
53 | P a g e
Fluid pumping requirements nonetheless, are practically negligible when compared to the
energy requirement of fanning air. To calculate the hydraulic power of the pump, the
following parameters are required:
•
Volumetric flowrate of NaOH – Q (m3/h)
•
Density of NaOH – ρ (kg/m3)
•
Acceleration due to gravity – 9.81 (m/s2)
•
Pump head – h (m)
Determining the volumetric flowrate of NaOH is simple. Given a need to capture 1t-CO2/day
and that 20g of CO2 require 1kg of 2M NaOH solution, 3.t-NaOH/day is necessary.
Dimensional analysis and dividing by the density of NaOH (2130 kg/m 3) gives Q = 0.98
m3/h. Pump head on the other hand, generally requires pipeline diameter and length, the
number of fittings and elbows (including respective geometries). To simplify the calculations,
a pipeline diameter of 0.10m is taken and no fittings or elbows are utilised.
This results in a cross-sectional area of 0.0314 m2 and therefore a velocity of Q/A = 0.01 m/s.
We can then substitute all known values into the pump head formula:
ℎ=
𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐷𝑟𝑜𝑝 𝑉𝑒𝑙𝑜𝑐𝑖𝑡𝑦 𝑜𝑓 𝑓𝑙𝑢𝑖𝑑
+
𝜌𝑔
2𝑔
(4.3)
We therefore get an h = 0.005m, a value that is undeniably low. Let us then assume a value of
h = 5m in calculating the hydraulic power of the pump. The equation below is used:
𝑃𝑜𝑤𝑒𝑟 (𝑘𝑊 ) =
𝑄𝜌𝑔ℎ
3.6 ∗ 106
(4.4)
Even with a pump head of 31.1m – as suggested by manufacturer Bedu Pompen (CT 61
series) - the energy required is 0.33 kW on a per hour basis [60]. For a 1t-CO2/day equivalent,
this is still less than 1 kW and accordingly, is negligible compared to the fan requirement of
97 kW/t-CO2. It should be noted however, that fluid pumping is usually 15% of total
contacting energy [53], though this will not be considered.
54 | P a g e
4.4.5 Sorbent Geometry
The next concept assessed within the contactor design is sorbent geometry. This plays a
pivotal role in determining the CO2 uptake and pressure drop, and has two states:
1. Fixed geometry system – this is surface-uptake limited; the sorbent strength decreases
until this state occurs.
2. Fixed sorbent system – this is airside limited; the boundary layer thickness governs
this state.
In a surface-uptake limited system, high partial pressures are commonplace. As a result,
reducing the strength of the sorbent (the concentration) will reduce the amount of CO 2
absorbed by the surface, however momentum remains unchanged. Naturally, these systems
maintain high pressure drops, which as discussed above, is detrimental to the efficient
operation of DAC. On the other hand, an airside limited system maintains low concentrations
of CO2 on the surface of the sorbent, despite a large fraction of CO2 being transferred as
initial momentum dissipates. Minimising the thickness of the boundary layer leads to a
smaller airside transfer coefficient, thereby increasing the absorption of CO2 in the sorbent
per unit surface area [61]. Subsequently, less equipment and chemicals are needed. This
represents the trade-off between sorbent geometries; the energy requirement must be
minimised by sustaining low pressure drops throughout operation, but the uptake rate of CO 2
must be high enough to reduce purchased material cost. When optimising the operating
system between these two states, the concentrations (and therefore partial pressure) of CO 2 at
the surface, must lie between some negligibly small value and that of ambient air [61].
4.4.6 Accommodating the optimised model
The selection of a 1-2M NaOH sorbent requires a boundary layer thickness that upholds both
the 100Pa pressure drop and an adequate CO2 uptake. Theory suggests that the choice of such
a sorbent necessitates a layer of a few millimetres (maximum) [52], which corresponds to the
low flow regime speed of 1-3m/s. Keith et. al utilise a 50µm film that flows vertically
through a packed cooling tower, while air flows horizontally – that is, a cross-flow
configuration. The calculated thickness is based on an Aspen Simulation in congruence with
an Excel module to determine the most ideal operating conditions [51]; despite the flow
reversal in this investigation, a 50 µm will be used.
In order to determine the capture fraction of this mode, the final parameter that must be
calculated is the mass transfer coefficient – through stoichiometry and linear ordinary
differential equations.
55 | P a g e
The reaction occurring in the contactor, that is CO2 absorption by NaOH is as follows:
2NaOH (aq) + CO2 (aq) → Na2CO3 (aq) + H2O (l)
Bird, Stewart and Lightfoot (2006) showed that this reaction can be broken into segments.
1. CO2 transport to the liquid film over the packing;
2. Air/liquid equilibrium;
3. CO2 diffusion through the boundary layer;
4. Reaction between hydroxide and CO2;
5. OH- and CO32- diffusion within the film.
Deriving a linear differential equation predominantly focused on segments 3 and 4 becomes
relatively simple, as these form a constraint to mass transfer [62].
𝛿𝐶
1
= 𝐷∇2 𝐶 − 𝐶
𝛿𝑡
𝜏
(4.5)
Where C is the concentration of CO2, D is the diffusivity of CO2 in solution and τ represents
the limiting rate constant for the reaction between CO2 and the hydroxide. These values are
obtained from literature on DAC, utilising a similar process of air contacting.
This ODE can be further simplified by assuming: steady state in the concentration – all time
derivatives tend to zero, that concentration is only a function of depth and that we have a
stagnant film – if diffusion is constant, there is no accumulation in the film. Solving the new
equation at the boundary condition – interface concentration = Henry’s constant x initial
concentration – gives a formula for the mass transfer coefficient in mm/s.
𝐾 = 𝐻√𝐷𝑘𝐶𝑂𝐻−
(4.6)
As a consequence of literature marginally varying on the values of diffusivity, reaction rate
constants and Henry’s constants, a range of mass transfer coefficients have been generated
[62]. They span 0.6 mm/s to 5 mm/s, and as such a rather conservative average of 3 mm/s has
been taken. Whilst this may too high to be classified as ‘conservative’ a ‘K’ of this size is
paramount in ensuring the overall feasibility of the process. Further investigation into optimal
packing geometries, humidity, velocity and flowrates may reduce the range significantly, and
home in on a viable process. Having all the necessary values allows us to determine the
capture fraction – 60%.
𝜀
1 − 𝐶𝐹 = 𝑒 −𝑆𝑆𝐴∗𝐷∗𝐾∗𝑉
56 | P a g e
(4.7)
This is a relatively low capture fraction but subject to increases if the air velocity was more
finely tuned or the packing depth increased. From a perspective of scaling, this process is
more likely to capture a greater quantity of CO2. Associated risks with the air contactor can
be placed in two broad categories – environmental and sustainability, and performance and
operational.
Classification
Description
Operational
Leakage of chemicals from pipeline
Mitigation
•
or spills.
Safe handling methods and
alarms on pipelines for
deviating flow.
Environmental
NaOH droplet dispersion, which may
•
react in the environment.
Include demisters at each
theoretical stage in the
contactor – integrates well
with the system and
maintains low pressure
drops.
•
Operate in a low flow
regime to reduce droplet
generation.
•
In periods of high solution
flow regimes, steady
particle loss by tuning the
fanning process – reduce
air flow.
Operational
Useful life of packing – subject to
•
dust and debris accumulation over
Cycling to ensure that dust
and debris are cleared.
time and risks fouling, as well as the
constriction of channels.
Table 13 - Classification of Risks [52]
Further to the above risks, there are certain advantages and disadvantages with setting of the
system – open or closed. Whilst a closed system maintains strong advantages when
performance risk and technology are omitted, an open system is generally more feasible. A
clearer assessment of the two systems is shown below.
57 | P a g e
Figure 9 - Open versus Closed Contactor Systems [52]
58 | P a g e
4.5 Pellet Reactor
Following the absorption of CO2 and production of Na2CO3, the carbonate ion must be
removed from solution via causticisation. This particular unit operation is comparably less
energy intensive than both contacting and calcination.
Caustic recovery has been utilised in industry for a number of years, commonly for the
production of paper. In such reactions, Na2CO3 reacts with lime, generating calcium
carbonate (CaCO3) and pure NaOH – it is a regeneration step. Earlier literature on DAC
implemented this initial process, until more favourable processes were devised.
Na2CO3 (aq) + Ca(OH)2 (s) → 2NaOH (aq) + CaCO3 (s)
However, a major issue presents itself in the form of a minimum thermodynamic
requirement. In conventional recovery loops, causticisation necessitates 179 kJ/mol CO 2 at
standard operating conditions (ideal for DAC). The absorption of CO2 into an NaOH film – at
a concentration of 1-2M – consumes 109.4 kJ/mol CO2. Accordingly, the minimum
thermodynamic energy is well below that required for causticisation; the process must be
modified to ensure feasibility. Mahmoudkhani et. al (2009) indicated that drawbacks include:
•
Relatively large consumption of high temperature energy;
•
Efficiency of conventional recovery loops are limited to 80%; and
•
Regenerated NaOH is limited by its original concentration i.e. 1-2M.
A number of processes have been thoroughly examined, the most notable of which are autocausticisation and direct causticisation. In direct causticisation, titanates are currently being
researched; properties are favourable as a supplementary process for calcination or as a
complete substitute [53]. The primary advantage of using titanates stems from the
significantly lower enthalpy of reaction – 90 kJ/mol CO2 – which is practically half as
intensive as the conventional method mentioned. Nonetheless, this process faces significant
headwind in an air capture context because of a difficult chemical extraction need; dry,
anhydrous Na2CO3 must be removed from the rich NaOH solution [53]. Theoretically, the
extraction would occur in a two-stage crystallisation and precipitation unit:
1. Crystallisation – Na2CO3.10H2O is crystallised from a concentrated alkaline solution.
2. Precipitation – Na2CO3 precipitates from the saturated solution, whilst sodium pentatitanate is hydrolysed at high temperatures. This adds aqueous NaOH to the process
solution, and forces the precipitation – this NaOH is regenerated and recycled.
59 | P a g e
As such, a more efficient method for removing the carbonate ion from solution is needed.
Keith et al. (2018) suggest the utilisation of a pellet reactor, adapting its use from various
waste and water treatment technologies. The pellet reactor consists of an oxy-fired circulating
fluidised bed (CFB) – implemented heavily in the chemical, mineral, environmental and
energy process industries [51]. The steps undertaken within the reactor and the associated
specifications are highlighted in the table below.
Steps
Parameter Values
1. CaCO3 pellets are suspended in an upward-
•
flowing solution.
Pellet diameter ranges
from 0.1 to 0.9mm.
2. Ca(OH)2 enters through the reactor bottom – Ca2+
•
2-
react with CO3 , removing lime from solution.
suggested to be
3. Miniscule pellets then enter at the top,
agglomerating and sinking until their exit from
The solution flowrate is
approximately 2 cm/s.
•
the bottom.
The lime slurry has a
concentration of 30%.
4. Calcium leaves the bottom of the reactor as a fine
•
10% of the total calcium
particle, whilst the pellets are captured by a filter;
leaves the reactor as fine
these pellets are effectively calcite crystals.
particles.
Table 14 - Operation of the Pellet Reactor
In waste and water treatment processes, slurries maintain a concentration of approximately
2%. This strays noticeably from conventional recovery processes in that the lime slurry has a
concentration of 30%; it places greater importance on maximising caustic flux and that
NaOH is the limiting reagent [51] .
Given that the process utilises pellets instead of ‘lime mud’, it performs substantially better
than the Kraft loop. Pellets facilitate efficient transport, and are easily washed and dried – this
allows reuse through less energy intensive means. Furthermore, vacuum filtration – as CO2 is
typically removed as a solid – can be omitted from the system, and permits the use of a CFB
rather than the conventional rotary kiln. The primary disadvantage of rotary kilns is that they
consume 60% more energy, both for precipitation or calcination purposes than other methods.
The selection of a pellet reactor and oxy-fired CFB therefore reduce the energy consumption
of the overall process [51] – a valuable characteristic when considering the predominant
barriers to implementation of DAC.
60 | P a g e
To determine the minimum fluidisation velocity in a laminar flow regime – for which this
paper investigates – the following equation must be utilised:
𝜐𝑓 =
𝑔 Δ𝜌 𝜀 3 𝑑 2
180 𝜇 1 − 𝜀
(4.8)
Where vf represents the minimum velocity, Δρ is the density differential between the CaCO 3
pellet and the lime slurry, µ is the dynamic viscosity of the lime slurry, ε is the porosity of the
CFB and d is the particle diameter; the values are listed below.
•
g = 9.81 m/s2;
•
Δρ = 2710 kg/m3 * (0.3*2210 kg/m3 + 0.7*1000 kg/m3) = 1347 kg/m3;
•
µ = 0.001 kg/m/s;
•
ε = considered negligible, thus a value of 0.1 is taken; and
•
d = 0.9mm.
Substituting the values into equation 4.8, we arrive at a minimum of 0.66 cm/s, which
justifies the use of any higher velocity – in this case, 2 cm/s. The energy consumption of the
pellet reactor now requires the loading rate and efficiency of the CFB, as well as the
previously determined minimum fluidisation velocity. Experiments at a pilot-scale conducted
by Keith et al. have shown that calcium loading rates range between 20-40 kg-Ca/m2h, with
the exact value depending on a variety of factors [51]. These include:
•
Bed height and energy performance;
•
Retention rates – defined as the quantity of Ca that exits the reactor as a pellet, rather
than fine particulate (which moves to disposal or the calciner);
•
Pellet sizing at the base of the fluidised bed – this has foundations in the initial
diameter of the pellets, as well as the seed crystals entering the top; and
•
The number of nucleation sites for calcite precipitation.
The results demonstrated that loading rates of 40 kg-Ca/m2h generate the most efficient
energy performance, to the detriment of higher capital costs and footprint. A plant capturing
1t-CO2/day approximately requires a height of 10m and a 1.7m diameter has been linearly
adjusted from literature values. The pumping energy utilises equations 4.3 and 4.4, in
congruence with the above values, to establish a value of 96.8 kWh/t-CO2.
61 | P a g e
4.6 Calcination
The next step is recycling the calcite precipitate – accomplished through calcination. This
consists of a thermal treatment facility applied to solid materials, resulting in their
decomposition, phase transition and subsequent removal of a fraction of interest – in this case
CO2 – from the solution. Three necessary parameters must be controlled to ensure the
efficient dissociation of CO2 from CaCO3:
1. Temperature of the reaction
2. Duration of the calcination process
3. Concentration of CO2 in the surrounding atmosphere
CaCO3 (s) → CaO (s) + CO2 (g)
The most noteworthy evaluation metric is the thermal efficiency of the extraction process,
which is defined by the theoretical heating requirement times the available quantity of oxide,
divided by the total heating requirement. The upper range of efficiencies that exist are 8593% of available lime; that is, the closeness of the process energy consumption to the
theoretical minimum. Given the enthalpy of reaction to be 179.2 kJ/mol-CO2, the total
heating requirement as suggested by Zeman et al. (2004) is 4.5GJ/t-CO2 [63].
Any advancement in technology or substitution of operating units that result in reductions of
the abovementioned parameters, will undoubtedly increase the feasibility of DAC – it lowers
the heat input [63]. It should be noted however, that higher temperatures would increase the
reaction rate of calcination (following reaction rate theory). As such, further optimisation
would be required to determine the ideal trade-off between duration and temperature.
The reaction rate may also be influenced by incorporating steam. Studies have shown that
substituting a steam cycle for heating substantially increased the rate of calcination, whilst
operating at temperatures on the order of 753K [64]. This particular experiment generated a
95% conversion rate, with a composition of 79% helium, 21% steam. In a similar manner, a
60% steam cycle required temperatures typical for conventional calcination – 1173K;
however, the conversion rate of 98% and the production of 30% more active CaO
demonstrate additional benefits [64]. Temperatures this high are significant economic
drawbacks, but methods to reduce the enthalpic value of such a process have been researched
for decades. One such example is an original steam dryer by Theliander and Hanson [63],
decreasing the overarching enthalpy by 33%. Further conclusions drawn from investigations
into steam cycling include:
62 | P a g e
•
An increased sorbent capture capacity of CO2 – higher steam dilution at atmospheric
pressure resulted in greater CaO sorption capacities, particularly in relation to the
structural characteristics e.g. surface area and volume [65];
•
Heightening dilution results in lower operating temperatures to achieve the desired
level of calcination; and
•
After multiple cycles, the decay in sorption capacity is super-linear regardless of the
operating conditions.
This final conclusion is a significant shortcoming of using steam, especially in the context of
scaling. Multiple cycles are undoubtedly needed for calcination dealing with high flowrates;
accordingly, another process must be implemented. In similar vein to the pellet reactor, the
calciner this paper investigates will consist of an oxy-fired CFB. The specifics of oxy-firing
and the associated design choices will be addressed in Section 4.9.
Prior to calcination, a pre-treatment step is necessary to reach the required operating
temperatures to dissociate CO2 from CaCO3 – this occurs in a series of cyclones. Both the
calciner and cyclones are constructed from stainless steel, with internal layers of refractory
material. It is possible to achieve the desired temperature in two heating cycles, with large
changes in the temperature of the gas and entering solids. The sequence of events occurring
in this unit operation are:
1. Pellets travel toward the calciner from the slaker at ~300°C, passing through two
cyclones in a counter-current configuration to the passing gas stream.
2. The first cyclone heats the pellets to 450°C, whilst the gaseous stream is reduced from
650°C to the same temperature.
3. The second cyclone steps up the solids’ temperature to 650°C, whilst the direct gas
stream is cooled to the same temperature from 900°C.
4. Energy from the gaseous stream is conserved through its use in a steam superheater;
this unit generates power for downstream processing.
5. Finally, the resultant CaO is cooled from 900°C to ~650°C; this heat exchanger in
turn heats the incoming oxygen from the ASU to this temperature before the CaO
moves to slaking [51].
This entire process operates at ambient pressure, as pressure drops are unfavourable for
efficiency and energy purposes. In the calciner, fluidising gas enters through the bottom on a
distribution plate, whilst natural gas is inoculated directly above this location [51]. The setup
63 | P a g e
itself ensures maximum heat integration – all heated streams exchange with another until the
superheater, where heat energy is converted to power. In doing so, the operational risk of the
system is not compromised; in stark contrast to existing technologies, there is no trade-off
between maximised energy efficiency and minimised capital cost, both are achieved
concomitantly [51].
There advantages this form of calcination maintains over other methods can be summarised
as follows:
•
Sealing equipment can be utilised to minimise any leakages of interest; in particular,
nitrogen – the pressure points being piping between the calciner and slaker, as well as
the inlet of the slaker itself [66];
•
Circulating fluidised beds have significantly higher capacities than typical rotating
kilns. Given the same diameter of ~6m, CFBs have a capacity of 2 kt-CaO/day whilst
the foremost rotary kiln (with a markedly higher length of 165m) holds 1.6 ktCaO/day;
•
The system exhibits a very low energy penalty (<6%) when compared to similar
capture technologies – the heating requirement for calcination can translate to
electrical energy for power generation;
•
Limestone is a relatively cheap and abundant material geographically – minimal
capital investment is required to this end; and
•
In an overall sense, this design is 78% more thermally efficient than a lime mud
calciner – the pellets and capture efficiency of upstream processes aids with this.
Finally, the direct energy requirement for the calcination process stems from the reaction
enthalpy. Given that enthalpy is 179.2 kJ/mol-CO2, we can then divide this value by the
molar mass – 44 g/mol – to derive a mass-based energetic requirement. The per day target of
1 tonne results in a minimum energy demand of 4.07GJ/t-CO2. Naturally, no process can run
at optimal efficiency for the full period of time; accordingly, a conservative value of 80%
efficiency is taken, culminating in an energy usage of 5.1GJ/t-CO2 [66]. The size of the
calciner at this level is difficult to estimate, but the riser of the fluidised bed is reported to be
on the order of 8.5m [51] for a pilot-scale plant.
As with any chemical process, mitigating both operational and environmental risks is a
priority. Fortunately, no harmful chemicals are disposed or released in calcination. However,
64 | P a g e
there are three specific operational risks that must be considered; stable combustion, recarbonation fouling and alkali fouling.
Stable combustion necessitates high oxygen content – under a certain percentage, incomplete
combustion occurs, releasing carbon monoxide – arguably more toxic than the emissions this
process aims to prevent. This can be achieved with a feed rate of approximately 2160 kgCaCO3/day and [O2] ≥ 20% [51].
Another prominent risk arises in the agglomeration of particular matter in the fluidised bed
combustion system. The interface between, and amalgamation of these particles and ash –
specifically from sintering (which is difficult to reduce without the substitution of steam) –
are considered the primary causes of CFB fouling [65]. Sintering occurs in the calciner
temperature range of 650°C-900°C, but common mitigation techniques for slagging, fouling
and corrosion (occurring in pulverised coal combustion), are difficult to adapt to this
instance. CFBs are subject to deposit formation within the preheat cyclones and post-cyclone
gaseous channel (the back-pass) [64], hindering movement in these dense areas. Determining
that the rate of fouling was markedly low has been suggested as a goal by Carbon
Engineering in its commercial operation [67].
Should the temperature fall beneath the re-carbonisation range, CaO and CO2 react to form
CaCO3, which generates a layer of deposit on the bottom and sides of the vessel. In contrast,
alkali fouling – typically sodium or potassium – is facilitated by carry-over from the pellet
reactor phase. It should be noted however, that conventional methodology (the Kraft process)
would result in notably higher rates of alkali fouling; the use of a CFB limits carry-over [64].
Several techniques have been proposed to limit exposure to these risks, involving:
•
Introduction of ‘pincering’ air between the preheaters and piping;
•
High pressure – 1.5MPa – soot-blowing at the associated blockage sites;
•
Implementation of fluidising pads to enhance material flow and hopper screens; and
•
More precise temperature control.
With the introduction of these elements to the system, scaling to a commercial size becomes
demonstrably less constrained [51].
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4.7 Slaking
The final major unit operation regenerates Ca(OH)2, powered by steam resulting from both
the superheater and the process itself. As opposed to a CFB, the slaker constitutes a bubbling
fluidised bed with a turbulent flow regime rather than laminar. It is however, lined with
refractory material in similar vein. The following equation describes the regeneration:
CaO (s) + H2O (l) → Ca(OH)2 (s)
Incorporating steam as both an input and product of slaking, engenders a number of
advantages over typical slaking utilised by the paper/pulp industry. Chiefly, the exothermic
enthalpy occurs at markedly higher temperatures in the Kraft process, whilst steam slaking
achieves the same reaction kinetics with lower energy consumption [1]. The maximum
operating temperature in conventional processes is approximately ~500°C, whilst pellets
leave the slaker at 300°C. The method of operation is described below:
1. CaCO3 pellets at standard temperature and pressure (from the pellet reactor), in
addition to CaO at ~650°C (from the final stage of preheating), enter the slaker.
2. These solids are bubbled through the fluidised bed from the bottom, at a speed in the
range of 0.5 m/s – 2m/s [51] – during the transportation and diffusion phase, the CaO
forms Ca(OH)2.
3. Any marginally smaller CaO particulates that bypass the initial reaction are elutriated
and re-enter the system through a sealed loop, whilst the finer particulates are
captured and disposed.
4. The product stream – a primarily solid slurry of Ca(OH)2 – leaves the unit at 300°C;
heat can simply be recovered and reutilised for heating of incoming components –
that is, the pellets from the stage 2 CFB. These pellets are then transferred into the
calciner [51].
The energy production from steam slaking uses similar calculation methodology to the
calcination step. Firstly, the enthalpy of reaction per tonne of CO2 has been stated as -1.9 GJ
by Stolaroff et al. 2006 for this exact process. Converting this to an appropriate energy format
gives a value of 527kWh/t-CO2 – assuming 100% efficiency. This is substantially higher than
Keith’s estimate of 77kWh/t-CO2, derived from an Aspen simulation with optimised
parameters. As such, the more conservative value will be utilised, and the energy
consumption of the slaking process taken into account; this gives 36kWh/t-CO2 produced.
66 | P a g e
4.8 Compression of CO2
After the CO2 has been successfully separated from the system, compressors are required to
facilitate safe transport and/or storage, depending on the choice of reutilisation. The pressure
at which the gas must be compressed depends on a variety of factors, including the
properties, recovery rate, necessary purity for further applications and the location of the
storage site/distance of transportation.
In this paper, it is assumed that CO2 is compressed to 100bar – a value widely accepted in
commercial carbon capture and storage operations [67]. This means that the solubility of any
impurities – gases including nitrogen and oxygen – are exceptionally low in CO2. The
number of stages required for compression, and subsequently the power consumption can
then be ascertained using the following formulae:
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑆𝑡𝑎𝑔𝑒𝑠 =
𝑊𝑐𝑜𝑚𝑝𝑟𝑒𝑠𝑠𝑜𝑟
𝑃
ln(𝑃2 )
1
ln(3)
(4.9)
𝛾
𝑃2 𝛾−1
[( ) 𝛾 − 1]
= 𝑃1 ∗ 𝑄 ∗
𝛾 − 1 𝑃1
(4.10)
P2 and P1 represent the outlet and inlet pressures respectively, Q the volumetric flowrate of
CO2 from the calcination phase and γ, the ratio of specific heats – CP/Cv. Here, the ratio of
specific heats is taken to be the most common value = 1.4; note than a γ =1 would mean an
isothermal process. Upon compression, the resultant CO2 would be at a temperature of 45°C
and is thus a supercritical fluid [67].
Equation 4.10 with the stated inlet and outlet pressures gives a value of 4.17 – accordingly, 5
compression stages will be required to achieve the desired pressure for safe storage and
transportation. The work done by the compressor is 401.04 kJ/t-CO2, translating to a value of
142.1 kWh/t-CO2 – a value not too distant from conservative estimates [51]. The isentropic
efficiency of compression is assumed to be 100% in this instance, given the large energy
consumption in comparison to other unit operations.
67 | P a g e
4.9 Oxy-firing – CFB versus Pulverised Coal and Air versus Oxygen
CFB combustion maintains a number of characteristics pertinent to DAC’s overall feasibility,
given its increasing use in conjunction with CCS. At 2004 year-end, the global capacity for
CFBs held a level of 17 GWe but this value increased to 46.5 GWe by the end of 2010. These
characteristics and advantages over PC options are shown in the table below:
Advantage
Implication
Low operating temperature range of
Markedly lower energy consumption and
approximately 650°C-900°C
also reduction in the formation of NOx
Fuel flexibility – anthracite, lignite, coke,
Given a wide variety of options, the system
biomass and opportunity fuels
can be further optimised based on material
sourcing and specific needs
Uniform heat flux
Aids with ensuring complete combustion and
efficient generation
Remarkable load-following ability
The process can be tuned to match the
required energy demand
With increasing oxygen concentration,
Reduction in the furnace/boiler size, which
volumes of gas decrease
further reduces capital cost - this constrains
PCs, but surface arrangements are more
simply modified in CFBs
No burner redesign necessary
In PCs, customised manufacturing is required
to modify properties that affect safety,
combustion efficiency and the emissivity of
NOx. CFBs need only control the
concentration of incoming O2.
Simpler transition from air-firing to oxy-
Air-firing is necessary for start-up and
firing
shutdown procedures; as such, switching
between modes is enabled further by CFB
material – allows temperature to be
controlled.
Table 15 - Circulating Fluidised Bed Advantages [68]
A selection must then be made between air-firing and oxy-firing – this has significant
implications for both the energy consumption and thermodynamic efficiency of the system.
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Combusting fossil fuels in the presence of highly concentrated oxygen, as opposed to air,
signifies an opportunity to increase the efficacy of CO2 capture. Almost the entire nitrogen
content of air is removed, resulting in a stream of > 95% oxygen [68]. The primary
technology at a commercial scale is cryogenic distillation – this technique produces the
desired quantities of O2 at the necessary purity in an economic manner. Further air separation
methods exist, including the use of membranes, pressure swing adsorption and vacuum swing
adsorption; however, the technology readiness level is significantly lower and are unable to
contest the economic feasibility of cryogenics.
Despite the fact that cryogenics have been commercially employed for decades, the industry
has continually achieved efficiency milestones [69]. Improving productivity within the
distillation column itself and the energy consumption of the process are two specific ways in
which this can occur. The following figure shows growth in the techniques capability to do
so, particularly given that actual energy consumption is substantially higher than the
thermodynamic minimum.
Figure 10 - Gains in Cryogenic Air Separation [69]
The differences between air and oxy-fuel combustion, in terms of both characteristics – flame
temperature, flame ignition and emissivity – and the advantages/disadvantages are shown in
Table 16. These arise from the variety of unit operations that constitute an ASU, including:
•
The primary air compressor;
•
The precooling system – reducing air to the necessary temperature;
•
An air purification system that facilitates the removal of both water and CO 2;
•
Multiple heat exchangers to conserve energy; and
•
Distillation columns and the associated reboiler and condenser.
69 | P a g e
Characteristics
Advantages
•
Large size (footprint) and therefore capital cost;
•
Low pressure requirements – typically 1-2 bar; and
•
High oxygen purity – 95.0-99.8%.
•
Lower flue gas recycling – 60% - thereby reducing the
footprint and auxiliary consumption;
•
Higher degree of mixing in the furnace and increased
residence time, resulting in burnout suiting low-reactive
carbon;
•
Volume of gas flowing through the furnace is reduced, thereby
diminishing the volume of flue gas emitted by ~80%;
•
Decreasing the likelihood of leakages given operating
temperatures of just over atmospheric pressure;
•
Concentration of O2 in recycled flue gas can be minimised,
whilst O2 can be injected into the system via separate lances –
no new burner design is needed; and
Challenges
•
Able to incorporate steam cycles to conserve energy.
•
Oxyfuel combustion necessitates higher concentrations to
achieve the same flame temperature;
•
When combined with storage, additional units – those that are
not necessary in conventional plant configurations – consume
significant power, thereby reducing the efficacy per unit
energy;
•
Large footprint associated with the air separation unit and the
purification of CO2; and
•
The technology readiness level of oxyfuel combustion is still
significantly lower than commercial air-fired plants – there is
notable room for improvement.
Table 16 - Oxyfuel Combustion Analysis [70]
Nonetheless, the most economically feasible option is to utilise pure oxygen. This avoids the
tedious and energy intensive separation of CO2 from N2 post-calcination. Should air-firing be
employed, a substantial quantity of N2 would be present with the CO2 and water,
necessitating an additional post-combustion capture system [1]. A notable ASU vendor
quoted an energy consumption of 238 kWh/t-CO2 for this scheme [51].
70 | P a g e
4.10 Other Auxiliaries
Two particular auxiliaries must be mentioned, as they increase the efficiency of the overall
process and contribute to lower CO2 emissions – commonly found in power plants [70]. Gas
turbines are used to turn fuel into electrical energy, with any excess being recovered by a heat
recovery steam generator (HRSG) from the turbine exhaust stream. High pressure steam from
this boiler can be utilised by the steam turbine, sitting between the calcining and slaking
mechanisms, thereby generating additional clean power for the plant [70]. The exhaust stream
itself is sent into an absorber, which removes approximately 80% of the CO2, before
condensing and being sent through the air contactor loop. The energy requirement and capital
cost of these units are not negligible (see Chapter 5).
4.11 Alternative Configurations
Changes to the described system will not be investigated further in this paper; rather, a
sensitivity analysis on various parameters will be conducted in Chapter 5 – the economic
analysis subsection. If alternative configurations were to be examined in more detail, the
factors below would require greater design.
•
Optimising the transition between air-firing and oxygen firing;
•
Changing the nature of compression in terms of design choices and specifications–
this is dependent on application e.g. storage or reutilisation; and
•
Ascertaining the most viable power supply – rather than sourcing from the grid, is
geothermal, nuclear or renewable power (or some combination of such) employable.
71 | P a g e
Chapter 5: Costing and Sensitivity Analysis
Despite having the highest technology readiness level, the costing associated with the chosen
process may be significantly improved. A number of simplifying assumptions are made
throughout this investigation, which indeed result in a variable cost of capture. Both capital
and operating costs are subject to efficiency increases through substitution of equipment,
recycling energy through heat integration, or switching to more affordable power sources.
Nonetheless, this is all dependent on the location, the surrounding regulatory environment,
and the willingness of companies to invest time and capital in such a project.
5.1 Equipment Sizing and Purchased Equipment Cost
The purchased cost of equipment (PCE) is intrinsically linked to the capacity of each unit,
and its material of construction. In order to determine the capacity, surface area or the power
output, a material balance was conducted; the foundations of this calculation were derived
from the stoichiometric ratios from the chemical equations listed in Chapter 4.
Unit Operation
Capacity
Purchase Cost (AUD)
Industrial Fan
20.0 m3/s
4207
Centrifugal Pump 1 & 2
0.05-0.15 m3/s
Thermoplastic Packing
31.1 m3
56766
11679
Packed Column
5.30 m3
39481
CFB Reactor 1 & 2
1.0-3.0 m3
78118
Rotary Filter
0.40 m3/s
27255
Cyclone (inlet area)
1.15 m
2
Steam Heater
0.05 m /s
10692
16038
Steam Turbine
36.0 kWh
20885
BFB Reactor
1.0 m3
8019
Shell and Tube Heat Exchanger
0.25 m2
17642
Air Separation Unit
N/A
19533
Centrifugal Compressor
142.1 kWh
151858
CO2 Absorber
0.01 m3/s
12491
Gas Turbine and Regenerator
2.30 kg-CH4/h
24982
3
Total Purchased Cost of Equipment
499646
Table 17 - Purchased Equipment Cost Results
An example calculation for the purchased cost of the industrial fan is as follows:
72 | P a g e
•
Air passes through the fan at 16.3 m3/s; assuming an operating efficiency of 80%, the
fan must at least accommodate 20 m 3/s – hence the capacity.
•
316 Stainless Steel was chosen for the material of construction, specifically because it
is extremely resistant to corrosion. Given its necessity to the overall operation,
downtime on the fan would undoubtedly be unfavourable, thus a greater initial
expense must be placed into this. Stainless Steel has an ‘exponent’ of 1.3 – that is, the
costing estimate calculated must be multiplied further by this value.
•
Peters and Timmerhaus (2006) suggest that industrial fans within the designed
capacity have a cost exponent of 1.17 [72]. For the industrial fan, typical constants
used to determine the PCE were not available; the following formula was used.
o The comparison was drawn from Carbon Engineering’s design of the air
contactor unit – a capacity of approximately 59,000 m3/s and a cost of $26.3
million was substituted into the equation.
𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝑜𝑓 𝐴 1.17
)
𝐶𝑜𝑠𝑡 𝑜𝑓 𝐴 = 𝐶𝑜𝑠𝑡 𝑜𝑓 𝐵 (
𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝑜𝑓 𝐵
•
(5.1)
The resulting value was cost of US$2987 – the current exchange rate of 0.71US for
1AUD was implemented to derive a value of $4207.
o A check was conducted to ensure the value seemed reasonable for the scale –
$4207 for 1t-CO2/day was scaled to 1Mt-CO2/year, giving a value of $11.5
million – roughly half of the Carbon Engineering estimate.
In further calculations, the constants were indeed required to determine the PCE of unit
operations, as manufacturers/vendors and literature could not provide current data. The
prominent formula was in the form of:
𝐶 = 𝑎 + 𝑏𝑆 𝑛
(5.2)
Where ‘a’ is a baseline costing constant, ‘b’ is a constant depending on the type of
equipment, ‘S’ is dependent on the size/output of the equipment and ‘n’ is the exponent.
Inputting these values in returns a cost; depending on the year of publication, this cost must
be further adjusted by a reputable chemical engineering cost index – taken from Sinnott – to
increase the accuracy of the estimate [73]. The formula utilised is a variation on equation 5.2,
where capacities of A and B are swapped for Year A and B, with the corresponding exponent.
73 | P a g e
Additional corrections for temperature and pressure were also taken into consideration, and
implemented in the units that operated in these regions. Typical values ranged from 1.1-1.3
times the equipment cost.
5.2 Capital Cost and Operating Cost
Capital Cost (CAPEX) and Operating Cost (OPEX) are both contingent on the PCE – though
indirectly. They are comprised of a multitude of parameters, detailed in the following
subsections. These values could then be used to obtain the total cost of constructing and
operating the plant, and therefore the cost of capture per tonne of CO 2.
5.2.1 Components of CAPEX
There are two specific categories within CAPEX – the fixed capital investment and working
capital; the former can be divided further into direct and indirect costs. Fixed capital
investment (FCI) involves the design, construction and installation costs associated with unit
operations in the plant. This model assumes the inclusion of the follow components:
Direct Costs
Indirect Costs
Purchase Cost of Equipment
Contractor’s Fee (5% of Direct Costs)
Piping (45% of PCE)
Contingency (10% of Direct Costs)
Equipment Erection (45% of PCE)
Engineering and Supervision (5% of Direct Costs)
Instrumentation (15% of PCE)
Construction Expense (10% of Direct Costs)
Buildings and Process (10% of PCE)
Storage (5% of PCE)
Site Development (5% of PCE)
Table 18 - Capital Costing Weighting Assumptions [73]
•
These fixed capital costs specifically involve major process equipment, the associated
addons (piping, wiring, insulation, paints etc.), civil construction (roads, ditches,
sewers, pilings), and further construction and labour.
o Contingency is also required in any project – should the worst case scenario
come to fruition, there must be a reserve or backup plan. This may come in the
form of raw material / material of construction price fluctuations, currency
changes (thereby altering shipping and transport costs), union and contractor
disputes and other unexpected circumstances.
74 | P a g e
Offsite costs are typically costs associated with retrofitting and establishing an external
generation plant. Given DAC requires the construction of an entirely new plant, offsite costs
are mostly included within the capital cost estimate e.g. the ASU plant.
Working capital on the other hand, is generally a fixed percentage the CAPEX – this
investigation has assumed 15%; that is, divide fixed capital investment by 0.85 to determine
the CAPEX. In accounting terms, working capital is equal to current assets minus current
liabilities – the value this turns out has implications for the going concern of the project.
However, should the project fail, the working capital is indeed recoverable – value is derived
from inventories and cash on hand, and hindered by payables to debtors.
CAPEX, as we see later in the discussion, constitutes the majority of total capture cost at all
scales. Therefore, the accuracy of these estimates have implications for the economic
feasibility of the project. A slight change in the fixed percentage given to these costs may
result in large changes to overall cost. Considering the AACE International Cost Estimate
Classes, the model described falls into the accuracy range of:
•
Preliminary – this is known to be ±30% [73];
o At this level, choices can be made between design alternatives – highlighted
extensively within the process selection step.
o Despite being initially founded on similar case studies – used for screening
and feasibility studies (as this paper is) - this takes the design one step further
by undertaking more precise calculations.
•
Definitive – this is known to be ±10-15% [73];
o At this level, funding is provided to commence research and development, as
well as testing (up to a pilot scale).
It is difficult to obtain estimates anywhere past this level without conducting a highly detailed
design; that is, obtaining vendor quotes, planning the piping and instrumentation, process
control and general plant layout. The technology readiness level of DAC is already a
considerable obstacle to commercialisation; the scale-up of this process enhances the
uncertainty as only two plants exist as comparisons (releasing little data).
As such, the CAPEX table shown on the following page does indeed include provide a valid
estimate of the capital cost at 1t-CO2/day. However, further optimisation and more detailed
costing (from vendors) is required to determine the true feasibility of DAC.
75 | P a g e
Direct Costs
Factor (relative to PCE)
Cost ($AUD 000’s)
Purchase Cost of Equipment
100%
499
Equipment Erection
45%
225
Piping
45%
225
Instrumentation
15%
74.9
Buildings, process
10%
49.9
Storage
5%
24.9
Site Development
5%
24.9
(PCE)
Total Physical Plant Cost
1120
(PPC)
Indirect Costs
Factor (relative to PPC)
Contractor's Fee
5%
56.2
Contingency
10%
112
Engineering and Supervision
5%
56.2
Construction Expense
10%
112
Total Indirect Costs
337
Fixed Capital Invesment
1460
Working Capital
15%
258
Total Capital Investment
1720
Table 19 - CAPEX Results at 1t-CO2/day
Taking the total capital investment at face value, reaching the smallest commercial size (1MtCO2/year) would cost approximately $A4.7 billion, which is considerably higher than any
capital estimate recorded in literature. This is substantially diminished by economies of scale,
which as suggested in the MCA (see Chapter 3), is pertinent to the viability of this process.
Scaling exponents were taken from Coulson and Richardson, and applied to all direct costs.
The magnitude of the factor is indicative of the ease to which the component can be scaled –
the lower the factor, the greater the change [73].
Direct Cost
Power Factor
Purchased Cost of Equipment
0.7
Equipment Erection, Piping, Instrumentation
Buildings and Process, Storages and Site
Development
Table 20 - Capital Power Factors [73]
76 | P a g e
0.6
Naturally, the PCE maintains the highest power factor as vendors will not supply all
equipment needed; this reduces the likelihood and advantage of bulk purchases. However, a
value of 0.7 is more than reasonable – PCE constitutes approximately 30% of CAPEX and
thus large savings as the plant it scaled toward a commercial size. The rest of the power
factors in Table 20 maintain a value of 0.6, precisely because of bulk purchasing. This
efficiency extends to contractors – for example, the same construction company may be hired
for building and site development, and the space allocated for storage can be adjusted to
increase capacity.
Plant Capacity
Capital Cost
10t-CO2/day
50t-CO2/day
1Mt-CO2/year
Cost ($AUD millions)
Direct Cost
Purchased Cost of Equipment
2.50
7.73
127
Equipment Erection
0.89
2.35
26.0
Piping
0.89
2.35
26.0
Instrumentation
0.59
2.53
93.1
Buildings & Process
0.20
0.52
5.77
Storage
0.10
0.26
2.89
Site Development
0.10
0.26
2.89
Total Physical Plant Cost
5.29
16.0
284
Contractor’s Fee
0.26
0.80
14.2
Contingency
0.53
1.60
28.4
Engineering and Supervision
0.26
0.80
14.2
Construction Expense
0.53
1.60
28.4
Total Indirect Costs
1.58
4.80
85.2
Fixed Capital Investment
6.88
20.8
369
Working Capital
1.21
3.67
65.1
Total Capital Investment
8.09
24.5
434
Indirect Cost
Table 21 - CAPEX Results at Varying Scales
The highlighted case demonstrates the effect of the power factors; an initial estimate of
$4.7 billion has been reduced to a calculated estimate of $434 million.
77 | P a g e
5.2.2 Components of OPEX
The OPEX is a major determinant in the profitability of the project. As determined through
cash flow analysis – to be detailed in Section 5.4 – the OPEX in this process is markedly
higher than the revenue. A priority in cost optimisation therefore lies in reducing the
constituents of the production cost; these are split in variable costs and fixed costs.
Fixed Costs
Variable Costs
Maintenance and Repair (5% of FCI)
Consumables
Operating Labour
Utilities
Capital Charges (10% of FCI)
Disposal
Insurance (0.4% of FCI)
*Packaging and Shipping
Local Taxes (1% of FCI)
Plant Overhead (50% of Operating Labour)
Rent on Land/Buildings (1% of FCI)
Patents and Royalties (1% of FCI)
Table 22 - Operating Cost Weighting Assumptions [74]
The variable costs, as the name suggests, are most subject to change based on a number of
factors. Consumables in the process are comprised only of the solvents; that is, NaOH and
KOH. The quantity of solution required, in congruence with the purchase price per tonne
results in almost inconsequential costs (relative to other parameters). 3.7 t-NaOH/t-CO2/day
at $USD 650/t-NaOH results in $AUD 3400/day – 1.5% of total production cost (OPEX).
Utilities on the other hand, make up approximately 11% of OPEX and experiences notable
volatility. The three components are electricity, natural gas and water.
•
Electricity – current grid price (Ausgrid) = $AUD 0.29964/kWh;
o This value may change based on investigations into the levelised cost of
electricity of alternative power sources, and varies depending on the location
in Australia (and of course, across the globe).
•
Natural gas – ranges from $AUD 5-8/GJ; thus $AUD 6.5/GJ was taken.
•
Water – Sydney Water estimate for industrials - $1.86/m3;
o This stays relatively constant, but it was assumed that meter service charges
were negligible (as the size of the meter is unknown).
The sensitivity analysis conducted in this paper (see Section 5.5) demonstrates the effect of
changes in the price of electricity – this makes up the most significant portion of utilities and
was therefore examined in more detail. However, substituting renewable sources of power
78 | P a g e
removes the need for natural gas entirely, having implications for the OPEX of a potentially
more optimal process (covered in Section 5.5.4).
Packaging and shipping was not included because it is beyond the scope of this investigation.
Given an already insurmountable OPEX (at this current point in time), packaging and
shipping costs are assumed negligible – despite CO2 being assumed sold to an EOR
company, or for carbon credits.
Fixed operating costs maintain the greatest weighting in the total production cost, with two in
particular being the direct cause: operating labour and capital charges.
•
Operating Labour – for a fluids processing plant operating continuously, three shift
positions are required [74]. The salaries were estimated to be $AUD 83,000 (each) for
two engineers and $AUD 62,000 for a single shift supervisor.
o The total value of $AUD 207,000/year contributes to 30% of OPEX.
•
Capital Charges – 10% of FCI, which involves the repayment of interest on loans,
which are practically guaranteed for a project of this scale and higher.
o With an already high CAPEX, this parameter also contributes to 30% of
OPEX and only increases with scale, as no power factor exists for interest
payments – the rate is set and discounted according to the number of years.
However, power factors do exist for some parameters within fixed operating costs;
maintenance and repairs, and patents and royalties. In similar fashion, power factors exist for
both consumable materials and utilities, as these can be purchased in bulk.
Cost Type
Variable
Fixed
Parameter
Power Factor
Consumables
0.7
Utilities
0.6
Maintenance and Repair
0.6
Patents and Royalties
0.7
*Operating Labour
0.65
Table 23 - OPEX Power Factors [74]
The reason operating labour has an exponent, is because scaling would suggest a linear
increase in the number of staff required to run the plant. From a logical perspective, it would
be unreasonable to assume that 3 (the current number) must be multiplied by 2740 (the factor
adjusting the plant from 1t-CO2/day to 1Mt-CO2/day) to give 8220 staff. This alone would
79 | P a g e
result in an expense of $AUD 567 million, a value more than 500% of the OPEX for the
commercial case. Accordingly, an operating factor of 0.65 was chosen to reduce this expense
to a level that aligns with operating labour estimates from both APS and CE.
The table below provides OPEX estimates for all scales of the plant.
Plant Capacity
Operating Cost
1t-CO2/day
10t-CO2/day
50t-CO2/day
1Mt-CO2/year
Cost ($AUD millions)
Variable Cost
Consumables
0.009
0.044
0.136
2.239
Utilities
0.061
0.244
0.641
7.082
Disposal
0.002
0.024
0.122
6.696
Total Variable Cost
0.072
0.313
0.899
16.02
Maintenance
0.062
0.247
0.649
7.175
Operating Labour
0.176
0.668
1.902
25.67
Capital Charges
0.146
0.687
2.081
36.91
Insurance
0.005
0.027
0.083
1.476
Local Tax
0.015
0.073
0.226
3.726
Plant Overhead
0.088
0.334
0.951
12.83
0.015
0.069
0.208
3.691
0.015
0.073
0.226
3.727
0.521
2.179
6.326
95.20
0.594
2.491
7.225
111.2
Fixed Cost
Rent on
Land/Buildings
Patents and
Royalties
Total Fixed Cost
Annual Production
Cost
Table 24 - OPEX Results at Varying Scales
80 | P a g e
Comparison of OPEX at Differing Scales
Patents and royalties
Rent on land/buildings
Plant Overheads
Local taxes
Insurance
Capital charges
Operating Labour
Maintenance and Repairs
Disposal
Utilities
Raw Materials
0
500
1000
1500
Cost ($AUD 000's)
50t-CO2/day
10t-CO2/day
1t-CO2/day
Figure 11 - Breakdown of Operating Costs – The Effect of Scale
81 | P a g e
2000
5.3 Total Cost of Capture
When comparing Tables 21 and 24, it becomes evident that the ratio between CAPEX and
OPEX deviates significantly from the base case, as the process is scaled. The pie charts
below highlight this trend.
Composition of Total Cost Base Case
Composition of Total Cost Commercial Case
20%
43%
57%
80%
CAPEX
OPEX
CAPEX
OPEX
Figure 12 - Comparison of Capture Cost Composition
Economies of scale dictates that both capital cost and operating cost will reduce as the
process capacity increases, at varying rates. The reason we see such a large deviation from
the base case however, is a direct result of operating labour. This value was initially in the
same order of magnitude as the largest constituents of CAPEX (PCE, piping and
instrumentation), but ends up a factor of 5 less than PCE.
It stands to reason that the value of CAPEX is unable to decrease at the same rate as OPEX.
Taking CE’s air contactor as a reference, dimensions of 200m x 20m x 8m are necessary to
capture a suitable quantity of air. A structure of this capacity is estimated to have a cost of
$USD 132 million after optimisation, including the ancillary equipment and controls [51].
From a more cursory perspective of this unit operation in terms of its materials of
construction (stainless steel fans and supports) and footprint (1600m 2), one may assume that
the costing is accurate. Looking at the OPEX of this investigation at the same scale of
operation, the cost of the contactor alone has already surpassed its value. The physical plant
cost, whilst impacted heavily by economies of scale, is inherently high and therefore
decreases at a much smaller rate that the constituents of OPEX.
82 | P a g e
Further, the fixed operating costs incorporate both the power factor affecting the components
of FCI and the power factor of the parameter itself. The layering of these values results in an
exponential decrease; however, the values affected are minor in comparison to operating
labour and capital charges.
An additional case was included for the purposes of highlighting this trajectory – a plant that
aims to capture 5Mt-CO2/year, which moves toward the scale required to effect change in a
global warming context.
Composition of Total Cost 5Mt-CO2/year
13%
87%
CAPEX
OPEX
Figure 13 - An Extreme Case – Composition of Cost
This figure conclusively reveals that optimisation must be focussed on CAPEX rather than
OPEX. Such cost reduction may come through:
•
The substitution of equipment;
•
Simplification of unit operations;
•
Reductions in the price of materials of construction; and
•
A more suitable sorbent with respect to the uptake rate of CO 2.
Again, the presented compositions are estimates for a hypothetical system, and in actuality,
may not truly represent their weighting. As such, there exists notable scope for reducing
OPEX, including greater energetic efficiency through heat integration and implementing
renewable sources of power and government subsidisation to reduce capital charges.
83 | P a g e
5.3.1 The Result – Cost per tonne of CO 2 Captured
No literature has investigated a benchmark scale of 1t-CO2/day, instead choosing to address
an impactful scale of 1Mt-CO2/year. APS has suggested that 4Gt-CO2 must be captured each
year to reduce CO2 concentrations in the atmosphere to a manageable level, and accordingly,
projects at the scales examined here are negligible. They do however, provide insight into the
trajectory of DAC and the effects of various changes in parameters. The table below
highlights the range of capture costs associated with all scales of the plant, including an
extreme case of 5Mt-CO2/year. Taking the total cost and diving this value by the number
tonnes of CO2 captured by the plant (at each scale), gives the cost per tonne of CO 2.
Capacity
(kt-CO2/year)
Total Cost
($A millions)
$/t-CO2
0.365
3.650
18.25
1000
5000
2.31
10.6
31.7
545
1670
6339
2896
1736
545
334.4
Yes
No
No
Yes
Yes
No
No
No
No
No
Reference
System
Available
Feasible
Table 25 - Capture Cost Results ($/t-CO2) at Varying Scales
The trend becomes immediately obvious, with the cost of capture decreasing markedly as the
process is scaled. Capture capacities of both 1Mt-CO2/year and 5Mt-CO2/year are highlighted
in red because they lie below a prominent estimate by APS; the value of $600/t-CO2
generated in their report instigated further research and development into DAC, as the cost
was low enough to warrant interest [1].
The significance of these results is the break-even price for a DAC project; that is, the point
where total cost and total revenue are equal. The cost model devised in this paper, assumed
that CO2 was being sold as carbon credits or to an oil and gas company for EOR. For the pilot
scale plant – 1t-CO2/day – which must be stress tested and optimised, an acceptable price of
CO2 is exactly $6339; no profit would be made, but the environmental benefits. Naturally, at
this level, the benefits are practically negligible – local changes in air quality may be noticed
and recorded. However, the purpose of a pilot scale plant is to demonstrate the applicability
of the process itself, and determine whether the technology can practicably be scaled.
84 | P a g e
To this end, testing a pilot plant for this process is undeniably worthwhile, particularly given
the scaling estimates. Increasing the capture capacity by a factor of 10 results in a 54%
reduction in cost – a valuable change on all accounts, albeit an unfeasibly high cost.
5.4 Commercialisation – A Cash Flow Analysis
In order to place the commerciality of DAC into context, a cash flow analysis was conducted.
Despite the break-even price at each capacity being known, numerous factors can be
modified to make the project slightly more attractive for companies.
The following assumptions were made for this cash flow analysis:
Assumption
Explanation
Loan = 100% of CAPEX
As mentioned in the literature review, only two sources of
funds are venture capital (private equity) or debt, with
debt being the more likely case. Government subsidisation
is also a potential option; facilities operated by
Climeworks have received up to CHF 5 million funding
from the Swiss government, but this is not assumed.
Nominal Discount Rate = 6.57% This rate is taken from Westpac’s quoted rate on business
development loans – the value will be used to calculate the
interest repayments. However, cash flows will be
discounted based on the WACC i.e. the cost of debt,
which decreases by the tax rate.
Project Life = 25 years
Most projects involving chemical manufacturing,
separation or purification have a span of 25 years; this is
typically the useful life of the equipment. Anything
beyond this means that the project incurs replacement
costs, overcomplicating the analysis.
Tax Rate = 27.5%
The company tax rate provided by the ATO.
Depreciation Rate = 40%
Inflation Rate = 1.9%
Price of CO2 = $AUD 38.90
Straight line depreciation method.
1st Quarter 2018 provided by the RBA.
The average value was taken from ETS and Carbon Tax
prices across all listed countries from the World Bank’s
records.
Table 26 - Cash Flow Analysis Assumptions
85 | P a g e
Real Cash Flows
Years
Revenue
Capex
Working Capital
Salvage Value
Opex
NCF
$354,962.50
$0.00
-$257,905.69
$0.00
-$14,860,206.16
-$14,763,149.35
0
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
1
$14,198.50
$0.00
-$257,905.69
$0.00
-$594,408.25
-$838,115.44
2
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
3
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
4
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
5
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
6
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
7
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
8
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
9
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
10
$14,198.50
$0.00
$0.00
$0.00
-$594,408.25
-$580,209.75
$457,551.16
$0.00
-$262,805.90
$0.00
-$19,154,994.18
-$18,960,248.92
0
1.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
1
1.02
$14,468.27
$0.00
-$262,805.90
$0.00
-$605,702.00
-$854,039.63
2
1.04
$14,743.17
$0.00
$0.00
$0.00
-$617,210.34
-$602,467.17
3
1.06
$15,023.29
$0.00
$0.00
$0.00
-$628,937.34
-$613,914.05
4
1.08
$15,308.73
$0.00
$0.00
$0.00
-$640,887.15
-$625,578.42
5
1.10
$15,599.60
$0.00
$0.00
$0.00
-$653,064.00
-$637,464.41
6
1.12
$15,895.99
$0.00
$0.00
$0.00
-$665,472.22
-$649,576.23
7
1.14
$16,198.01
$0.00
$0.00
$0.00
-$678,116.19
-$661,918.18
8
1.16
$16,505.78
$0.00
$0.00
$0.00
-$691,000.40
-$674,494.62
9
1.18
$16,819.39
$0.00
$0.00
$0.00
-$704,129.41
-$687,310.02
10
1.21
$17,138.95
$0.00
$0.00
$0.00
-$717,507.86
-$700,368.91
$1,719,371.26
$31,361,031.29
$2,060,419.76
$3,779,791.02
$1,832,333.96
$29,641,660.02
0
$1,719,371.26
$1,719,371.26
$112,962.69
$0.00
$0.00
$1,832,333.96
1
$0.00
$1,832,333.96
$120,384.34
$151,191.64
$30,807.30
$1,801,526.66
2
$0.00
$1,801,526.66
$118,360.30
$151,191.64
$32,831.34
$1,768,695.32
3
$0.00
$1,768,695.32
$116,203.28
$151,191.64
$34,988.36
$1,733,706.96
4
$0.00
$1,733,706.96
$113,904.55
$151,191.64
$37,287.09
$1,696,419.86
5
$0.00
$1,696,419.86
$111,454.79
$151,191.64
$39,736.86
$1,656,683.01
6
$0.00
$1,656,683.01
$108,844.07
$151,191.64
$42,347.57
$1,614,335.44
7
$0.00
$1,614,335.44
$106,061.84
$151,191.64
$45,129.80
$1,569,205.64
8
$0.00
$1,569,205.64
$103,096.81
$151,191.64
$48,094.83
$1,521,110.81
9
$0.00
$1,521,110.81
$99,936.98
$151,191.64
$51,254.66
$1,469,856.15
10
$0.00
$1,469,856.15
$96,569.55
$151,191.64
$54,622.09
$1,415,234.06
Depreciation
Years
Total
Book Value Start of Year
$1,461,465.57
Depreciation
-$1,461,465.57
Book Value End of Year
$0.00
0
$0.00
$0.00
$1,461,465.57
1
$1,461,465.57
-$584,586.23
$876,879.34
2
$876,879.34
-$350,751.74
$526,127.61
3
$526,127.61
-$210,451.04
$315,676.56
4
$315,676.56
-$126,270.63
$189,405.94
5
$189,405.94
-$75,762.38
$113,643.56
6
$113,643.56
-$45,457.43
$68,186.14
7
$68,186.14
-$27,274.46
$40,911.68
8
$40,911.68
-$16,364.67
$24,547.01
9
$24,547.01
-$9,818.80
$14,728.21
10
$14,728.21
-$5,891.28
$8,836.92
0
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
-$112,962.69
-$112,962.69
-$112,962.69
$0.00
$0.00
-$112,962.69
1
$14,468.27
$0.00
-$262,805.90
$0.00
-$584,586.23
-$605,702.00
-$120,384.34
-$1,559,010.20
-$1,671,972.89
$0.00
$0.00
-$1,559,010.20
2
$14,743.17
$0.00
$0.00
$0.00
-$350,751.74
-$617,210.34
-$118,360.30
-$1,071,579.21
-$2,743,552.10
$0.00
$0.00
-$1,071,579.21
3
$15,023.29
$0.00
$0.00
$0.00
-$210,451.04
-$628,937.34
-$116,203.28
-$940,568.37
-$3,684,120.48
$0.00
$0.00
-$940,568.37
4
$15,308.73
$0.00
$0.00
$0.00
-$126,270.63
-$640,887.15
-$113,904.55
-$865,753.59
-$4,549,874.07
$0.00
$0.00
-$865,753.59
5
$15,599.60
$0.00
$0.00
$0.00
-$75,762.38
-$653,064.00
-$111,454.79
-$824,681.57
-$5,374,555.63
$0.00
$0.00
-$824,681.57
6
$15,895.99
$0.00
$0.00
$0.00
-$45,457.43
-$665,472.22
-$108,844.07
-$803,877.73
-$6,178,433.36
$0.00
$0.00
-$803,877.73
7
$16,198.01
$0.00
$0.00
$0.00
-$27,274.46
-$678,116.19
-$106,061.84
-$795,254.47
-$6,973,687.83
$0.00
$0.00
-$795,254.47
8
$16,505.78
$0.00
$0.00
$0.00
-$16,364.67
-$691,000.40
-$103,096.81
-$793,956.11
-$7,767,643.94
$0.00
$0.00
-$793,956.11
9
$16,819.39
$0.00
$0.00
$0.00
-$9,818.80
-$704,129.41
-$99,936.98
-$797,065.80
-$8,564,709.74
$0.00
$0.00
-$797,065.80
10
$17,138.95
$0.00
$0.00
$0.00
-$5,891.28
-$717,507.86
-$96,569.55
-$802,829.74
-$9,367,539.48
$0.00
$0.00
-$802,829.74
0
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
$0.00
1.00
$0.00
$0.00
1
$14,468.27
$0.00
$0.00
-$605,702.00
-$151,191.64
$0.00
-$742,425.37
-$742,425.37
0.95
-$707,061.80
-$707,061.80
2
$14,743.17
$0.00
$0.00
-$617,210.34
-$151,191.64
$0.00
-$753,658.81
-$1,496,084.19
0.91
-$683,571.45
-$1,390,633.24
3
$15,023.29
$0.00
$0.00
-$628,937.34
-$151,191.64
$0.00
-$765,105.69
-$2,261,189.87
0.86
-$660,899.05
-$2,051,532.30
4
$15,308.73
$0.00
$0.00
-$640,887.15
-$151,191.64
$0.00
-$776,770.06
-$3,037,959.93
0.82
-$639,014.54
-$2,690,546.84
5
$15,599.60
$0.00
$0.00
-$653,064.00
-$151,191.64
$0.00
-$788,656.05
-$3,826,615.98
0.78
-$617,889.01
-$3,308,435.85
6
$15,895.99
$0.00
$0.00
-$665,472.22
-$151,191.64
$0.00
-$800,767.87
-$4,627,383.85
0.75
-$597,494.67
-$3,905,930.52
7
$16,198.01
$0.00
$0.00
-$678,116.19
-$151,191.64
$0.00
-$813,109.82
-$5,440,493.67
0.71
-$577,804.83
-$4,483,735.36
8
$16,505.78
$0.00
$0.00
-$691,000.40
-$151,191.64
$0.00
-$825,686.26
-$6,266,179.93
0.68
-$558,793.82
-$5,042,529.17
9
$16,819.39
$0.00
$0.00
-$704,129.41
-$151,191.64
$0.00
-$838,501.66
-$7,104,681.59
0.64
-$540,436.94
-$5,582,966.11
10
$17,138.95
$0.00
$0.00
-$717,507.86
-$151,191.64
$0.00
-$851,560.55
-$7,956,242.14
0.61
-$522,710.47
-$6,105,676.58
Nominal Cash Flows
Years
Escalation Factor
Revenue
Capex
Working Capital
Salvage Value
Opex
NCF
Financial Calculations
Years
Loan
Balance at Start
Interest during Year
Repayment
Principal Paid
Balance at End
Income Tax
Years
Revenue
Capex
Working Capital
Salvage
Depreciation
Opex
Interest Paid
Net Revenue
Loss Carry Forward
Taxable Income
Tax Payable
Profit
After Tax Net Cash Flow
Years
Revenue
Capex
Salvage Value
Opex
Loan Repayment
Tax
ATNCF
Cumulative NCF
Discount Factor
Discounted Cash Flow
Cumulative DCF
Total
Total
Total
Total
$457,551.16
$0.00
-$262,805.90
$0.00
-$1,461,465.57
-$19,154,994.18
-$2,060,419.76
-$22,482,134.24
-$299,824,160.39
$0.00
$0.00
-$22,482,134.24
Total
$457,551.16
$0.00
$0.00
-$19,154,994.18
-$3,779,791.02
$0.00
-$22,477,234.04
-$273,971,554.41
-$12,184,879.73
-$179,211,178.74
Figure 14 - Sample of Cash Flow Analysis – 1t-CO2/day
86 | P a g e
Figure 14 highlights the first 10 years of cash flows, incorporating the assumptions listed
above. However, the totals shown in the left column represent the entirety of project life; that
is, the full 25 years. The highlighted cell shows a $0.00 input for CAPEX since the capital
investment is funded solely by a business loan. An ‘IF’ statement exists in this cell, which
changes the value of the cell to the CAPEX – conditional on the input for the loan: if the loan
is 0, then CAPEX is equal to its original value.
Nonetheless, the cash flow analysis shows that the real cash flows (and therefore nominal)
are negative in each year. This is because the price of CO2 is an order of magnitude too low –
the revenue is 2.5% of the value of OPEX. With the introduction of the loan, a new breakeven price – deviating from the capture cost – must be calculated. A simple run of Solver on
excel revealed that $1629/t-CO2 is the new break-even price for a 1t-CO2/day plant. A
summary of the results for each capacity is shown in the table below.
Capacity (kt-CO2/year)
Break-even Price ($/t-CO2)
Percentage Change (%)
0.365
1629
74.3
3.650
683
76.4
18.25
396
77.2
1000
111
79.6
Table 27 - Loan Case – Adjusted Break-even Prices
There exists a substantial discrepancy between the two sets of break-even prices, as one
would expect. It is implausible to assume that a loan financing 100% capital would be
provided at scales any higher than the pilot. A more likely scenario would follow the funding
scheme of Climeworks – a 25% CAPEX loan and 75% private equity funding. The
technology must be proven under a variety of conditions before achieving the backing of debt
financers or private equity. Financers expect positive cash flows to achieve a return on their
investment. The cash flow analysis returns extremely negative NPVs at each scale, given the
fact that the price of CO2 is underwhelmingly low; this can be seen in Table 27.
Here, revenue increases linearly with the capture capacity of the plant, whilst each
component of operating cost increases by quantity defined by the power factor. The result?
An exponential decrease in the attractiveness of the project from the perspective of investors.
Consequently, the only purpose the loan serves is to increase in the NPV, which signals to
investors that the project is slightly more viable. The tax shield effect of the loan is entirely
negligible unless the price of CO2 increases to a point where positive cash flows exist.
87 | P a g e
Capture Capacity (kt-CO2/day)
Parameter
NPV – Loan
($AUD million)
NPV – No Loan
($AUD million)
$/t-CO2 for NPV = 0
($AUD) w/loan
Payback Period
(years)
0.365
3.650
18.25
1000
-8.60
-35.1
-97.6
-1110
-10.1
-41.9
-118
-1480
1675
705
409
116
> 25
> 25
> 25
> 25
Table 28 - Comparison of Financial Metrics at Varying Scales
Investors also look for:
•
Positive cash flows from pre-existing plants, or a similar plant whilst proving
scalability – this can be done by retrofitting;
•
Reasonably low payback periods – typically less than 5 years (maximum) [74];
•
A market for the product – the most viable options are EOR or selling CO2 for carbon
credits, though it is not limited to this;
•
Future growth prospects – that is, the likelihood that demand for CO2 will increase
and that prices will rise to a financially viable level; and
•
Improvements in technology – how much research and development is being
undertaken to increase the efficiency of similar processes.
The causticisation process for DAC purposes has only recently been tested by CE. The pilot
plant achieved a reportedly low cost, with scaling calculations as well as local
manufacturer/vendor quotes deriving a value of $USD 94-232 [51], which is significantly
lower than this paper. For this reason, CE was able to raise a sizeable funding round – CAD
$11 million. Such a level of private equity would be enough to cover approximately 50% of
the CAPEX for the 50t-CO2/day case, established in this paper.
By setting NPV to 0, the project has going concern – holding all else constant, the operations
can continue until the end of the project life. With the inclusion of interest repayments, tax
and depreciation, the break-even price is marginally greater than that established in Table 27.
Should efficiencies in this operation increase, NPV will turn positive, thereby warranting
more support and investment.
88 | P a g e
However, a zero NPV has implications for the payback period (PP). PP does not take into
account the time value of money, rather, has foundations in the cumulative cash flows; the
year in which cumulative NCF reaches 0 signifies the PP. Setting NPV = 0 suggests that the
money invested will not be returned within the lifetime of the project; each plant capacity has
a payback period of over 25 years - investors will never realise their returns. Thus, the price
of CO2 must increase further to bring the payback period down to a reasonable span of time.
5 years is a generous PP, giving a project with a large initial capital investment (and therefore
working capital) plenty of time to recoup the negative cash flows. A PP any longer may
concern debtors and creditors regarding the likelihood of future positive returns. The time
value of money plays a part in this sense, as a dollar today is worth more than a dollar in the
future for the investors. The required $/t-CO2 to achieve a payback period < 5 years at each
capacity is highlighted in the table below. This value (as well as the NPV = 0 case) was
calculated using the Solver tool in Excel: selecting Year 5 of cumulative NCFs as the target
cell, desiring a value of $0, by changing the cell containing CO2 price.
Capacity (kt-CO2/year)
Required Price of CO2 ($/t-CO2)
0.365
2020
3.650
867
18.25
507
1000
147
Table 29 - Break-even Price of CO2 with a 5-year Payback Period
Despite the prices being notably higher – approximately 25% - it becomes apparent that NPV
is considerably higher with this PP. Accordingly, a low PP should be prioritised when
optimising the cost model, as this concomitantly results in a high NPV. Suggestions to
achieve a lower intrinsic PP include, but are not limited to:
•
Obtaining a competitive interest rate – selecting the most flexible retail bank for this
purpose may result in significant savings;
•
Utilising efficient equipment with a salvage value – in this sense, both the sunk cost
from PCE and depreciation expense can be reduced. In a scenario with positive NPV,
this would however, reduce the tax shield (a benefit); and
•
Creating a highly usable product for end-users – ensuring the purity of CO2 generated
in this process holds a comparative advantage over others, thereby commanding a
higher price.
89 | P a g e
5.5 Sensitivity Analysis
Following on from the aforementioned investor preferences, it should be noted that a certain
degree of uncertainty clouds ‘future growth prospects’ and ‘a market for the product’. Whilst
these play a major role in determining the overall feasibility of the process, the trajectory can
only be speculated upon. As such, the sensitivity analysis will focus on improvements in
technology, specifically at the pilot scale – these must demonstrate realisable gains. The
examination of CAPEX and OPEX in conjunction with the break-even price analysis, has
highlighted several parameters that may be adjusted to increase the efficiency of this process
(as mentioned in Section 5.2 and 5.3).
5.5.1 Compressor Price
In this current model, the compressor constitutes 30% of PCE. This value was obtained from
the constants provided by Coulson and Richardson for a centrifugal compressor, consuming
between 20-500 kWh. However, for a system capturing 1t-CO2/day, this cost is undoubtedly
inflated and requires substitution. The only rationale for such a high cost comes from the
pressure requirement – compressing CO2 to 100 bar from atmospheric conditions, reading it
for storage or transport. Whilst this primarily changes the energy consumption, the cost must
reflect the mechanical capability of the unit. Nonetheless, a reduction in the equipment cost is
warranted, and based on an adjusted value of CE’s total compression cost - $USD 31 million.
By dividing this value by 2740, the realised compressor cost is $17,000.
Reducing Compressor Cost
25
Cost ($AUD millions)
20
15
10
5
0
Original
Reduced
1 t-CO2/day
Original
Reduced
10 t-CO2/day
CAPEX
Original
50 t-CO2/day
OPEX
Figure 15 - Equipment Cost Sensitivity – Adjusting the Compressor
90 | P a g e
Reduced
The change is immediately noticeable, now contributing a mere 5% to total PCE. This
reduction has further implications for total OPEX when considering the relationship between
fixed operating costs and FCI, of which PCE is a remarkable component. With both CAPEX
and OPEX decreasing, the new cost of capture costs for the system are:
Capacity (t-CO2/day)
Capture Cost ($/t-CO2)
Percent Change (%)
1
4758
-24.94
10
2158
-25.56
50
1290
-25.73
Table 30 - Results of System Remodelling - Compressor
Whilst the percent changes between the investigated scales are relatively similar (as a result
of the order of magnitude), it stands to reason that the cost trajectory follows the base case.
At 1Mt-CO2/year, the percentage change in CAPEX will be rather substantial and given the
more pronounced weighting of CAPEX in the total cost (see Figure 13), results will show that
the system configuration is highly sensitive to compressor costing.
5.5.2 Sorbent Selection
The next change examined is the variation of capture sorbents from NaOH to KOH. In
Section 4.2, NaOH was chosen as a result of its relative price and level of testing in similar
processes. However, the KOH has been proven to capture 27% more CO2 and consumes 30%
less energy, but is comparatively 1.5x more expensive on the market [53].
Substituting KOH into the chemical equations and determining the quantity of KOH required
per tonne of CO2 captured yielded a value of 3.97 tonnes; a value greater than that of NaOH
(3.7 tonnes). This is a direct result of the considerably higher molar mass of KOH, resulting
in a greater concentration in solution. Combining this with the market price of KOH resulted
in a consumables contribution of $AUD 3600/day in contrast to $3400/day. The nature of the
process dictates that the sorbents can mostly be regenerated, and thus become yearly costs.
Capacity (t-CO2/day)
Capture Cost ($/t-CO2)
Percent Change (%)
1
6340
-0.011
10
2899
-0.012
50
1738
-0.012
Table 31 - Results of System Remodelling – Sorbent
In relation to the remaining variable costs and fixed costs, the sensitivity of the process to a
change in sorbent is underwhelming. Furthermore, economies of scale exist in consumables,
91 | P a g e
as they can be purchased in bulk from a single supplier. The scope for reducing costs in
consumables is relatively low, and is subject to the market forces of supply and demand.
This result is supported by APS’ article, suggested that consumables have a cost of
approximately $0.90 per tonne captured [1] , which takes potential chemical losses into
account. Despite this value being several orders of magnitude smaller than this investigation,
the result is the same – consumables are practically inconsequential, and time should be
devoted to more prevalent costs.
Altering the Sorbent - NaOH to KOH
25
Cost ($AUD millions)
20
15
10
5
0
NaOH
KOH
1 t-CO2/day
NaOH
KOH
10 t-CO2/day
CAPEX
NaOH
KOH
50 t-CO2/day
OPEX
Figure 16 - Sorbent Sensitivity
From an engineering design perspective, in light of Figure 16 the costs of NaOH and KOH
are the same. However, the most important consequence of sorbent choice its impact on the
surrounding environment. With both sorbents being hydroxides, any concentration of solution
released without treatment will result in higher levels of toxicity for aquatic environments.
Substituting the solvent entirely is the only potential mitigation for this; however, the entire
process would need to change around it – the regeneration of the solvents works specifically
because they are hydroxides.
Nonetheless, should uptake rates need to increase as the process is scaled, higher
concentrations of hydroxides will be required. These higher concentrations command greater
purchase prices, and thus, sorbents may contribute more significantly to consumable costs.
92 | P a g e
5.5.3 Combustion Preference
In section 4.9, the advantages and disadvantages of oxyfuel combustion and air-firing were
detailed, arriving at the conclusion that oxyfuel combustion is more efficient. Given the lower
technology readiness level of this technique and the need for an offsite power generation and
separation plant, air-firing may prove to be more beneficial strategy, at least in the short-term.
As such, the air-firing has been substituted into this configuration to determine the impact on
costing and energy consumption.
The capital cost of the associated post-combustion capture plant in the air-firing scenario
adds approximately 5.3%, whilst the fuel consumption increases by 20%. As a result, the
capture cost has increased at all scales, albeit negligibly.
Capacity (t-CO2/day)
Capture Cost ($/t-CO2)
Percent Change (%)
1
6360
-0.32
10
2907
-0.31
50
1742
-0.30
Table 32 - Results of System Remodelling – Combustion Method
Even at a 1Mt-CO2/year scale, the change in capture cost is incremental as PCE reduces by a
factor of 0.7; however, in absolute terms this value is non-negligible, constituting $AUD 1.5
million in expenditure.
Given the result, a swap to air-firing may indeed prove to be worthwhile from an investor
perspective. With a more mature technology – despite cryogenic air-separation having been
conducted for several years – comes greater investor confidence. Air-firing in power
generation plants has been the most common combustion method, and its inclusion may
therefore increase the funding received allowing for greater testing.
Nonetheless, oxyfuel combustion does indeed maintain both physical and chemical
advantages over air-firing. Given time, it will prove to be a considerably more efficient
process through further reductions in capital cost and fuel consumption. Moreover, the
resulting lower emissions will undoubtedly become an essential capability as the uptake on
mitigation techniques increases. This ensures that the offsite plant itself is not contributing to
the production of CO2.
The table on the following page highlights the miniscule discrepancy between the two
combustion preferences at the scales investigated.
93 | P a g e
Oxy-fuel Combustion vs. Air Firing
25
Cost ($AUD millions)
20
15
10
5
0
ASU
Air
1 t-CO2/day
ASU
Air
10 t-CO2/day
CAPEX
ASU
Air
50 t-CO2/day
OPEX
Figure 17 - Combustion Preference Sensitivity
5.5.4 Sources of Power
Arguably the most interesting and important change to the system configuration is the source
of power. As a consequence of progressively more rigorous regulation, the willingness of
companies to incorporate environmentally friendly practices into their operations is
increasing. The most potent method is to incorporate renewables where possible; that is,
solar, wind and hydroelectricity. With noticeable changes in the supply and demand forces in
the electricity sector, advances in technology and research and development into these
renewables will result in remarkable improvements to efficiency.
In considering the list of renewable technologies, only two currently maintain a technology
readiness level worthwhile mentioning – solar PV and wind. Both technologies are
undergoing cost and performance testing; wind has the lower levelized cost of electricity
(LCOE) at a value of approximately $AUD 70-120/MWh [75]. This is NPV of the unit-cost
of electricity over the entire project life – in this case, the external wind farm (onshore). It
therefore allows a comparison of technologies with vastly divergent CAPEX and OPEX
profiles; much like the cash flow analysis, cost of equity and debt, inflation, tax rates, project
life etc. must be input into the model. As such, wind power is the only renewable technology
considered in this investigation, as it has the greatest chance of being implemented,
particularly in a DAC context.
94 | P a g e
The following table presents the benefits of wind energy in comparison to natural gas
combustion (the base case), highlighting its applicability as a potential substitute in DAC.
Solar PV is also included for reference, and data has been taken from the Australian Power
Generation Technology Report (2015).
Parameter
Natural Gas (base case)
Wind
Solar PV
Capital
The process is well-known
Wind farms are
Solar farms are also
Cost
and thus considerable
commonly utilised,
commonly utilised,
improvements have been
having a marginally
having a marginally
made in reducing PCE
greater capital cost
greater capital cost
Cost of
Natural gas combined
As previously mentioned,
At a commercial
Electricity
cycle has the lowest LCOE
this has the lowest LCOE
scale, the lowest
of all current technologies
of the renewables.
LCOE is $120/MWh
As a standalone plant, the
Zero CO2 emissions
Zero CO2 emissions
Emissions
level of emissions are
undoubtedly an issue
Availability
Readily available
Difficult to procure
Difficult to procure
Flexibility
Very flexible – this plant
Not flexible – wind farms
Not flexible –
can be constructed in any
must be located in zones
daylight hours and
location and have a
with high wind velocities
intensity of sunlight
consistent performance
and consistent winds
vary drastically
Table 33 - Assessment of Feasibility of Power Generation Techniques [75]
Table 33 clarifies the most important facet of renewable technologies – zero carbon
emissions. In stark contrast to natural gas plants, which hold advantages in practically every
area (some larger than others), both wind and solar plants ensure DAC remains a ‘negative
emissions technology’; the external plant emissions do not compromise the captured quantity
at the existing facility.
Another option that results in zero carbon emissions is nuclear power. Despite the fact that
the ‘Environment Protection and Biodiversity Conservation Act’ explicitly forbids the
construction and operation of nuclear technologies in Australia, this may be subject to change
in the future given the necessity for climate change reversal strategies. Other notable
countries are not placed under the same restrictions, and knowing that DAC can be located in
any region, strengthens the argument for nuclear power.
95 | P a g e
Assessing the same parameters in Table 33, reveals that nuclear power competes with natural
gas on the grounds of availability, and is markedly more flexible than both wind power and
solar PV. However, the capital cost is prohibitively high at this current point in time. In light
of the composition of total cost particularly at commercial scales (see Section 5.3), the
application of nuclear power is unrealistic unless substantial efficiencies are achieved and the
regulatory environment changes.
The graph below shows how both wind and nuclear power compare against the base case
design modelled in this paper.
Comparing the Sources of Power
35
Cost ($AUD millions)
30
25
20
15
10
5
0
CAPEX
OPEX
CAPEX
1t-CO2/day
OPEX
10t-CO2/day
Natural Gas
Wind
CAPEX
OPEX
50t-CO2/day
Nuclear
Figure 18 - Total Cost of Power Generation at Varying Scales
Two specific trends are highlighted in this sensitivity analysis:
•
CAPEX – both power generation via wind and nuclear power have a higher capital
cost than natural gas, with nuclear power being the most expensive - as expected from
the assessment in Table 33.
o The average purchased equipment cost for wind and nuclear power were taken
from a number of sources [75, 76] – these values were $AUD 43,000 and
$AUD 64,000 respectively. Calculations involved determining the kW utilised
each day and multiplying this by the installed cost per kW, which the sources
provided.
96 | P a g e
•
OPEX – wind power actually has the lowest OPEX of all three alternatives. This can
be attributed to the fact that the natural gas term component of utilities is set to zero
(though also implemented for nuclear power).
o The reason nuclear power has a higher OPEX than wind and natural gas can
be explained by weighting of fixed operating costs.
In similar vein to the previous component changes, the trends can be summarised by the
change in total capture cost.
Capacity (t-CO2/day)
1
10
50
Source of Power
Capture Cost ($/t-CO2)
Percent Change (%)
Wind
6497
-2.49
Nuclear
6735
-6.24
Wind
2992
-2.65
Nuclear
3103
-6.50
Wind
1794
-2.74
Nuclear
1861
-6.61
Table 34 - Results of System Remodelling – Source of Power
The percent change as the process is scaled increases, culminating in an increase of 3.02%
and 6.91% for wind and nuclear power respectively, at 1Mt-CO2/year. This is again
attributable to higher capital cost weightings. Contrasting to the previous cases (barring
compression costs), the changes to total capture cost are not insignificant, especially in the
case of nuclear power – demanding in excess of $AUD 30 million for the initial capital
investment at a commercial scale. Prior to implementing a new renewable energy facility or
nuclear power system (including co-generation options), a cost-benefit analysis must be
conducted.
The most important facet of this cost-benefit analysis is the trajectory for the technology, and
the short-term or long-term trade-off that must be made to ensure this project is both
commercially feasible and environmentally beneficial. By 2030:
•
Wind – development is being focussed on increasing the power generation per turbine
at a level greater than the associated increase in costing, improving the operating life
of wind farm projects thereby reducing life-extension or replacement costs, and
increasing the size and therefore capacity for generation, taking full advantage of
economies of scale [75]; and
97 | P a g e
•
Nuclear power – development is focused on reducing the overall CAPEX by at least
15% and in particular, the financing risks that such high initial capital investment
engenders [76], technological advancement to reduce the quantity of nuclear waste,
and reducing the volume of water required for cooling.
Considering the short-term objectives of development in these power generation
technologies, it is unlikely that they will be implemented for DAC. Optimising DAC requires
first and foremost a reduction in capital cost, of which neither provide. Moreover, the
technology readiness level of DAC itself is rather low; to add sources of generation that are
little incorporated in CCS, intensifies the degree of uncertainty.
Renewables
Nuclear
The legal and regulatory environment that
The financial barriers to implementation in
dictates the inclusion of renewable energy in
conjunction with the contestability of nuclear
commercial operations, is contingent on the
power (in reference to policy and public
ability of technological advancement to
acceptance), delay the progression of
command lower PCEs. Current cost estimates development [10].
are still uncertain despite being promising
sources of power in the future. The relatively
large error margins cause difficulties in
decision-making [29].
To recuperate the initial capital investment,
the DAC facility must operate at maximum
capacity and have as much plant up-time as
possible, thereby reducing the $/t-CO2
captured.
With intermittent sources of power, such as
wind and solar PV, this cannot be achieved
unless power storage systems were available
– only driving up capital costs and footprint.
Lackner et al. suggested that co-generation
may be feasible for the air contactor if the
system switched on only when the wind
velocity reached a certain value. [10]
Table 35 - Notable Issues with Proposed Sources of Power
98 | P a g e
5.5.5 Cost of Electricity and Operating Labour
This paper reveals that the path to implementation for DAC rests primarily on the ability to
reduce CAPEX. However, there are still noticeable gains to be made in optimising major
components in OPEX – electricity and operating labour.
The grid price of electricity is subject to change drastically as a result of its foundations in the
wholesale market. Environmental conditions such as heatwaves can cause large spikes in
volatility, however energy regulations set maximum and minimum spot prices to limit this.
Countries currently operating pilot and commercial DAC facilities similarly source electricity
from the grid, however prices are considerably lower [77]. Taking Carbon Engineering’s
location – Squamish, Canada – the price charged for energy consumption is $CAD
0.0567c/kWh. As such, the sensitivity of this process to changes in the grid price of
electricity is warranted.
Operating labour is another component subject to fluctuations, both from an economic
perspective and an efficiency perspective.
•
Economic – wages are heavily dependent on global economic conditions, the
domestic rate of inflation, existence of pension schemes and trade unions.
•
Efficiency – the company must decide how many engineers, shift supervisors and
operators are required per section of the facility on a case by case basis. Additionally,
a variety of unit operations may be capable of automation, further reducing costs.
Rather than assuming operating labour as a fixed percentage of FCI, or as this paper does,
establishing a power factor based on value proximity to literature, the sensitivity to the
aforementioned conditions should be examined in more detail. Accordingly, changes in the
cost operating labour are a very real possibility, and have a clear impact on the total capture
cost.
5.5.6 The Parameters in Relation to Capture Cost
To summarise and highlight the direct effects of each component assessed in this sensitivity
analysis, a spider plot has been constructed. However, only the results at a pilot scale have
been presented – as seen in the ‘remodelling’ tables, the percentage changes are relatively
similar despite the increase in capacity. This plot is shown on the following page.
99 | P a g e
Cost Sensitivity
6.000%
4.000%
% Change in $/t-CO2
2.000%
-25%
0.000%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
-2.000%
-4.000%
-6.000%
% Change in Parameter
Compression
NaOH
ASU
Wind
Nuclear
Electricity Price
Labour Cost
Linear (Compression)
Linear (ASU)
Linear (Wind)
Linear (Nuclear)
Linear (Electricity Price)
Linear (Electricity Price)
Linear (Labour Cost)
Figure 19 - Spider Plot – Sensitivity of Significant Costs
100 | P a g e
25%
The spider plot evidences the necessity of including operating labour in this economic
analysis. Excluding the overwhelming large sensitivity of the system to changes in
compressor cost – arguably, a result of inaccurate estimation formulae – the operating labour
cost can result in significant changes to total capture cost, particularly as the process is
scaled. Other sensitivities are as expected; components with large capital costs will naturally
cause greater change in the $/t-CO2 captured even at 1t-CO2/day.
5.6 A Comparison of Capture Cost Estimates and Optimisation
The following section draws a number of conclusions from a comparison of this process with
both commercial facilities and existing literature, identifies and briefly describes the
trajectory of DAC technologies.
5.6.1 The Market Price of CO2
At this point in time, only one company operates at the assessed scale commercially –
Climeworks. The plant currently captures 900t-CO2/year, selling the CO2 for agricultural use
in greenhouses. This operation in Switzerland commands a carbon price of CHF 100-250/tCO2 (Swiss Francs), approximately equalling $AUD 150-350, and demands CHF 600/t-CO2.
The reason the carbon price is considerably higher than assumed cost per tonne, is a result of
regulation and location. In Switzerland, the Carbon Tax on production costs industry a
substantial $USD 100.90/t-CO2, whilst the Emissions Trading Scheme (ETS) holds a price of
$USD 7.88/t-CO2. This indicates that the Swiss Government is expecting a specific result;
that is, to limit the production of CO2. Subsequently, companies are faced with an
unfavourable choice: produce 1 tonne of carbon and be taxed heavily as a consequence, or
receive a miniscule price for trading the credit to another company.
For Climeworks to continue operations, it must have a financial incentive – this comes in the
form of higher prices. Rather than sell carbon credits to companies looking to manage their
own emissions for needs that are typically irrelevant to climate change mitigation,
Climeworks has managed to both secure a customer for the small amounts of CO2 captured at
a reasonable price, and avoid CO2 emissions at the facility itself.
The implication of this is that DAC is feasible if and only if the market price of CO2 is high
enough to warrant its application; this is in-turn dependent on the geographical location. For
the purposes of this investigation, the average price of Carbon Taxes and ETS was assumed,
resulting in $38.90, which pales in comparison to Climeworks. As such, it can be concluded
101 | P a g e
that facility designed in this paper, if operated commercially, would have no financial
incentive to continue – rather, an environmental incentive only.
Nonetheless, the spot prices of CO2 in similar geographical regions can be disparate
depending on the conditions. For example, a company selling their CO2 for EOR purposes in
a location close to the refinery and depleted oil field cannot pass on the same proportion of
storage and transportation costs as a project located further away. Lackner et al. (2010) has
suggested that the price of truck-delivered CO2 can exceed that commanded by Climeworks,
reaching a value of up to $USD 300/t-CO2 – though this is an extreme case. Prices for EOR
are considerably lower than the estimate taken in this paper, averaging approximately $30/tCO2. These could be driven further down by policies limiting CO2 emissions, reducing the
price of CO2 delivered to a fraction of the cost – enough to cover compression and
transportation only [Global CCS Institute]. Nonetheless, the availability of CO2 at these
locations is severely limited. This means that the assumption of selling CO2 for EOR
purposes – as suggested by this paper – for the stated price, is entirely valid; the EOR market
is large enough to have a noticeable impact on climate change.
5.6.2 Design Optimisation and Costing Model Discrepancies
Moving on from an assessment of macroeconomic conditions, design choices vary
significantly between outstanding projects and literature, and therefore have a profound
influence on the ability to reduce capture costs.
The table on the following pages highlight the discrepancies in both assumptions and unit
operations between this design, APS’s and CE’s. Despite employing a relatively similar
process – utilising hydroxides are the sorbent – the results of this paper returned capture cost
values that proved entirely infeasible at small scales, but tended toward the estimates
provided by these designs. The following components will be assessed:
•
Contactor design – this is compared in terms of the configuration, materials of
construction and packing choice;
•
The calcination step – the type of unit operation used has implications for the capital
cost and the energy consumption; and
•
Costing model assumptions – this primarily involves the fixed percentages in both
capital and operating costs; their variance can cause significant changes to the overall
capture cost.
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Model Area
Comparison
Contactor
The contactor utilised in the APS system is a counter-current scrubbing
Configuration
column with NaOH as the sorbent. However, the contactor alone had an
[1, 10, 29, 51]
estimated cost of approximately $USD 290 million (including packing); at
1Mt-CO2/year, this price is substantially higher than both Carbon
Engineering’s estimate of $USD 132 million and this investigation - $AUD
127 million. Their system involves 330 absorbers; without optimal
configuration, the stripped air feed into a subsequent unit reduces the
energy efficiency of the process. Indeed, the capital cost of 330 smaller
units is also detrimental to economies of scale [1]. In this sense, Carbon
Engineering’s singular contactor, in rectangular shape, helps mitigate this
impact. The same benefits are attained by our design; a horizontal packed
column (which is cheaper than customising an untested rectangular
configuration) modelled off cooling existing cooling towers at this scale
can achieve economies of scale. Furthermore, the is a possibility for the
material of the column itself to be constructed from concrete instead of
stainless steel, as APS, CE and this design all assume. This must first be
tested for corrosive resistance.
A closed system is not preferred for this application; open systems on the
other hand are heavily utilised in cooling tower technology, which both CE
and our design have foundations in – it is suitable for ingesting high
volumes of ambient air. Furthermore, assuming a cross-current system
instead of counter-current brings with it a host of benefits, despite the
decreased wettability – necessitating cycling (Section 4.4.4). These are:
•
Reduces the total liquid flow for continuous operation;
•
Allows more optimal packing to be chosen – a higher specific
surface area results in lower CO2 concentrations through the
contactor i.e. a greater uptake (however, higher pressure drop);
•
Performing twice as effectively as counter-current systems; and
•
Minimisation of drift – the droplet production is a particular
concern in contacting systems, as mentioned in Section 4.4.2 – the
addition of demisters alleviates this, and droplet concentration can
be controlled to the specified OHS level.
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Packing
The selection of appropriate packing has proven decidedly important. In the
Choice and
APS article, packing costs constituted 33% of total PCE, compared to
Materials
approximately 8% in our design. It is difficult to estimate the packing cost
[51, 57]
of CEs design, as their quoted price for the contactor incorporated the
packing cost. However, it can be approximated: multiply the volume of
packing – 8.6m x 200m x 20m – by $USD 250/m3 = $USD 8.6 million.
The APS article selected stainless steel packing, which does indeed perform
better. Nonetheless, relative to a 600% greater cost, the associated increase
in sorbent distribution and therefore uptake of CO2 is negligible.
If the APS design swapped to CEs chosen packing, $USD 136 million
would be cut in costs, resulting in a $100/t-CO2 decrease in overall capture
cost. However, the price for this quoted plastic is remarkably low. Typical
thermoplastics, including the packing utilised in our design – PVCC – are
approximately 20% cheaper [58]. These are typically supplied by specialist
cooling tower companies, including Sulzer – investigated by both APS and
CE. The specific surface areas exceed 200/m and have comparable
absorption capacities to typical scrubbing applications under the same
operating conditions. They also maintain lower pressure gradients,
increasing the efficiency of the entire contacting process through reductions
in fan energy requirements [58]. This further advocates both CEs and our
design.
Calcination
The calcination step, as previously detailed, can be conducted via rotary
Equipment
kiln – as APS does – or through the use of a CFB. The benefits culminate in
Choice [1, 51]
a substantially lower CAPEX for CEs design and this paper. Furthermore,
the efficiency of a rotary kiln is approximated at 75%; whilst it is unclear
what justifies this value, CEs estimates have suggested a 98% conversion
efficiency, another proponent for the use of a CFB.
Combustion
Oxy-firing is utilised in all three cases; however, the thermal energy
Preference [64] requirement estimated by APS is 8.1 GJ/t-CO2. This paper calculated the
thermal energy demand to be approximately 5.17 GJ/t-CO2, by determining
the enthalpy and multiplying through by the quantity, accounting for any
thermal inefficiency. Our design includes heat integration through steam
turbines and heat recovery mechanisms for inlet and outlet streams.
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Costing
Capital Charge – This is assumed to be a percentage of fixed capital
Assumptions
investment, and a comparatively less conservative estimate was taken.
[1, 51]
APS assumed a value of 12%, whilst CE chose 15% - seemingly arbitrarily.
Coulson and Richardson suggested a value of 8-12% and thus an average
value was taken for this investigation – 10%. However, it has contributed
markedly to the operating cost, constituting 33% of annual production costs
and 6.7% of total capture cost. Despite the fact that capital charges demand
high operating expenditure (as it includes depreciation costs on expensive
capital equipment and interest payments on large capital loans), it seems
almost unreasonable that the contribution be this high. Rather than
changing the fixed percentage in our estimates, capital costs must be
reduced further.
Contingency – In similar vein, both APS and CE maintain noticeably
higher contingency costs, taking a value of 25% each. Our investigation
assumes a contingency value of 10%. If the value taken in these
investigations were to be substituted, CAPEX would increase linearly i.e.
15%, meaning total capture cost will congruently rise. For early
deployment plants, particularly those with low technology readiness levels
(as this investigation is), errors in the operation of the process or
chemical/physical estimates may appear more frequently. As such, the
estimate for contingency should be revised in this paper.
Equipment Estimates – The cost of equipment vastly differs between APS,
CE and our design. Whilst this investigation partially calculates PCE
through well-known chemical engineering guides, APS strictly determine
value through these estimations. In comparison to CE, who obtained all
values from various procurement companies and vendor assessments, the
costing may deviate substantially. As such, the PCE should not be taken at
face value, rather, as a ballpark estimate.
Total Capture
APS: USD 600 - 2011
Cost
CE: USD 94-232 - 2017
($/t-CO2)
Our Investigation: AUD 545
Table 36 - Comparing Design and Model Specifications
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5.6.3 Improvements
In light of all the assessed factors in this investigation, literature and commercial plants, it is
evident that significant improvements can be made to the process. Some companies such as
Global Thermostat have stated that capture costs can feasibly be reduced to $USD 50/t-CO2
in the very near future, though provide little evidence on how to do so. Keith et al. have
suggested that co-generating power with natural gas and grid electricity can result in a
capture cost as low as $USD 94-97. Assuming this process was initiated in a location where
the carbon price was markedly higher than Australia, the facility may indeed generate a
profit, thereby providing the financial incentive needed to continue operations. It would also
prove to the public and governments that investment in negative emissions technologies such
as DAC is more than worthwhile, particularly with a long-term perspective.
An optimal case that combined all cost-reducing substitutions was examined. It is not known
whether this combination of equipment would result in the facility operating at the same
efficacy as the base case; however, it does put improvements into perspective.
•
The compressor cost was substituted to the lowered value from 5.5.1;
•
The electricity price was equated to lower global charges; and
•
Operating labour was equated to the value assumed by CE.
This resulted in a capture cost of $AUD 401/t-CO2. Given the benchmark by APS of $USD
600/t-CO2, the value falls well within the range. Whilst it is still considerably higher than
both the CE cost and the market price of CO2, this investigation has shown that
improvements are possible and undoubtedly warrants further research and development to
realise these gains.
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Conclusion
Environmental conditions are shifting globally as a result of continual greenhouse gas
emissions. A variety of options for the mitigation of this effect have been proposed. Direct air
capture has the potential to decrease the concentration of carbon dioxide in the atmosphere,
but a litany of barriers are preventing its implementation. This Thesis initially aimed to
investigate the most effective techniques for capturing carbon dioxide from ambient air, in
light of these obstacles. By contextualising negative emissions technologies through an
explanation of climate change’s impacts, tested capture methods, reutilisation options and
policy objectives, the advantages of direct air technologies could be better understood.
Methods examined were causticisation, amine sorption, solid inorganic chemisorbents,
membranes and cryogenics. Upon analysing the advantages and disadvantages of each
process, one specific technique was required to be chosen for further investigation.
The project deliverable detailed the selection process, employing AHP and VIKOR – two
multicriteria analysis techniques that are particularly useful when used in combination.
Conducting such methods facilitates the decision-making process, as the costs and benefits of
each process appear balanced at a surface level. The criteria was selected based on the
literature view, which highlighted the necessary requirements for a successful project; these
included cost, energy requirement, technology readiness level, footprint, pollution and public
acceptance. AHP consists of a linguistic approach, which does introduce some bias into the
ranking system. Each criteria is compared in a pairwise function, with numerical values
assigned to the linguistic termed ‘importance’; intensities ranged from 1-9. The resultant
table easily compares the total values obtained by each criterion, allowing for a simple
computation of weightings. Cost and technology readiness level proved to be the two highest
weightings, with waste pollution and public acceptance being the smallest. On the other hand,
VIKOR first establishes an ideal solution, with all alternatives ranked in reference. The
process allows for negative criteria values, which means that two particular alternatives move
in entirely opposite directions. It also maintains additional qualities, including a ‘veto’ option
which ensures that alternatives balances the bias in the system.
AHP-VIKOR produced a result suggesting causticisation to be the most efficient process,
largely on the basis of technology readiness level. This laid the foundations for the primary
aim of this Thesis, to determine the economic viability of direct air capture. Accordingly, a
techno-economic analysis was performed on a causticisation capture system based on the
Kraft process. Modifications to the process had been made by both the American Physics
107 | P a g e
Society and Carbon Engineering, who provide a benchmark value for total capture cost. This
investigation sought to achieve a total capture cost in a similar range: that is, lower than
$USD 600/t-CO2.
The scale investigated in this Thesis was 1t-CO2/day, the minimum size for a pilot-scale
plant. It was reasoned that the technology had to be proven on a smaller scale before further
research and development into the process was acceptable. Nonetheless, the effects of
economies of scale were examined at a capture rate of 10t-CO2/day, 50t-CO2/day and 1MtCO2/year – the capture capacity at which both APS and CE modelled their system. In this
way, a direct comparison could be made between the three systems, and improvements easily
identified. Methodology in designing the system involved the selection of appropriate
equipment for each stage (contacting, regeneration, calcining and slaking), sizing and energy
calculations, selection of materials and a comparison of alternatives. These would serve as
inputs into the costing model for the techno-economic analysis.
A number of assumptions were made with regard to the costing model, ranging from
purchased equipment costs, to conservative percentage estimates for fixed costs and power
factors for scaling. The base case results were particularly underwhelming but not
unexpected. At 1t-CO2/day, the cost of capture was shown to be $6339/t-CO2; at 10t-CO2/day
a value of $2898/t-CO2 and 50t-CO2/day at $1737/t-CO2, which deviated significantly from
the benchmark. However, at a scale of 1Mt-CO2/day, the proposed system established a
capture cost of $AUD 545/t-CO2, well under the APS estimate given an exchange rate of 0.71
USD per AUD.
This result was primarily attributable to economies of scale; the purchased cost of equipment
constituted a large percentage of CAPEX, with all other components of CAPEX a fixed
percentage of PCE. As such, a power factor of 0.7 ensured that as the process was scaled,
capital costs reduced remarkably. Purchasing material could be done in bulk from a single
supplier, resulting in lower costs. Similarly, all necessary construction and contracting could
be done by a single company. On the other hand, OPEX did not scale as prominently – the
largest contributions came from operating labour and capital charges. No scaling factors exist
for either of these parameters; however, operating labour decreases exponentially with
increasing plant size. Capital charges are a fixed percentage of fixed capital investment, and
therefore indirectly scale based on purchased equipment cost.
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The composition of total cost proved vastly different between pilot scale and the commercial
scale, 57:43 and 87:13 respectively for CAPEX:OPEX. It implies that improvements in
causticisation should focus on the CAPEX component. In CCS systems, consumables and
utilities may make up a considerably greater portion of total cost, but this investigation has
shown that capital costs dominate direct air capture – the major barrier to implementation thus distinguishing itself from CCS. To realise cost reductions, a variety of alternative
configurations were examined through a sensitivity analysis.
Compression costs were exceedingly high, contributing approximately 30% to PCE. The
revised estimate resulted in a 5% weighting, which is considerably more reasonable. This
reduction resulted in a 24-26% decrease in total capture cost across all scales, thereby
demonstrating the sensitivity of the process to a major change in PCE. The initial cost
estimate was taken from chemical engineering textbooks, but was unrealistically high.
Another notable discrepancy in configurations was the substitution of natural gas power
generation for wind and nuclear energy. Despite having higher capital costs, the
environmental benefits provided are unparalleled – the entire plant could guarantee zero
carbon emissions. Thus, at a commercial scale of 1Mt-CO2/year, the facility would be
effecting real change in a global warming context. However, the costs are still prohibitively
high, despite wind power having the lowest levelized cost of electricity amongst all potential
renewables. Whilst it is widely accepted that co-generation of power will dominate the future,
DAC faces extensive financial risk as a result of large initial capital investments, and
accordingly cannot afford an increase. It should be noted however, that the substitution of
wind power resulted in a decreased OPEX – the only alternative configuration to directly do
so within this investigation. The need for natural gas was entirely removed, which
contributed considerably to the utilities cost.
The last major disparity occurred through a change in operating labour. For the pilot-scale
plant, a total staffing of 1 engineer and 2 shift supervisors was required. Naturally, a linear
increase in staffing as the plant scales would result in an irrecoverable OPEX each year. As
such, a power factor was implemented to reduce operating labour to a reasonable level. An
approximate 20% change in the operating labour resulted in a 2.2% change in the total
capture cost of the system – at 1Mt-CO2/year, this would allow $2.2 million in cost savings.
This again shows the major shortcoming of techno-economy analyses for processes fraught
with uncertainty; estimates can vary dramatically between models despite similar conditions.
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The overarching question of the economic feasibility of direct capture comes down to
iteration versus innovation. Which trajectory will reduce the primary barrier to
implementation? This Thesis concludes that both are necessary; innovation in adapting
existing technologies to reduce the associated capital costs, and iteration to ensure that the
process runs at optimal efficiency.
Direct air capture falls under a category of estimates where substantial research and
development is required to estimate the cost of the system, which is not fully designed.
Consequently, endeavouring to accurately calculate the costs of a future project (including
future learning achieved from scaled plants and more detailed estimates), is practically
impossible. Furthermore, the scope of technological advancement is very much dependent the
exposure direct air capture achieves and the quantity of deployment; this is in-turn dependent
on the cost and thus iterative modelling is desirable.
This Thesis drew comparisons with a number of existing commercial plants and highly
regarded literature, to identify the areas for improvement. Factors including the market price
of CO2 were entirely out of this project’s control. The forces of supply and demand vary with
geographic location, and thus the price commanded by each project differs vastly. Areas with
a stringent regulatory framework place higher incentive on ensuring zero carbon emissions,
rather than financially incentivising negative emissions technologies. Such policies are
deemed counterproductive however, as they stifle innovation by demanding a guarantee of
economic viability prior to funding. Whilst this makes sense from an investor perspective,
without further testing, these gains cannot be realised. However, the market price of CO2
determines the revenue generated from a facility. In the case of this thesis, CO 2 took a value
of $AUD 38.90 – determined by averaging the price of existing Carbon Taxes and ETSs. In
light of the extreme scale case mentioned in Section 5.6.1 – 5Mt-CO2/year at $AUD 334/tCO2, this price was still one order of magnitude too low. It is unreasonable however, to
assume that carbon prices can rise over $AUD 300 to match the current cost estimates of
direct air capture, even if storage and transportation costs are passed onto end-users.
Even with 100% government subsidisation, the revenues must rise above operating costs to
show that the process is economically viable. The cash flow analysis performed in Section
5.4 highlighted that a 1Mt-CO2/year facility receiving a loan equal to 100% of CAPEX would
still derive a break-even price of $AUD 116, well above any known price of CO2 (barring the
price commanded by the Climeworks facility in Zurich).
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Future work must therefore place a considerable focus on the following:
•
Design optimisation
o Equipment selection – choosing the most appropriate unit operation in each
stage, by adapting existing technologies or establishing a new process;
o Materials of construction – swapping to significantly cheaper materials e.g.
316 stainless steel to concrete, thereby reducing PCE.
o Sources of power – where possible, renewable energy should be integrated
into the system to reduce operating expenses in the long-term.
•
Cost model assumptions
o Contingency and Capital Charges – rather than estimates varying from 15100%, which significantly alters the outlook of a project, examine a
commercial case in more detail to ascertain the level required.
•
Sources of reutilisation
o Assessing market conditions in areas such as EOR, biofuels, carbonation and
greenhouses to determine the most profitable buyer.
Despite the limitations presented in this research, the potential costs of capturing emissions
using causticisation are highlighted. This paper also provides insight into alternative
strategies both through the literature review and process selection, with respect to their
ranking across a variety of pertinent criterion. Finally, the investigation demonstrated that
gains may be realised given technological improvement, a change in market conditions and
future research and development. It can be concluded that, in the broader context of climate
change, DAC is not economically feasible. The barriers to implementation that stem from
high initial capital investment to non-existent government subsidisation to large power
consumption, are overwhelmingly high. As a result, alternative strategies that reduce
distribution emissions such as electric cars, may prove to be more economic in the short-term.
Further research and development is undoubtedly necessary, and in the end, DAC may be
used, but only in conjunction with other mitigation techniques.
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