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Technology Readiness Assessment,
Costs, and Limitations of five shortlisted
NETs
•
Accelerated mineralisation, Biochar as soil additive, BECCS, DACCS,
Wetland restoration
Kenneth Möllersten, Raza Naqvi
Mälardalen University
March 2022
NET-RAPIDO Project
Negative emission technologies: readiness assessment, policy instrument
design, options for governance and dialogue
A collaboration between Mälardalen University (Sweden), Perspectives Climate
Research (Germany), and Climate Strategies (UK)
Content
Abbreviations .............................................................................................................. 1
Introduction ................................................................................................................. 2
Biochar ........................................................................................................................ 3
Introduction ........................................................................................................... 3
Biochar production ............................................................................................... 5
Technological readiness ...................................................................................... 16
Techno-economic analysis .................................................................................. 17
Deployment barriers and knowledge gaps .......................................................... 18
Bioenergy with Carbon Capture and Storage (CCS) ................................................. 19
Introduction ......................................................................................................... 19
CCS technology .................................................................................................. 20
Technological readiness ...................................................................................... 24
Techno-economic analysis .................................................................................. 31
Deployment barriers and knowledge gaps .......................................................... 35
Wetland restoration.................................................................................................... 39
Introduction ......................................................................................................... 39
Mitigation principles ........................................................................................... 39
Technological readiness ...................................................................................... 40
Techno-economic analysis .................................................................................. 41
Implementation barriers and knowledge gaps .................................................... 41
Direct Air Carbon Capture and Storage (DACCS) ................................................... 43
Introduction ......................................................................................................... 43
DAC technology ................................................................................................. 43
Technological readiness ...................................................................................... 46
Techno-economic analysis .................................................................................. 47
Deployment barriers and knowledge gaps .......................................................... 48
Accelerated Mineralization (AM) ............................................................................. 50
Introduction to the concept ................................................................................. 50
Accelerated Mineralisation technology .............................................................. 50
Technological readiness ...................................................................................... 52
Techno-economic analysis .................................................................................. 53
Deployment barriers and knowledge gaps .......................................................... 54
Summary and conclusions ......................................................................................... 57
Biochar as soil additive ....................................................................................... 57
BECCS ................................................................................................................ 58
Wetland restoration ............................................................................................. 59
DACCS ............................................................................................................... 59
Accelerated mineralization ................................................................................. 60
Technology readiness levels (TRLs) .................................................................. 61
Cost assessment .................................................................................................. 62
Realising the potentials ....................................................................................... 63
References ................................................................................................................. 65
1
Abbreviations
BECCS Bioenergy with carbon capture and storage
CAPEX Capital expenditure
CCS Carbon capture and storage
CDR Carbon dioxide removal
DAC Direct air capture
DACCS Direct air capture and carbon storage
EOR Enhanced oil recovery
GHG Greenhouse gas
ICS Improved cookstove
NET Negative emission technology
OPEX Operational expenditure
ppm Parts per million
SOC Soil organic carbon
TEA Techno-economic analysis
TRL Technology readiness level
USD United states dollar
WR Wetland restoration
2
Introduction
Scenarios reaching 1.5°C by 2100 included in the IPCC 1.5 degree report (IPCC, 2018)
rely on large volumes of Carbon Dioxide Removals (CDR) generated with Negative
Emission Technologies (NETs), ranging between 25 – 50% of current global greenhouse
gas (GHG) emissions (Anderson and Peters, 2016). In view of the magnitude of assumed
future NETs deployment, technical, socio-political and economic challenges will arise and
may impose serious constraints. Analysis of the readiness, feasibility and realistic potential
of NETs is therefore key for improving the understanding of a realistic potential for their
implementation.
The current report builds on previous work in which an assessment of the major classes of
NETs was carried out (Möllersten, et al., 2020a; Möllersten, et al., 2020b), including (i)
bioenergy with carbon capture and storage (BECCS); (ii) direct air capture and storage
(DACCS); (iii) large-scale afforestation and reforestation; (iv) soil carbon sequestration;
(v) Biochar as soil additive; (vi) Enhanced Weathering; (vii) Accelerated Mineralization;
(viii) Ocean fertilization and priority NETs were selected for further analysis on the basis
of a number of performance indicators. A comprehensive literature review was carried out
in accordance with the broad NET categories identified as outlined above resulting in a
substantial amount of data on all identified NET categories.
On the basis of a qualitative assessment, Accelerated Mineralization (AM), BECCS;
Biochar as soil additive; DACCS; and Wetland Restoration (WR) were shortlisted for
further analysis.
This report presents an in-depth technology readiness and cost assessment and an analysis
of practical deployment barriers for the selected NETs along with an analysis of related
knowledge gaps and research needs. The report is divided into sections in accordance with
the selected NETs and concluded with a summary and conclusions.
The work has been carried out as a component of Work Package 1 “Technology Analysis
of NETs” of the NET-Rapido research programme. NET-Rapido aims to create a clear
understanding of opportunities, challenges and risks of negative emission reduction efforts
based on an informed analysis and proper discussion amongst relevant stakeholders.
NET-Rapido is funded through a research grant from the Swedish Energy Agency.
3
Biochar
Introduction
Biochar is the solid remains of biomass that has been heated to temperatures typically
between 300 ˚C and 800 ˚C in an anoxic environment (Scholz, et al., 2014; Kumar, et al.,
2020; Brownsort, 2009). Pyrolysis is the primary technology for producing biochar. In
addition, biochar can be produced through hydrothermal carbonisation and biomass
gasification (Brownsort, 2009; Kumar, et al., 2020). Liquid and gas products, which have
a potential use as energy carriers, are typically produced along with biochar (Woolf, et al.,
2010; Lee, et al., 2019).
Organic materials fundamentally change their chemical composition through such
thermochemical conversion and are dominated by stable aromatic carbon forms, in contrast
to the original biomass feedstock that mainly contains cellulose, hemicellulose, and lignin
(Lee, et al., 2019; You & Wang, 2019). The creation of biochar from biomass places C into
a recalcitrant form which could last hundreds to over thousands of years (Ippolito, et al.,
2020). Biochar falls into the spectrum of materials called “black carbon,” which includes
substances with a range of properties, including slightly charred biomass, charcoal, and
soot (Masiello, 2004; Novak & Johnson, 2019).
1
Researchers have proposed several different definitions of biochar, e.g., Lehmann &
Joseph (2009), Scholz, et al. (2014), Kumar, et al., (Kumar, et al., 2020), on the basis of
either production method or its use. For the purpose of this report, which considers biochar
systems as a potential negative emission technology, the following definition is used, which
refers to both the production of biochar and its application:
“The porous carbonaceous solid produced by the thermochemical conversion of organic
materials in an oxygen-depleted atmosphere and which has physiochemical properties
suitable for the safe and long-term storage of carbon in the environment and, potentially,
soil improvement.” (UK biomass research centre, 2021)
Several authors include in their definitions of biochar the actual intention of using the
produced char as soil amendment, e.g., Lehmann et al. (2003), Seitz et al. (2017), and
Novak & Johnson (2019).
Mitigation principles
The practice of amending soils with charcoal for fertility management goes back millennia.
The currently best-known examples include the ancient practice of adding rice husk
charcoal to agricultural soils in Asia (Ogawa & Okimori, 2010) and the development of the
Amazonian soils known as terra preta, or “dark earths”. Terra preta soils are rich in
organic matter and highly fertile compared to the adjacent native soils (Lehmann, et al.,
2003). Terra preta soils also stand out for their capacity to store carbon, with as much as
three times the amount of soil organic carbon compared to surrounding soils (Glaser, et al.,
2001). They are thought to have been created through both habitation activities and
deliberate soil application by pre-Colombian populations (Lehmann, et al., 2006), who
1
Note that the term ”biochar” excludes black carbon derived from fossil fuels or non-biomass waste.
4
amended the soils with, among other components, charcoal, giving the soils their
characteristic black colour.
Seifritz (1993) suggested that massive implementation of charcoal production in
developing countries for long-term storage could be used to offset fossil emissions from
industrialised countries. The contemporary interest in biochar took off in the 2010s and
arises from the bringing together of the potential benefits for soils and agriculture with the
carbon storage or sequestration opportunity afforded by recalcitrant, stabilized aromatic
carbon. In 2006, Ogawa et al. proposed “Carbon Sequestration by Forestation and
Carbonization (CFC)” which involves biomass utilization and land conservation by
incorporating the products of biomass carbonization into agents for soil improvement,
water purification, etc. In a similar fashion, Lehmann, et al. (2006) proposed the application
of biochar to soil as a novel approach to establish a significant, long-term, sink for
atmospheric carbon dioxide in terrestrial ecosystems and achieve improved soil fertility
and increased crop production. Möllersten, et al. (2006) discussed production of biochar
based on sustainable biomass with subsequent application as soil amendment as a
distributed “negative emission biomass technology” which would have features that would
be complementary to the centralised option BECCS
2
.
Biochar production and deployment has the potential to bring one or more of the following
overlapping and interlinked benefits (Seitz, et al., 2017; Ippolito, et al., 2020; Kumar, et
al., 2020; Tisserant & Cherubini, 2019; Lehmann, et al., 2021):
•
Reduce atmospheric GHG concentrations through CO
2
removal and avoided
GHG
•
Improve the structure, properties and ‘health’ of soils;
•
Buffering capacity; Its porous nature makes it effective at retaining both water
and water-soluble nutrients
•
Increase crop productivity;
•
Provide energy (e.g. electricity from syngas, heat from syngas and bio-oil or
liquid fuel);
•
Safely dispose of certain waste materials with potentially useful recovered by-
products;
•
Absorb pollutants, contaminants and reduce nitrate leaching to water courses;
•
Suppress soil emissions of nitrous oxide and methane.
In addition to its use as soil improvement agent, biochar has a number of beneficial usages
in agri-food value chains before its application to croplands. The high-carbon material has
been applied as fertilizer coating to reduce nitrogen loss during storage, and as stabilizer
for manure and compost. Research over the past few years proved that amendments of
biochar to soils in farming systems in the tropics creates long-lasting benefits on food
production, water retention and input use efficiency, unlike in temperate latitudes where
biochar showed negligible or even negative effects on agriculture as soils are ‘younger’
and more fertile. On average, biochar addition to soils in tropical regions are found to
enhance yields of staple crops by 25% (Jeffery, et al., 2017). A one-time application of
biochar increases food production and soil carbon for more than a decade under intensive
cropping (Kätterer, et al., 2019). Biochar composition of inherently stable, recalcitrant
2
Abbreviated ”BECS”.
5
forms of organic matter leads to very low decomposition rate and very high persistence in
soil. This explains its overall positive effects on the accumulation of carbon (Wang, et al.,
2016). Input of maize stover as dry raw form has been shown to keep significantly less
carbon in soil over one year time and give lower crop production (Calderon, et al., 2015).
Biochar systems thus offer an attractive sustainable solution that utilizes locally available
resources, to contribute to enhanced agricultural productivity and the possibility to co-
generate electricity and/or heat. This chapter provides a review of the available
technologies.
Biochar production
Principles
Pyrolysis, the main technology considered for biochar production, is described as a thermo-
chemical decomposition process in which organic material is converted into a carbon-rich
solid and volatile matter by heating (400-700°C) in the absence of oxygen (Basu, 2018;
Kumar, et al., 2020). The solid, termed variously
3
as char, biochar, charcoal or coke
(depending on feedstock and intended use of the solid product), is generally of high carbon
content and may contain around half the total carbon of the original organic matter. The
volatiles can be partly condensed to give a liquid fraction (often referred to as bio oil)
leaving a mixture of so-called ‘non-condensable’ gases. The gas product is usually called
synthesis gas (often shortened to “syngas”). The process is represented simply in Fel!
Hittar inte referenskälla.. Each of the three product streams from pyrolysis, solid, liquid
and gas, can have properties and uses that provide value from the process.
Figure 1. Simple representation of the pyrolysis process.
There are two main process classes for biochar production through biomass pyrolysis, fast
and slow pyrolysis. Pyrolysis, hydrothermal carbonisation and gasification processes are
described briefly below. Pyrolysis generally has higher biochar yields (typically in the
range of 30%) as compared to gasification (around 10% or less).
3
While “char” may be used generally to describe the solid product of pyrolysis, “charcoal”
is commonly used for more traditional processes with wood as feedstock, and more recently
“biochar” has emerged as the term used where the intention is for the char to be used as a
soil amendment. “Coke” is used to denote fossil coal-derived char.
6
3.2.1.1 Fast pyrolysis
Fast pyrolysis is characterised by high heating rates (>200°C/min) and short vapour
residence times (<10 s). This generally requires a feedstock prepared as small particle sizes
and a design that removes the vapours quickly from the presence of the hot solids. There
are a number of different reactor configurations that can achieve this including ablative
systems, fluidised beds, stirred or moving beds and vacuum pyrolysis systems. A moderate
(in pyrolysis terms) temperature of around 500°C is usually used. The process is designed
to give a high yield of bio-oil. There are several well-established commercial processes.
3.2.1.2 Slow pyrolysis
Slow pyrolysis can be divided into traditional charcoal making and more modern processes.
It is characterised by slower heating rates (5-7°C/min), relatively long solid and vapour
residence times (>1h) and usually a lower temperature than fast pyrolysis, typically 400°C.
The target product is often the char, but this will always be accompanied by liquid and gas
products although these are not always recovered. Traditional processes, using pits,
mounds or kilns, generally involve some direct combustion of the biomass, usually wood,
as heat source in the kiln. Liquid and gas products are often not collected. Industrial scale
processes developed use large retorts operated in batch or continuous modes. These allow
recovery of organic liquid products and recirculation of gases to provide process heat. Prior
to the widespread availability of petrochemicals, such processes were used to generate
important organic liquid products (e.g., acetic acid and methanol).
Other developments in the later 20th century led to slow pyrolysis technologies of most
relevance for biochar production. These are generally based on a horizontal tubular kiln
where the biomass is moved at a controlled rate through the kiln; these include agitated
drum kilns, rotary kilns and screw pyrolysers (Brown, 2009). In several cases these have
been adapted for biomass pyrolysis from original uses such as the coking of coal with
production of ‘towns gas’. Although some of these technologies have well-established
commercial applications, there is as yet limited commercial use with biomass in biochar
production.
4
3.2.1.3 Flash pyrolysis
Very fast pyrolysis is sometimes referred to as ‘flash pyrolysis’. Higher temperatures and
shorter residence times than fast pyrolysis are used, the main product distributions are
similar to fast pyrolysis.
3.2.1.4 Gasification
Gasification is an alternative thermo-chemical conversion technology suitable for
treatment of biomass or other organic matter including municipal solid wastes or
hydrocarbons such as coal. It involves partial combustion of biomass in a gas flow
containing a controlled level of oxygen at relatively high temperatures (500-800°C)
yielding a main product of combustible syngas with some char. Although designed to
produce gas, under some conditions gasifiers can also produce low yields of biochar.
3.2.1.5 Microwave pyrolysis
In addition to conventional pyrolysis, biochar can also be produced via microwave
pyrolysis, which involves uniform penetration of microwave radiation throughout the
4
The term ‘intermediate pyrolysis’ is used occasionally but not consistently in the literature. Intermediate
pyrolysis, when applied to biomass, has performance similar to slow pyrolysis techniques, although
somewhat quicker .
7
treated biomass. Biochar produced from microwave pyrolysis is of higher quality and has
a relatively higher surface area and pore volume compared to that from conventional
pyrolysis.
3.2.1.6 Hydrothermal carbonisation
The pyrolysis- and gasification-based methods described above are suitable for dry
feedstock (below 10-12% moisture). However, these thermochemical processes are highly
energy-intensive to convert wet biomass like municipal waste into biochar, as they require
prior drying. This led the researchers to develop a process that can address the problems
associated with wet feedstock (Kumar, et al., 2020). Hydrothermal carbonization (HTC) is
a promising process for direct conversion of high moisture containing feedstock to carbon-
rich solid residue called “hydrochar”.
HTC involves the conversion of carbohydrate components of biomass (from cellulose) into
carbon-rich solids in water at elevated temperature and pressure. The process may be
suitable for concentration of carbon from wet waste streams that would otherwise require
drying before pyrolysis, making it complementary to pyrolysis and a potential alternative
to anaerobic digestion for treatment of some wastes.
Effect of feedstock and process parameters
3.2.2.1 Type of biomass feedstock
Biomass is generally composed of three main groups of natural polymeric materials:
cellulose, hemicellulose and lignin. Other typical components are grouped as ‘extractives’
(generally smaller organic molecules or polymers) and minerals (inorganic compounds).
These are present in differing proportions in different biomass types and the proportions
have an influence the product distributions on pyrolysis.
Primary products of hemicellulose and cellulose decomposition are condensable vapours
(hence liquid products) and gas. Lignin decomposes to liquid, gas and solid char products.
Extractives contribute to liquid and gas products either through simple volatilisation or
decomposition. Minerals in general remain in the char where they are termed ash.
8
Biochar primarily contains carbon and ash. Generally, the use of wood-based feedstock
generates biochar of high carbon content while e.g. biochar based on straw has higher ash
content. Depending on the feedstock the biochar can also contain certain nutrients such as
phosphorus. These nutrients can be loosely bounded leading to a higher availability for
plants or more strongly bounded and thus less available (Lehmann & Joseph, 2009).
3.2.2.2 Moisture content
Moisture content can have different effects on pyrolysis product yields depending on the
conditions. In traditional charcoal kilns heated internally by wood combustion, high
moisture levels lead to reduced charcoal yields as a greater quantity of wood must be burnt
to dry and heat the feed. For externally heated equipment the reported effect of steam on
the yield of char varies depending on the conditions.
Fast pyrolysis processes in general require a fairly dry feed so that the rate of temperature
rise is not restricted by evaporation of water. Slow pyrolysis processes are more tolerant of
moisture, the main issue being the effect on process energy requirement. For charcoal
making, wood moisture contents of 15-20% are typical (Brownsort, 2009).
3.2.2.3 Pressure, flow rate, heating rate
In general terms, any factor of pyrolysis conditions that increases the contact between
primary vapours and hot char, including high pressure, low gas flow, large particles or slow
heating is likely to favour char formation at the expense of liquid yield (Brownsort, 2009;
Kumar, et al., 2020; Yaashikaa, et al., 2020).
3.2.2.4 Conclusion: Selection of feedstock and production process
The choice of feedstock is likely to be dependent on factors such as availability, cost and
sustainability considerations. For any given feedstock it is possible to vary the product
distribution between char, liquid and gas, within limits, by choice of feedstock pre-
treatment and process type and operating conditions. Higher char yields are obtained by
slow pyrolysis processes with lower temperatures and low flow rates; higher liquid yields
Figure 2. Simplified representation of biomass pyrolysis (based on Brownsort (2009)).
9
arise from fast pyrolysis processes, specific temperatures and high flow rates. In general,
biochars produced at lower pyrolysis temperatures have a more diversified organic
structural makeup because there is less loss of volatile compounds. These biochars are
potentially more amenable as soil amendments for improving soil microbial properties and
increasing soil cation-exchange capacities. High-temperature biochars have higher
amounts of carbon in aromatic structures which makes them more recalcitrant to soil
microbial oxidation, with longer half-lives and, thus, a more appropriate selection for
increasing long-term carbon storage (albeit also with benefits to soil fertility) (Novak &
Johnson, 2019; Ippolito, et al., 2020).
Biochar production technologies
Carbonization technologies have been developed covering a broad range of applications
from very small-scale, household level up to industry scale pyrolysis retort (pressurized
vessel) systems. While small-scale systems, such as kitchen stoves (Gitau, et al., 2019;
Scholz, et al., 2014) enable farmers to utilize their own biomass residues without a need
for large capital investment large-scale biochar production facilities need large quantities
of concentrated biomass. IN ETHIOPIAN AGRICULTURE
3.2.3.1 Small-scale pyrolysis units
Traditional earth pits and mounds are mainly preferred due to their simple technology and
its local adaptivity. However, process energy remains unused, pyrolysis gas and vapors are
released to the atmosphere and the biochar yield is low (Seitz, et al., 2017).
The conical shaped flame curtain has been designed in the 2010s and is currently being
used in over 50 countries due to open-source technology transfer (Seitz, et al., 2017). Due
to the flame curtain, which contributes to the largest parts of the pyrolysis gases being
oxidized, these kilns allow for a relatively clean and rapid (within several hours)
carbonization of biomass at comparably low investment costs. Biochar yields are around
22%. However, a reasonable concept to use the heat of the biochar production still needs
to be developed to increase the energy efficiency of this process, since the largest part of
the produced heat is currently not used at all. Furthermore, these kilns require continuous
attention by the operator and independent research on this technology in developing
countries is missing.
Small-scale modern charcoal retort systems with an internal combustion of pyrolysis gases
are generally less problematic in this respect. The so-called ANILA stove developed by the
University of Mysore in India allows for using the pyrolysis gases for cooking.
10
Figure 3. The Anila stove (Central Institute for Dryland Agriculture, 2013).
3.2.3.2 Medium and large-scale pyrolysis units
Container-sized pyrolysis plants of various designs and sizes are available on the market.
Some examples are provided below.
PYREG is an example of a modern, medium to large scale industrial biochar production
facility. The biomass is transported into the system, pre-heated (and pre-dried) by the -
comparably clean - combustion gases and finally carbonized in the pyrolysis unit. The
resulting annual biochar production is approx. 220 t and 680 t for the PYREG P500 and
P1500, respectively (PYREG, 2021). Typical biochar yields are in the range of 30%. The
pyrolysis plant offers several options to use the process heat (150 kWth and 600 kWth,
respectively, e.g. for drying purposes). To run the plant, an electricity grid connection is
needed. The pyrolyzer is cooled by air, thus a water supply is not necessary. The maximum
feedstock water content is 50%. Investments costs for the P500 is around 400.000 €.
11
Figure 4. PYREG process scheme.
The international nature conservation organization PRO-NATURA has developed
different pyrolysis units (CarboChar 1-3, Figure 5) for an annual biochar production of 300
– 1,200 tonnes. It is possible to use the excess process energy (120 kWth - 1.000 kWth,
depending on the pyrolysis unit size) for heating purposes. Electricity supply and
emergency water supply is required to run the pyrolysis units. The maximum feedstock
humidity is 15%. The smallest unit is available for about 70.000 € and can be mounted on
a trailer to be moved from site to site.
12
Figure 5. CarboChar pyrolysis system.
A
GreenPower (Ukraine) produces the Bio-kiln, which comes in three different sizes. The
Bio-kiln is a continuously fed vertical retort kiln (Figure 6). Biomass feedstock is loaded
using a conveyor or a bucket loader into the storage hopper, from which, using a vibrating
feeder, the raw material is fed into the bucket elevator for loading into the loading hopper
of the furnace. By gravity, the raw material then passes through carbonization chamber via
the channels for raw material. The biochar product then enters the stabilization hopper
where it is cooled, after which it is unloaded using a screw conveyor. The flue gases from
the pyrolysis enter an afterburner, where they are completely combusted at high
temperatures (> 1250°C), reducing harmful emissions to ambient air. Exhaust flue gas
temperature after the afterburner of the furnace is more than 1000°C, which makes it
possible to use them for various thermal processes such as drying of raw materials, heating
of premises, steam production, etc. The Bio-kiln has a feedstock moisture tolerance up to
15% and feedstock particle size needs to be between 0,5 – 3 cm. The annual biochar output
of one unit will be approximately 500t, 700t or 1000t pa for the Bio-kiln 1, 2, and 3,
respectively. The biochar yield is around 30% (based on 10 percent feedstock moisture).
The Bio-kiln is fully automated.
13
Figure 6. Bio-kiln process scheme.
GRICULTURE
3.2.3.3 Small-scale gasifires
Biomass domestic gasifier cooking stoves (“gasifier-stoves”) made from steel (e.g. Phillp
stove, the Peko Pe stove, Figure 7, and the Vitalite stove) or clay are another option to
produce biochar. In general, cook stoves are attributed with the benefits of being more
efficient, time saving, saving household fuel spendings, causing less pollution, burning
different biomasses and, for gasifier stoves, combining biochar production with energy use
for cooking (Seitz, et al., 2017; Jürisoo, et al., 2018; Gitau, et al., 2019). The Gastov gasifier
cookstove had been reported to have a biochar yield of 12-18% (Roobroeck, 2020).
Gasifier stoves typically sell at USD 20-30 while simpler models might cost less than USD
10 and the top-of-the-line force draft Phillip stove USD 120-140 (Jürisoo, et al., 2018).
14
Figure 7. Design principle of the Peko Pe gasifier cookstove (Home Energy Ltd., 2020).
3.2.3.4 Medium and large-scale gasifiers
Medium to large-scale gasifiers for electricity and heat production available were
constructed to produce electric energy and due to this, they generally have a low biochar
yield (about 10%).
All Power Labs (US) offers the biomass gasifier genset (“Power Pallet”) PP30 (All Power
Labs;, 2020). The Power Pallet is designed to use agricultural and forestry waste
materials as fuel. The biomass consumption is approximately 25 kg/h. Four main parts
compose the machine: a 0.3 m2 hopper, where the biomass is loaded, a gasifier reactor,
where the thermochemical conversion of solid bio-waste takes place, a drum filter, where
syngas is cleaned from particulate and tars, and an engine connected with a brushless
generator in order to produce electrical energy. Power Pallet has a fuel moisture tolerance
up to 30% and feedstock pieces must be between 1 – 4 cm. The first passage of the
biomass in the reactor is the pyrolysis stage. A heat exchanger heated with the exhaust
gases allows a pyrolysis reaction. Once pyrolyzed, the biomass reacts with hot air
entering through air nozzles and generates a combustion zone where the pyrolysis tars are
cracked producing hot gases. In the reduction zone, the gases react with the carbon to
create CO, H2 and CH4 and other gases. The part of the char that does not react with
combustion gases is disposed of through an ash auger. The resulting syngas passes
through a passage between the outside wall of the reactor and the combustion zones,
causing a heat exchange between the intake air and the outgoing syngas. The PP30 power
output is 22-27 kW depending on operating conditions and 1,5-2 kWth/kWe. AT 6 000
annual operating hours biochar production will be around 12 t/a. The capital cost of the
PP30 is USD 80 000.
15
Figure 8. The PP30 Power Pallet from All Power Labs inc.
RESET (Renewable Energy Solutions Environmental Technology), Italy, offers the
biomass gasification CHP system Syngasmart. In the Syngasmart, the biomass is loaded
and stored in a tank for continuous feeding to reactors. A forced ventilation system blows
hot air from the engines section to the tank, in order to reduce biomass moisture to a proper
degree for gasification, which is around 10/12%. This feature allows to introduce also a
high-moisture content woodchips (up to 35%), once the CHP is running and generating
heat. The syngas is generated through multiple pyro-gasification downdraft fixed bed
reactors which feature the following components: loading hopper + rotary valve, pyro-
gasification reactor, cyclone dust collector, and automated biochar collector. The syngas at
the cyclone exit has high temperatures (ca. 300 °C) and some impurities, therefore it is
cooled down and filtered before being piped off to the double genset (internal combustion
16
engines). A Syngasmart 100 kWe unit produces approximately 150 kWth and consumes 115
kg biomass/h. The annual biochar production is around 30 t. The CapEx for the standard,
all integrated unit, is 590.000 EUR. OpEx varies according to labor cost particularly and
operational hours, but on average it is between 50 and 60 EUR per MWh, including spare
parts, consumables and labor (RESET, 2021; Manelfi, 2020).
Technological readiness
Technology readiness levels (TRLs) are a method used for estimating the maturity of
technologies. A scale from 1 to 9 is used with 1 being concept of a technology and 9
denoting a commercialized technology, for definitions of individual TRLs refer to Annex
1.
5
Technologies with TRL 6 and above have achieved sub-scaled demonstration with
prototypes that are fully functional. TRL of a technology does not directly relate to
potential for full commercialization barriers, for instance ability for mass production and
availability of supporting technologies such as compressors or coolers. The closer the
technology is to TRL 9 means that it is easier to deploy and that the number of suppliers is
greater.
6
For near-term deployment, only technologies with high TRL are realistic.
Note that the TRL concept is subject for discussion. E.g. IEA (2020) argue that arriving at
a stage where a technology can be considered commercially available (TRL 9) is not
sufficient to describe its readiness to meet energy policy objectives, for which scale is often
crucial. For this reason, the IEA proposes to extend the TRL scale to incorporate two
additional levels of readiness: one where the technology is commercial and competitive but
needs further innovation efforts for the technology to be integrated into energy systems and
value chains when deployed at scale (TRL 10), and a final one where the technology has
achieved predictable growth (TRL 11). However, in this report uses the 1-9 TRL scale
since this is the scale generally used in available literature.
Box 1. Technology Readiness Levels (TRL).
Available TRL assessments of biochar systems are generally on an aggregate level. Based
on the literature review, biomass pyrolysis and gasification systems TRLs range from 3 –
7 and biochar for soil impact TRLs range from 1-2 (Clare, et al., 2015; Someus & Pugliese,
2017; Napp, et al., 2018; Royal Society, 2018; National Academies of Sciences, 2018).
Some applications of pyrolysis including the production of pyrolysis oil, where stabilizing
the oil and further processing it into diesel substitute is still a challenge, are attributed with
a TRL of 5. Pyrolysis with cogeneration of biochar and heat are commercially available
and has been in long-term operation in multiple sites, indicating a TRL of 9. Gasification
systems where the main products are biochar, heat and power are available on the market
(refer to section 3.2.3.4) but lacks user cases with long-term operation under commercial
conditions. On the basis of discussions with technology providers our assessment that the
technology has reached TRL 7.
5
For further details refer to, e.g., the EU Horizon 2020 – Work Programme 2018-2020. https://ec.europa.eu/info/funding-
tenders/opportunities/portal/screen/support/faq/2890
6
IEAGHG (2019).
17
There are a handful of gasifier stoves and small-scale kilns for household applications that
are sold commercially in Africa and India and participatory tests have been carried out
(Sundberg, et al., 2020). Still unpublished research where the biochar from such stoves was
used in field trials with great success. Based on expert opinion the particular stove designed
used may have reached TRL 8 or above for energy and agriculture uses (Roobroeck, 2020).
As regards simple forms of soil biochar amendments combined with common agronomic
practices, studies in Africa are rapidly growing in number, including long-term
experiments in functional environment, see, for example, (Kätterer, et al., 2019). Based on
expert judgement soil biochar application can be placed at TRL 7 for Kenya (and Africa in
general) and should be at TRL 9 for Europe (Roobroeck, 2020). The mechanisms through
which biochar impacts crops are not fully understood, but its practical use is not held back
by it. One reason the TRL of biochar is often considered to be low may be that the supply
of sustainably sourced biomass feedstocks isn't commercially proven (Roobroeck, 2020).
This limitation, however, does not apply to cases where biomass residues are utilized as
feedstock.
Techno-economic analysis
A review of literature covering detailed techno-economic analysis (TEA) of biochar
systems has been carried out. It is clear from the review that the economic viability of
biochar systems is highly context specific, an observation that is frequently stated explicitly
in the reviewed literature sources.
The economic feasibility of systems depend on a range of variables, including (Brown, et
al., 2011; Kung, et al., 2013; Huang, et al., 2014; Homagain, et al., 2016; Zang, et al., 2017;
Allesina, et al., 2018; Heredia Salgadoa, et al., 2018; Ji, et al., 2018; Patel, et al., 2018):
•
Technical, such as type of process and the associated CapEx, OpEx,
efficiencies and outputs etc, and
•
Contextual, such as the cost of biomass feedstock (if any), the price of
electricity and fuels, whether thermal energy can be made useful and attributed
with a value, the price of biochar or the value of improved agricultural yields
in case the biochar is not sold to the market, and,
•
Potential value of GHG emission reductions and carbon removals
It is difficult to single out any parameters that would influence the economic feasibility
more than others. In some studied cases profitability is reached without any carbon
payments or other subsidies while in other cases the profitability is questionable at
considered carbon prices up to 30-40 USD/tCO2e.
Aggregate assessments of carbon abatement costs show a wide range, which reflects the
high dependency on, and large variability of, technical and contextual variables. E.g., Fuss
et al. (2018) found costs across literature in the range 30-120 USD/tCO2e and the Royal
Society (2018) the even wider range 18-166 USD/tCO2e.
Studies on the prospects of biochar production facilities in the long term are scarce in the
literature. Some techno-economic assessments suggest a potential decrease of biochar
production costs in the range of 10-20% compared to current levels, mainly associated with
its deployment at scale (IEA GHG, 2021).
18
The literature review did not identify any studies that explicitly address TRLs or TEA for
very small-scale, household level biochar production systems.
Deployment barriers and knowledge gaps
As an emerging technology biochar systems encounter multiple deployment barriers, e.g.,
industry scale systems face a lack of prior licensing of pyrolysis/gasifier systems in many
countries, agronomic advisory for biochar is missing in most countries, public acceptance
is largely unknown, limited in-practice know-how about pyrolyser/gasifier/biochar
systems, lack of skilled labour/technicians and operators for pyrolysers/gasification
systems, investment costs and risks not sufficiently understood, returns and payback time
not properly quantified, aversion to complex multi-disciplinary undertakings etc
(Roobroeck, 2020). Several of these barriers are most pronounced in developing countries
where the potential of biochar systems as a soil amendment to improve soil fertility is the
greatest.
Household level systems encounter several of the same barriers that are related to the
application of biochar to soils. In addition, they face similar barriers as “conventional” the
adoption of improved cookstoves (ICS), such as attention requirements and socio-cultural
fit (Jürisoo, et al., 2018). Barriers affecting gasifier stoves may be even stronger compared
to conventional ICS due to more demanding fuel preparation requirements and batch rather
than continuous feeding (Jürisoo, et al., 2018).
The techno-economic benefits of biochar as a soil-enhancement product is highly
contextual and requires further studies in multiple contexts. Although not a focus area of
this study, an important area for further study is the interaction of biochar with various soils
and climate conditions across the world. This comprises quantitative assessments of how
biochar soil amendments affect agricultural productivity, water use, and albedo and also
the mean CO2 residence time in soil, allowing long-term CO2 sequestration and potentially
validating under what conditions biochar systems can provide a negative emission route.
Because biochar composition and structure depend on the biomass feedstock and process
by which it is produced (Ippolito, et al., 2020), quantitative assessments should be coupled
with promising biomass-to-fuel conversion processes.
As regards very small-scale household level systems there are significant cultural and
behavioural barriers to implementation that need to both better understood and addressed.
An attempt to adapt the gasifier stove technology to the needs of households is made by
the Swedish company Make it Green, that is developing a gasifier stove (“BioCooker”)
with continuous (rather than batch) feeding (Make it Green, 2021).
19
Bioenergy with Carbon Capture and
Storage (CCS)
Introduction
Biomass Energy with Carbon Capture and Storage (BECCS) typically refers to the
integration of
(i)
Plant matter that removes CO
2
from the atmosphere as it grows,
(ii)
conversion of biomass to heat, electricity and/or gaseous or liquid fuels,
(iii)
the application of technologies to capture CO
2
from a gas stream, and
(iv)
compression and transport of CO
2
to a storage site
(v)
Long-term storage of CO
2
via injection into deep geological formations.
The potential of BECCS for climate change mitigation depends on a number of factors,
from biomass fuel supply to how efficiently CO2 is captured and transported, as well as the
integrity of the CO2 storage.
The concept of “negative emissions” relies on the premise that biomass feedstock can be
provided sustainably with zero or at least low carbon emissions. Generally, biomass
combustion, even if using sustainably produced feedstock, causes CO2 to be released more
rapidly to the atmosphere than it is absorbed by the biosphere via photosynthesis. In the
short to medium term, therefore, more CO2 is present in the atmosphere, although in the
long-term carbon-neutrality is achieved (Zanchi, et al., 2011).
Fuel supply involves either biomass residues, energy crops, forestry residues, or the
biogenic fraction of waste. Biomass often requires some level of pre-treatment prior to
transport or conversion. Depending on the feedstock as well as application, several pre-
treatment methods that may be used. Conversion technologies rely on similar approaches
as for other solid fuels, such as coal, but need to be optimized for biomass use. The
approaches build on either (Yan, 2015; National Academies of Sciences, 2018; Bui, et al.,
2018):
(i)
combustion, which uses air or pure oxygen to fully oxidize biomass to
produce heat and/or power,
(ii)
gasification which uses an oxidizing agent to partially oxidize biomass to
produce synthesis gas, having carbon monoxide and hydrogen as main
components, that can then be converted to various liquid hydrocarbon fuels
or combusted for heat and/or power generation,
(iii)
pyrolysis/torrefaction, where biomass is thermally decomposed in an
oxygen-free environment, and
(iv)
anaerobic digestion to produce methane-containing gas
(v)
and fermentation to produce fuel ethanol.
CO2 separation technologies for biomass-based thermal and electrical power generation are
generally the same as those currently under development for CO2 capture from the energy
use of fossil fuels. Broadly, these technologies fall within four main categories: post-
combustion, pre-combustion, oxy-combustion, and high-temperature solids-looping
processes (Rackley, 2017; Bui, et al., 2018; IEAGHG, 2019).
20
On a general level, BECCS is primarily suitable for large point sources of biogenic CO2
due to economies of scale. Furthermore, for any CCS scheme a highly concentrated CO2
stream enables CO2 capture that is less energy-demanding and less costly. Another
important parameter is whether the CO2 emissions at a facility originate primarily from one
large point source or from several smaller point sources: the former is preferable, because
capturing CO2 at several different places within a facility will drive up costs (Garðarsdóttir,
et al., 2018).
Geological CO2 storage closes the BECCS value chain. It involves the
compression/liquefaction of CO2 after it has been captured, followed by transportation to
a site where it can be injected down a well into a geologic formation that is deep enough
for the CO2 to remain as a supercritical fluid, typically 1000 meters or more.
Compression/liquefaction of the CO2 gas increases the density and thus allows for more
cost-efficient transportation and more CO2 to be sequestered given a certain storage space.
The possibility of leakage of CO2 from storage could seriously compromise the strategy’s
long-term potential. Careful site selection and long-term stewardship of storage sites is
therefore of utmost importance for the environmental integrity of BECCS (as well as for
CCS applied to emissions from fossil fuels) (IPCC, 2005; Cusack, et al., 2014; International
Energy Agency, 2020).
CCS technology
CO2 capture technologies
There are four main approaches, or categories, to carbon capture (Rackley, 2017; Bui, et
al., 2018; IEAGHG, 2019; International Energy Agency, 2020).
•
Post-combustion capture is when CO2 is separated from the flue gases after
the combustion of a fuel. After the separation the flue gas, which now mainly
consists of nitrogen is discharged to the atmosphere and the CO2 can be
transported to a storage site.
•
Pre-combustion capture is when CO2 is separated before the combustion. In
the context of BECCS, pre-combustion capture requires gasification of the
biomass prior to CO2 separation.
•
Oxyfuel combustion is when a fuel is combusted in relatively pure oxygen
instead of air, which results in a flue gas that comprises of CO2, steam and
possibly some impurities. The flue gas is cooled and compressed below its
water dew point so that the water can be removed and the remaining impurities
are removed in the same manner as in post-combustion capture.
•
High-temperature solids-looping processes use the same principal as oxyfuel
combustion, which is letting the fuel combust in oxygen and produce a flue gas
with high concentration of CO2. The two approaches principally differ in how
the oxygen is separated from the air stream.
21
Figure 9. Simplified block diagrams of coal or biomass power with carbon capture approaches: post -combustion,
pre-combustion, oxy-combustion, and chemical looping carbon capture (belonging to the group High-temperature
solids-looping processes). (National Academies of Sciences, 2018).
In practice, the most appropriate capture technology for a given application depends on a
number of factors, including the initial and final desired CO2 concentration, operating
pressure and temperature, composition and flow rate of the gas stream, integration with the
original facility, and cost considerations (International Energy Agency, 2020).
The four categories are given a more detailed description below.
4.2.1.1 Post-combustion capture
Post-combustion CO2 capture processes involve removing the CO2 from a gas stream after
the combustion process. There are various types of post combustion CO2 capture
technologies, including
•
liquid absorbents,
•
membranes,
•
adsorbents,
•
cooling and liquefaction,
•
electrochemical separation, and
22
•
microbial and microalgae.
The above categories can be further divided in sub-categories.
For post-combustion applications, the most technologically mature process is absorption
of CO2 into solutions of aqueous amines and amine blends (liquid absorbents). The
standard process is a cyclic absorption/desorption process. There are several technologies
already offered commercially, with widespread use in applications such as natural gas
processing. Applications in large-scale CO2 capture in power plants is, however, still
limited. Remaining developmental challenges include very large volumetric gas flows to
be treated and oxidative flu-gas conditions. Several other liquid absorbent processes are
under development but remain in less advanced stages compared to aqueous amines.
Membranes are a thin barrier over which one species is less mobile than others present in
a gas mixture. Membranes are attractive for post-combustion CO2 capture due to their low
energy requirement and modular nature. Several membranes capable of separating CO2
have been developed but challenges related to scale-up to power plant and large industrial
scale flu gas streams are present. Early economic assessments indicate a cost around 30%
above standard amine-based absorption. Generally, there is a lack of detailed techno-
economic performance data for real systems.
Solid adsorbents are potentially a lower-energy alternative to liquid absorbents. The target
gas component adsorbs (physically or chemically) onto the solid surface and once
saturation is reached the adsorbent can be regenerated by temperature, pressure or electrical
swings. CO2 capture with solid sorbents faces several challenges and operational
experience with real flu gas streams is critical.
Low-temperature separation involves cooling the flu gas stream to the point where the CO2
forms a liquid or a solid that can be separated. Potential advantages include no chemicals
needed (and hence no related emissions) and no requirement for steam extraction. The
technology still remains at relatively early development stage and requires further process
development and extended operation before large-scale demonstration.
Electrochemical separation processes use differences in electrical potential to facilitate
either the capture or release of CO2. The technology is at very early development level and
may be most promising in fuel cell applications.
Biological processes (CO2 to promote plant or algae growth) at large scale are at early
development stages and currently have unfavourable economics.
4.2.1.2 Pre-combustion capture technologies
Pre-combustion capture involves removing the CO2 prior to combustion. After gasification
of a carbonaceous fuel the raw syngas, a mixture of CO, CO2, H2, CH4, N2, H2O, and trace
contaminants, is cleaned to remove toxic impurities. Subsequently the gas is shifted, using
the water-gas shift reaction, to generate a gas stream of H2 and CO2. The resulting syngas
can be combusted or purified if H2 is desired. Where CO2 is captured, this can usually be
done at elevated pressure thus reducing the need for CO2 compression. Moreover, due to
higher CO2 partial pressure compared to combustion flue gas streams, pre-combustion CO2
capture processes are inherently more efficient than their post-combustion capture
counterparts. Higher overall efficiencies compared to post-combustion capture is offset by
higher capital costs.
23
Main pre-combustion capture technologies include liquid absorbents, gas-separation
membranes, adsorbents, and cryogenic separation, which can be further divided into sub-
categories.
4.2.1.3 Oxy-fuel combustion technologies
In oxy-fuel processes, nitrogen is removed from the air prior to combustion. The
carbonaceous fuel is then combusted in nearly pure oxygen generating a flue gas consisting
of mainly CO2 and water. Air separation and the final CO2 purification technologies are
well established, albeit very energy intensive. Ongoing research is mainly focused on
reducing energy consumption of the process. Large-pilot scale demonstration of the oxy-
fuel process has been achieved. Oxyfuel plants are generally estimated to offer the same
CO2 capture cost as standard post-combustion capture processes.
4.2.1.4 High-temperature solids looping processes
Calcium looping processes use calcium oxide (CaO) as a regenerable CO2 capture sorbent.
Flue gas is brought in contact with a fluidized bed of CaO which reacts with CO2 to form
calcium carbonate (CaCO3) at temperatures around 650 ˚C. The CaCO3 is conveyed to a
separate fluidized bed reactor where Cao is regenerated.
Chemical looping combustion is a two-step energy conversion process where the fuel and
air reactors are separated. An oxygen carrier is used to transfer oxygen from the air reactor
to the fuel reactor. This allows the fuel to react with oxygen, thus generating a highly
concentrated CO2 stream. Significant pilot-scale evaluation has been achieved, however at
smaller scales. Chemical looping combustion incorporating power production has not been
demonstrated.
CO2 transportation
The significant volumes of CO2 requiring transport as a result of large-scale CO2 capture
means that primarily two methods are practical, networks of pressurised pipelines and ship
transport. These technologies for CO2 transport are well established. The selection of mode
for transportation depends to a great extent on the quantity of CO2 and the distance from
the point of capture to the point of storage. Shipping is more favourable for a project with
lower CO2 flow rates (depending on transport distance) and longer transport distances
(depending on flow rate), due to the highly capital-intensive nature of pipeline costs (IEA
GHG, 2020).
Prior to transportation the CO2 stream must be compressed or liquified, which in many
cases represents a significant use of energy. Given the significant energy requirement
further work is called for to identify ways to improve the efficiency of this stage.
CO2 pipelines need to be designed and constructed (i) as to ensure that they are reliable and
safe to operate and (ii) in as cost-efficient fashion as possible. One important constraint is
that the phase transition should be avoided as it can result in operational problems. To avoid
this, feed pressures and temperatures must be chosen so that the fluid remains in the single-
phase region along the length of the pipe under normal operating conditions. The
composition of the CO2 mixture will impact the design as it has implications for the
permissible operating envelope. Furthermore, the level and type of impurities can influence
the material requirements of the steel used for the pipeline’s construction; this includes
both the steel strength needed to prevent fracture and the possibility of corrosion.
24
Shipping it is considered to be the lower cost option over very long distances although it
may also represent a least cost option when there are several small distributed sources. In
contrast to the case of pipeline transport, where the capital cost is the main driver, the
operating costs make up the bulk of total cost for shipping. The reduction of this cost of
liquefaction represents a key technical challenge as it makes up a significant share of the
cost in many cases.
Overall, there remain uncertainties around material selection and operation which
necessarily introduces conservativeness in design. A key challenge is to understand the
constraints for each transport technology to reduce the over-design and associated costs, as
well as where restrictions placed on the feed streams (for example purity) can be relaxed
to allow a reduced-cost whole-system design.
CO2 geological storage
Injection into oil-, gas-, and water-bearing geological formations is widely regarded as the
front-running option for CO2 storage and is the only option that has so far been applied on
a commercial scale (Rackley, 2017). The readiness of this option for commercial
deployment is due to the use of site characterization, injection, and monitoring technologies
that have been developed and widely deployed in the oil and gas industry. Two main
storage options are available: storage in formations containing non-potable water (saline
aquifers) or in oil and gas reservoirs.
The use of oil or gas reservoirs, whether producing or depleted, has a potential economic
advantage if injection can enhance hydrocarbon recovery, as well as a risk-management
advantage since the occurrence of hydrocarbons already demonstrates the presence of a
sealing cap rock that has remained competent on a geological timescale (albeit without the
potential geochemical impact of CO2).
For saline aquifer storage, this sealing capacity will need to be demonstrated by initial site
characterization studies and will also be an objective of monitoring throughout the life of
the storage project.
Although carrying a wide range of uncertainty, such estimates suggest a global capacity of
1000-1200 Gt CO2 in depleted oil and gas fields, including EOR applications, up to 20,000
Gt CO2 in saline aquifers and potentially twice this amount for in situ mineral carbonation
(Rackley, 2017). Available capacity is therefore unlikely to be a limit on CCS
implementation, although matching source and storage locations will also require
investment in CO2 transportation infrastructure.
Technological readiness
There are several potential biomass-to-energy technologies, some of which are
commercial. Across the full range, technologies are at varying technology readiness levels
(Yan, 2015; National Academies of Sciences, 2018; Royal Society, 2018).
Technology for CO2 capture from gas streams is well established in some applications (Bui,
et al., 2018; IEAGHG, 2019; Johnsson & Kjärstad, 2019; International Energy Agency,
2020). Post combustion capture is a mature capture technology and the processes involved
have been applied in some industrial applications for many years. Post combustion capture
25
based on chemical absorption is applied in a number of relatively large-scale CCS projects
around the world (Global CCS Institute, 2021), mainly to power plants, and therefore
features proven technologies.
In total there were 26 commercial CCS projects in operation around the world in 2020 with
a total capture capacity of around 40 Mt CO2/year (Global CCS Institute, 2021). Most of
them associated to Enhanced Oil Recovery (EOR).
BECCS is already operating in the biofuel production sector. There are currently more than
ten facilities capturing CO2 from bioenergy production around the world (Fel! Hittar inte
referenskälla.). So far, most of the completed or operating projects involve ethanol plants.
Fermentation produces a high-purity (99%) gaseous stream consisting only of CO2, H2O,
and small amounts of other compounds. Therefore, purification, dehydration, and
compression of fermentation streams can be accomplished at low cost (Sanches, et al.,
2015). The Russel CO2 injection plant in Kansas, USA was the earliest completed
demonstration, sequestering a total 7.7 kt of CO2 between 2003 and 2005. The Illinois
Industrial CCS Project (previously known as Illinois Basin - Decatur Project), with a
capture capacity of 1 MtCO2/yr, is the largest and the only project with dedicated CO2
storage (Finley, 2014) while other projects use the captured CO2 for EOR or other uses or
vents the captured CO2. More recently, the Mikawa Post Combustion Capture
Demonstration Plant in Japan launched the operation of a CO2 capture demonstration in a
biomass-fired power plant in 2020 with a 180 kt CO2 capacity. The project previously
developed a smaller scale pilot CCS unit (3 kt CO2/year) for coal-biomass co-fired power
generation.
Upcoming BECCS projects (Fel! Hittar inte referenskälla.) include the Norway Full
Chain CCS which is a large-scale project aiming to implement CCS for a cement plant that
uses biomass for over 30% of its fuel consumption and for a waste-to-energy plants, aiming
to store 800 kt CO2/yr in an offshore storage site in the North Sea. Following a
demonstration in a cement plant, the Norway Full Chain CCS is expected to start operating
by 2023 or 2024. Drax bioenergy carbon capture storage project, UK, aims to sequester 4
million tons of CO2 per year in a coal and biomass power plant, also in the North Sea.
Stockholm Exergi, Sweden, aims to capture approximately 800 kt CO2/yr in a biomass-
fired CHP plant to be shipped for storage offshore in Norway or elsewhere. Other
upcoming BECCS project in ethanol production include the Occidental/White Energy
project in Texas, US, which aims to sequester emissions from an ethanol plant at 600–700
kt CO2/yr capacity for EOR, the CPER Artenay project in France and Sao Paulo in Brazil.
Post combustion capture using chemical solvents is currently the only technology with a
potential to be more generally viable, especially when retrofitting existing plants. The other
capture technologies are either less mature, have not been tested at scale or would require
that existing industry processes are replaced or redesigned thus making it more difficult to
assess not only the technology performance but also the cost of capture (Johnsson &
Kjärstad, 2019). BECCS designs based on pre-combustion capture include biomass
gasification, which requires further research, development, and demonstration in order to
reach commercialization (Yan, 2015).
Carbon capture technologies have been developed to be used with fossil fuel feedstocks.
While biomass can be likened to coal in terms of basic composition the different properties
26
of biofuels compared to fossil fuels can clearly change the performance of the technologies.
A number of related knowledge gaps remain which magnify the uncertainties regarding the
cost of BECCS.
7
Of the different parts of a potential CCS supply chain, CO2 transport is the most mature
(Levihn, et al., 2019). There are >6500 km of CO2 pipelines worldwide (both on- and off-
shore), most of which are associated with EOR operation in the United States (Bui, et al.,
2018). Liquefied CO2 is currently transported by sea tankers, albeit a relatively modest
trade and in comparatively small quantities of around 2,000 tonnes (IEA GHG, 2020).
Moreover, the transport of gaseous and liquid fuels in pipelines and ships is common.
The injection and sequestration of CO2 at rates over 1 Mt CO2 per year at individual sites is
technically viable, demonstrated by 14 currently operating industrial scale projects,
including three injecting into saline aquifer systems. CO2 storage research has progressed
significantly over the last decade. The technical feasibility of CO2 storage has been
demonstrated through a number of industrial scale projects, with most being CO2-EOR
projects. In the norwegian ‘Northern Lights’ CO2 transport and storage initiative storage
capacity will initially be up to 1.5 million tonnes of CO2 per year but the project has the
potential to increase the transport and storage capacity up to 5 million tonnes CO2 per year
and provide an open acces storage solution for industrial facilities around Europe. Further
storage projects are under development in Denmark and Iceland and at other sites in
Northern Europe. In Iceland preparations are underway for a new onshore CO2 mineral
storage facility where CO2 is planned to be injected into the basaltic bedrock. The aim is
to start operations in 2025 and reaching full-scale operations, with an annual storage
capacity of three million tonnes of CO2 by 2030.
The technology for CO2 storage monitoring was originally developed for the petroleum
industry. Further development of monitoring instruments is required to enable quantitative
predictions of the amount of CO2 stored, the extent of plume migration, geophysical
saturation, and the extent of CO2 trapping and dissolution. Leak detection has not been a
focus for the petroleum sector, and advances in leak detection and remediation technology
is required to ensure that the storage of CO2 is permanent.
Table 1.
Bioenergy with CCS/CCU projects, completed or currently operating worldwide
(International Energy Agency, 2020; Consolli, 2019; Möllersten, et al., 2021).
Plant
Country
Sector
CO2
storage
or use
Start-
up
year
CO2 capture
capacity
(kt/year)
Russel CO2 injection
plant
US
Ethanol
production
EOR
2003-
2005
3,85
Arkalon CO2
compression facility
US
Ethanol
production
EOR
2009
290
OCAP1
NL
Ethanol
production
Use
2011
<400
7
Hailong Li, Beibei Dong, Worrada Nookuea, Qie Sun, Eva Thorin, Jinyue Yan, Zhixin Yu, Capturing CO2 from bioenergy conversion – opportunities and
challenges, draft, to be submitted.
27
Plant
Country
Sector
CO2
storage
or use
Start-
up
year
CO2 capture
capacity
(kt/year)
Organic Carbon Dioxide
for Assimilation of Plants
NL
Ethanol
and Oil
Refinery
Use
2011
400
Bonanza BioEnergy
CCUS EOR
US
Ethanol
production
EOR
2012
100
Husky energy CO2
injection
Canada
Ethanol
production
EOR
2012
90
Calgren renewable fuels
CO2 recovery plant
US
Ethanol
production
Use
2015
150
Lantmännen agroetanol
Sweden
Ethanol
production
Use
2015
200
AlcoBioFuel bio-refinery
CO2 recovery plant
Belgium
Ethanol
production
Use
2016
100
Cargill wheat processing
UK
Ethanol
production
Use
2016
100
Illinois Industrial Carbon
Capture and Storage
US
Ethanol
production
Dedicated
storage
2017
1000
2011-
2014
300
Saga city waste
incineration plant
Japan
Waste-to-
energy
Use
2016
3
Mikawa post-combustion
capture plant
Japan
Power
generation
Vented2
2020
180
2009
3
Saint-Felicien Pulp Mill
and Greenhouse Carbon
Capture Project
Canada
Pulp and
paper
Use
2018
11
1 The OCAP plant receives its CO2 from multiple sources and only part of the total CO2 qualifies as bioenergy
with CCU.
2 CO2 is vented after capture as part of research/pilot trials, but the long-term plan is to focus on offshore
permanent storage.
Table 2. Planned BECCS projects (Global CCS Institute, 2021).
Plant
Country
Sector
CO2 storage
Development
stage
(Start-up year)
CO2
capture
capacity
(kt/year)
Stockholm Exergi
BECCS project1
Sweden
Combined
heat and power
Vented
Pilot (2019)
-
North sea
Large (planned
2026)
800
Drax BECCS
plant1
UK
Power
generation
(coal and
biomass)
Vented
Pilot (2018)
-
North sea
Large-scale (2027)
4000
Norway Full
Chain CCS
Norway
North Sea
Large-scale (2023-
2024)
800
28
Plant
Country
Sector
CO2 storage
Development
stage
(Start-up year)
CO2
capture
capacity
(kt/year)
Cement plant
and waste-to
energy plant
Vented
Demonstration and
pilot at Norcem
cement plant
(2013)
-
Occidental/White
Energy
US
Ethanol
EOR
In evaluation
(TBC)
600-700
CPER Artenay
project
France
Ethanol
Dogger and
Keuper saline
aquifers,Paris
Basin
Development
Planning (TBC)
45
Sao Paulo
Brazil
Ethanol
Saline
aquifer
In evaluation
(TBC)
1-5
1 CO2 is vented after its capture as part of research/pilot trials, but for the full-scale projects CO2 will be
stored in deep geological formations.
Technology readiness levels
4.3.1.1 Bioenergy
According to the Royal Society (2018), TRLs of bioenergy is 7-9 on the basis of a TRL
scale from 1-9. A more detailed assessment can be found in American National Academies
of Sciences (2018) with TRLs ranging from below 4 up to 10 on the basis of a TRL scale
from 1-10, please refer to Fel! Hittar inte referenskälla. below which illustrates biomass-
to-energy pathways paired-up with their respective technology readiness levels.
29
Figure 10. Biomass-to-energy pathways and technology readiness levels ( (National Academies of Sciences, 2018).
4.3.1.2 CO2 capture
Technology readiness levels of CO2 capture technologies have been assessed in detail in
the following comprehensive studies (Bui, et al., 2018; National Academies of Sciences,
2018; IEAGHG, 2019; International Energy Agency, 2020), please refer to
Table 3. TRLs of CO2 capture technologies.
which highlights the key capture technologies that have reached the most advanced TRL
within each category.
30
Table 3. TRLs of CO2 capture technologies.
Carbon
capture
category
TRL
Post-
combustion
Separation technologies
Liquid absorbents
Aqueous amines
6-92; 93; 95
Amino acids and other mixed
salts
62
Catalysts
62
Membranes
Polymeric membranes
62; 63
Hybrid processes
62
Solid sorbents
Pressure-swing adsorption
62; 73; 95
Temperature-swing
adsorption
62; 73; 5-75
Pre-
combustion
Physical solvents
95
H2 separation membranes
5-62
CO2 separation membranes
5-62
Oxy-fuel
71; 73; 7-84
High-
temperature
solids looping
Chemical looping combustion
61; 4-52;
63; 5-65
Calcium looping combustion
62; 63; 6-75
Biomass carbon capture
Ethanol from lignocellulose with carbon
capture
5-64
Biomethane with carbon capture
7-84
Ethanol from sugar/starch with carbon
capture
7-84
Biomass power with chemical absorption
7-84
1National Academy of Sciences (2018). 1-10 TRL scale.
2IEAGHG (2019). 1-9 TRL scale.
3Bui et al. (2018). 1-9 TRL scale.
4International Energy Agency (2020). 1-11 TRL scale. the IEA has extended the TRL scale to
incorporate two additional levels of readiness: one where the technology is commercial and competitive but
needs further innovation efforts for the technology to be integrated into energy systems and value chains
when deployed at scale (TRL 10), and a final one where the technology has achieved predictable growth
(TRL 11).
5 (Kearns, et al., 2021).
4.3.1.3 CO2 transportation
According to (Bui, et al., 2018) on- and off-shore pipeline and ships all have a TRL of 9 as
they are currently being used in commercial applications for CO2 transportation.
31
(International Energy Agency, 2020) report that pipeline transportation has TRL11
(mature) while lower TRLs are associated with ship port to port, 7-8, and ship port to
offshore, 5-6.
Global CCS institute (Global CCS Institute, 2021) place pipeline transport as TRL 8-9,
truck as 8-9, rail as 7-9, ship design as 3-9, and ship infrastructure as 2-9. The lowest
TRL (2-3) relates to offshore injection into a geological storage site from a ship.
4.3.1.4 CO2 geological storage
As many commercial-scale CCS projects already use CO2-EOR (13 of the 17 operating
commercial-scale CCS projects) there is a significant amount of existing experience and
knowledge, which has enabled CO2-EOR to reach TRL 9 (Bui, et al., 2018). Similarly
Global CCS institute (2021) rates EOR as TRL 9 and (International Energy Agency, 2020)
also reports the highest TRL of the scale applied, 11, for CO2-EOR.
Saline formations have been used for CO2 storage at commercial scale project, including
Sleipner CO2 Storage, Snohvit CO2 Storage and Quest (on-shore and off-shore) and are
reported to have reached TRL 9 (Bui, et al., 2018; International Energy Agency, 2020;
Global CCS Institute, 2021).
In contrast, CO2 storage by enhanced gas recovery (EGR) and storage in depleted oil and
gas fields have not reached operation at commercial-scale, thus, both are still at the
development to demonstration phase (TRL 5-8) (Bui, et al., 2018; International Energy
Agency, 2020; Global CCS Institute, 2021).
Ocean storage and mineral storage are not considered in this CCS section.
Techno-economic analysis
Economic assessments published in the literature so far, have arrived at a wide abatement
cost range of approximately 15–400 US$ (excluding the most extreme estimates) per tCO2
for BECCS (McLaren, 2012; Kemper, 2015; Fuss, et al., 2018). These estimates include a
variety of environments in which CCS is applied to biogenic CO2 and, furthermore,
regional, financial, technological etc. assumptions that impact the final outcome of the
analysis. The cost of capturing CO2 can vary significantly, mainly according to the
concentration of CO2 in the gas stream from which it is being captured, the plant’s location
and related logistical prerequisites for CO2 transportation and storage, energy and steam
supply, and integration with the original facility Large-scale BECCS in power plants tends
to be in the upper part of this range, whereas smaller niche applications, such as ethanol
fermentation and biomethane production, are on the lower end.
IEA (2020) reports that capture from fuel transformation processes (such as bioethanol
production from sugar or starch) or biomass gasification (where only pre-treatment and
compression are needed to capture CO2) are the cheapest at present, with costs ranging
from about USD 15/tCO2 to USD 30/tCO2. Capture in biomass-based power generation
costs around USD 60/tonne, while BECCS applied to industrial processes has a capture
cost of around USD 80/t.
32
A factor affecting costs in the opposite direction is that scaling BECCS globally, along
with the growing demand for land for competing purposes, is expected to elevate cost as
the aggregate demand for land, and thus the value of land, is elevated.
The most immediate alternative for BECCS in Sweden and the EU would be the integration
of CCS with existing biomass-based power production or combined heat and power (CHP)
applying post-combustion capture using chemical absorption. However, as technologies
have been developed to be applied to industrial fossil-based CO2 sources, technologies
would in many cases have to be adapted to the different fuel properties and flue gas
composition of biomass fuels.
Techno-economic analysis of BECCS in a Nordic context
Below the results of some recent Nordic BECCS feasibility studies based on real life
conditions are summarised:
Johnsson et al. (2020) evaluated the cost of CO2 capture applied to Swedish industrial point
sources above 500 ktCO2/a, assuming post-combustion capture. The study found that the
cost of capture for a significant share of the biogenic emissions included in the analysis
varied in the range 47 – 60 €/tCO2. The cost of CO2 transportation and storage is estimated
to range between 20 - 40 €/tCO2 depending on the accumulated annual amount of CO2
captured in Sweden.
In a recent report by Beiron et al. (2022), the cost of post-combustion CO2 capture applied
to Swedish CHP facilities in the district heating sector was analysed. The analysis includes
biomass-fired CHP as well as waste-to-energy CHP (where the vast majority of CO2 is of
biogenic origin). According to the analysis about 2/3 of the CO2 can be captured at costs
ranging from 50 - 75 €/tCO2. The remaining share of the emissions, representing small
facilities, have higher capture costs reaching above 150 €/tCO2 in extreme cases.
Stockholm Exergi, the largest actor in the Stockholm multi-energy system, estimated the
cost of BECCS in the existing Stockholm Värtan CHP plant to 60-93 Euro per tCO2
assuming geological storage in Norway (Levihn, et al., 2019). The plant capacity would be
approximately 800 000 tCO2/year. The largest uncertainties are found to be related to the
investment cost of the capture unit and cost of utilizing storage infrastructure. The
corresponding cost assuming a hypothetical geological storage alternative in the Baltic sea
is estimated to 55-79 Euro per tCO2.
A joint feasibility study by the utility Vattenfall and the city of Uppsala addressed how
BECCS can practically be implemented in the Uppsala energy system. The study
concluded that post-combustion capture would be the most feasible approach. A solution
was proposed in which a BECCS facility can be integrated into the system of the Uppsala
combined heat and power plant, which incinerates municipal solid waste. The results
indicate that the plant in Uppsala could capture approximately 200 000 tCO2/year of which
approximately three quarters biogenic (there is a fraction of fossil-based material in the
waste). The total cost of BECCS was estimated to be approximately 90 Euro per tCO2
captured (Vattenfall, 2020) including transportation and geological storage in Norway.
The pulp and paper sector stands out among industries as it derives a large portion of the
energy required for its processes from biomass. Chemical pulp mills are globally the largest
33
source of large point sources of biogenic CO2 emissions, a statement which is also true for
the Nordic region (Rodrigues, et al., 2021). The biogenic CO2 emissions from pulp mills
using the Kraft process come mainly from the recovery boiler (chemicals are recovered
from lignin-rich black liquor) but also from lime kilns and any additional biomass boilers.
Post-combustion CO2 capture processes are applicable to all flue gas streams and can be
applied without modifications to the main production process.
The cost of CCS in Nordic pulp and paper mills has been estimated in a number of recent
studies (Skagestad, et al., 2015; Onarheim, et al., 2017; Garðarsdóttir, et al., 2018).
Summing the estimated cost of capture, transportation, and storage results in a range from
approximately 70-120 Euro per tCO2.
The pulp and paper producer Stora Enso investigated the possibility and cost of
implementation BECCS in its Skutskär (Sweden) kraft pulp mill (Stora Enso AB, 2020).
Both the recovery boiler and the lime kiln were considered. The study concluded that it is
possible to install a capturing and liquefaction plant with a capacity of 1 million tCO2
annually (all biogenic). The investment cost for capturing and liquefaction, including
intermediate storage, would be at 210-350 M Euro. That cost does not include investments
in equipment to produce necessary cooling and heating for the processes. The total cost for
CO2 capture, transportation and permanent storage is estimated to be within a range from
Euro 90 to 110 per tCO2.
CO2 transportation
4.4.2.1 Pipeline
The share of pipeline transportation in the total cost of a CCS project varies according to
the quantity transported as well as the diameter, length and materials used in building the
pipeline. Pipeline transport costs are dominated by capital cost (IEA GHG, 2020). Other
factors include labour cost and the planned lifetime of the system. Location and geography
are significant factors that affect the total cost as well (International Energy Agency, 2020).
In most cases, transport represents well under one-quarter of the total cost of CCS projects.
Pipelines located in remote and sparsely populated regions cost about 50-80% less than in
highly populated areas. Offshore pipelines can be 40-70% more expensive than the onshore
pipelines. There are strong economies of scale based on pipeline capacity, with unit costs
decreasing significantly with rising CO2 capacity.
IEA (2020) reports a range of cost estimates from USD 2-12/tCO2,250 km for onshore
pipelines and USD2-16 /tCO2,250 km for offshore pipelines.
4.4.2.2 Shipping
Shipping CO2 by sea may be viable for regional CCS clusters. In some instances, shipping
can compete with pipelines on cost, especially for long-distance transport, which might be
needed for countries with limited domestic storage resources. Contrary to the case of
pipeline transport, where the capital cost is the main driver, the operating costs make up
the bulk of total cost for shipping, the majority of which results from the liquefaction
process (Bui, et al., 2018). Shipping can thus be the cheapest option for long-distance
transport of small volumes of CO2 (up to around 2 Mt/year). This would be the case with
several early industrial CCS clusters across Europe and indeed for BECCS.
34
According to the IEA (2020) the shipping cost may be estimated to start at USD 20/tCO2
for short distances and slowly increase to between USD 25-30 for a transportation distance
of 1000 km.
4.4.2.3 CO2 storage
Generally, CO2 storage costs are expected to be low relative to CO2 capture. Current and
estimated CO2 storage costs vary significantly depending on the rate of CO2 injection and
the characteristics of the storage reservoirs, as well as the location of CO2 storage sites. The
cost of developing new sites, especially where CO2 storage has not been carried out before,
is uncertain, particularly with regard to the effect of reservoir properties and characteristics.
More than half of onshore storage in the United States is estimated to be below USD
10/tCO2, which would typically represent only a minor part of the overall cost of a CCS
project. Depleted oil and gas fields using existing wells are expected to be the cheapest
storage option. About half of offshore storage is estimated to be available at costs below
USD 35/tCO2. Similar cost curves are expected to apply in other regions, but further
research is needed to confirm this (International Energy Agency, 2020).
Cost reduction potentials
Research on technology learning rates suggests that the cost of CCS for power plant
applications is expected to fall as such installations are more widely deployed (Bui, et al.,
2018). This conclusion is consistent with analyses made by operators of the first two large-
scale CCS projects at coal-fired power plants, which project a roughly 20% cost reduction
for a subsequent CCS installation based on the experience to date (Bui, et al., 2018).The
magnitude of future cost reductions for power plants equipped with CCS will depend
strongly on the nature and timing of policy drivers to achieve GHG emission reductions.
Reducing the cost of CO2 capture has been the focus of a large amount of RD&D by private
and public research centres around the world in recent years. The main potential areas for
cutting both capital and operating costs include the use of innovative solvents,
standardisation of capture units, modularisation and off-site manufacture, reduced
contingencies, and better integration with the process plant, as well as increasing the size
of facilities in order to exploit economies of scale and learning-by-doing benefits. Cost
estimates for technologies at low TRLs are highly uncertain but generally, these
technologies have greater potential for cost reduction than mature technologies that are
well established in markets. Earlier-stage capture technologies, which could be deployed
10 to 20 years from now, could be 30% to 50% cheaper than current designs (International
Energy Agency, 2020).
CO2 transport by pipeline is a mature technology, with practical experience spanning
several decades, mostly in North America. The main scope for reducing costs is by
exploiting economies of scale through pooling of transport and storage demand. This can
be achieved by developing industrial clusters with shared infrastructure.
Experience with CO2 storage over the last decade has also grown but the site-specific nature
of geological storage makes it difficult to discern clear downward cost trends. CO2 transport
and storage are expected to benefit from technology innovation and digitalisation. The
largest cost reductions are likely to come from advanced sensing and real-time monitoring
technologies that allow for reduced downtime and early detection of CO2 migration or
leakage, due to improved tracking and predictive maintenance.
35
Smart drilling and developments in seismic analysis could also accelerate site appraisals
and reduce costs. The potential for cost reductions through innovation is greater for CO2
storage for which the costs of new projects are projected to fall by around 20-25% by 2040
(International Energy Agency, 2020).
Deployment barriers and knowledge gaps
The deployment of BECCS faces multiple barriers, some of which are intertwined. Below
is a summary of key deployment barriers identified through a literature survey as well as
related research needs.
Innovation and demonstration barriers
BECCS is still at demonstration or early commercialization stages of identifying and
overcoming technical problems - in particular, the loss of efficiency in the overall
conversion of fuel to useful energy (European Academies Science Advisory Council, 2018;
National Academies of Sciences, 2018; Bui, et al., 2018; International Energy Agency,
2020). Application of the most mature CO2 capture technologies to combined heat and
power plants or industrial facilities involves integration challenges. For BECCS more
generally, integrating the entire value chain from CO2 capture to geological storage needs
demonstration at large-scale (Johnsson & Kjärstad, 2019; Statens offentliga utredningar,
2020). In addition, less mature technologies offer opportunities for step-change cost
reduction but still requires significant development to reach commercialisation (Kearns, et
al., 2021).
Thus, a successful rollout of BECCS at scale towards the middle of this century requires
extensive RD&D efforts in the coming decade to enable the most suitable capture
technologies for different applications, to decrease technological uncertainty and to
minimize the cost per tonne of CO2. As there is a substantial risk that individual
technologies will not become viable or reach a mature stage, mitigation and absorption of
risks are critical and there is a need for governments to increase spending for these
technologies (Jeffery, et al., 2020; International Energy Agency, 2020). The development
of new technologies usually requires stable and predictable funding for an extended period
to prevent RD&D efforts being stranded before commercialisation.
High cost in combination with lack of financial incentives
High cost is one of the main barriers to widespread deployment of CCS and BECCS in
general. BECCS requires large up-front capital for investments and gives rise to operational
costs (for example energy and labour). Since negative emissions come with a cost it needs
to be incentivised by attributing negative emissions with an economic value (Burke, et al.,
2019; Zetterberg, et al., 2021). However, currently incentives for BECCS are weak.
As negative emissions lower the concentration of carbon dioxide in the atmosphere, the
world and its population may be seen to benefit. This viewpoint would be an argument for
financing negative emissions deployment through the public purse. However, state budgets
are limited, and it may be necessary to find alternative sources of funding, e.g. those
responsible for any emissions that remain would be responsible for financing negative
emissions, although also this funding source faces limitations as residual emissions reach
very low levels (Bednar, et al., 2019).
36
Infrastructure requirements
The CO2 transport and storage infrastructure required for BECCS (which is the same as for
CCS applied to fossil emissions) represents up-front costs too large to be borne by a handful
of BECCS projects and are particularly daunting for initial CO2 capture projects.
Irrespective of the mode of transport (i.e. ship or pipeline or a combination of these) a
national or regional CO2 transportation infrastructure would need to be capable of safely
handling millions of tonnes of captured CO2 annually. Planning and coordination of such
an infrastructure will involve overcoming significant barriers associated with risk and
uncertainty (IEAGHG, 2019). Planning, investment and development will eventually need
to be commenced independently of individual capture projects. Early groundwork would
include (Rootzen, et al., 2018):
• Feasibility and routing studies to dimension the infrastructure.
• Inventory of potential areas of national interests for CO2 infrastructure, e.g. harbours,
hubs, pipelines, intermediate storage (cf. existing dedicated areas of national interest for
energy production, wind power, energy distribution).
• Developing a strategy for ramping-up transportation and storage capacity over time.
• Long term signals and incentives for potential transport operators (that would own and
oversee the everyday operation of the transportation infrastructure).
Suitable sites for geological storage of CO2 need to fulfil several specific requirements,
such as overall storage potential, injection capacity, and the long-term integrity of the
geological formation. CO2 storage furthermore requires preparations of institutional
arrangements that would govern roles and responsibilities with regards to, for example,
access and costs for companies that demand transportation and storage services,
enforcement of monitoring and verification of the storage site, and long-term liability.
Public support for such infrastructure is generally considered important including
economic support and coordination of actors (European Academies Science Advisory
Council, 2018; IEAGHG, 2019; International Energy Agency, 2020). A potential role of
public sector institutions could be to form regional coalitions with common interest in
coordinating, constructing, operating and utilizing offshore storage sites and transport
infrastructure servicing industrial capture clusters and aggregating networks (Banks, et al.,
2017). Unless the transport and storage infrastructures are run by a public operator, separate
business cases are needed for each of these operations. Ultimately it is a political choice
what type of operation model to pursue.
Finally, for entities that may rely on other countries’ infrastructure to make use of carbon
capture and storage, not being captive to single operators with monopolistic market power
is in their interests (Levihn, et al., 2019).
Legal barriers
The London Convention and the London Protocol
8
are legally binding for all countries that
have ratified the convention. This includes the export of wastes or other matter for dumping
in the marine environment. In 2009 Parties to the London Protocol agreed on an
amendment to allow geological storage of CO2 in transboundary sub-seabed geological
formations – effectively allowing CO2 streams to be exported for CCS purposes (provided
that the protection standards of all other London Protocol requirements have been met).
8
Full name: The convention on the prevention of marine pollution by dumping of wastes and other matter
(“The London Convention”) and its 1996 protocol to the convention of the prevention of marine pollution by
dumping of wastes and other matter (“The London Protocol”).
37
The CO2 export amendment to the London Protocol has not come into force as not enough
parties have formally accepted the amendment. However, in 2019 a provisional application
of the amendment has been agreed pending bilateral agreements between the countries
concerned. Thus, bilateral agreements need to be in place until enough parties have ratified
the amendment.
Furthermore, the Helsinki convention
9
prohibits dumping of CO2 in the Baltic sea area and
the Kattegat. This means that an amendment to the convention is required to create legal
conditions for CO2 storage in this region.
The EU-ETS Directive specifically includes in the Annex I list the “transport of greenhouse
gases by pipelines for geological storage in a storage site permitted under the CCS
Directive”. The implication of this statement is that pipelines are the only permitted means
of transport for CO2 under the ETS scheme. This wording could mean that CO2 is excluded
from shipping under the ETS Directive. However, the barrier is not absolute since Member
States may apply emission allowance trading to activities and to greenhouse gases which
are not listed in Annex I. The EU MRV Regulations contain no specific provisions to
address ships transporting CO2, only the CO2 being emitted from the operations.
Consequently, how CO2 can be effectively and adequately monitored and verified under
the current regime is unclear (IEA GHG, 2020).
Accounting barriers
Accounting rules for BECCS need to be put in place that, inter alia, meet the need for
certainty of climate benefits, meet practical accuracy requirements for inclusion in national
inventories, and link policy incentives to tCO2 removed with measurement requirements
that are sufficiently precise (Grönkvist, et al., 2006; Torvanger, 2019; Vivid economics,
2019).
Accounting rules need to explicitly address reversal risks and in case of international
supply chains, the attribution of negative emissions between countries has to be handled.
Broader (environmental) externalities and risks
Although there is a large number of potential biomass feedstocks that can supply BECCS
facilities around the world, competition between different sectors for feedstock and
competition with other ecosystem services, such as food production, could significantly
limit their availability for BECCS (Bui, et al., 2018). Large-scale deployment of BECCS
will have implications for national land use patterns, create local environmental risks, and
raise concerns around the sustainability of large-scale biomass imports.
One way to avoid adverse side effect would be to limit biomass use to feedstock from
sustainably managed forests and/or to feedstocks that either would be wasted or is grown
in excess of what would have grown absent the demand for bioenergy (Rootzen, et al.,
2018), but this could significantly constrain the potential of BECCS.
Collective action dilemma
To pursue BECCS at scale, the different components of a carbon capture and storage value
chain would need to be developed (and incentivized through policy) jointly to avoid cross-
chain risks (i.e. where the basic problem essentially is ‘what comes first? The capturing of
CO2 or the infrastructure to transport and store it?’) (Elkerbout, et al., 2020 ). Investments
9
The Convention on the Protection of the Marine Environment of the Baltic Sea Area (“The Helsinki
Convention”).
38
in the interdependent components of the BECCS chain need to be coordinated. If one of
either capture, transport, or storage components of the BECCS chain is not moving ahead,
this risks the success of the entire value chain as operators will be reluctant to commit and
invest if others are not doing the same. In this regard, the challenge associated with BECCS
implementation exhibits some of the features that often characterize so-called “collective
action dilemmas” (Rootzen, et al., 2018).
Knowledge gaps
There are many challenges surrounding BECCS technologies that need to be resolved and
supported through R&D efforts. Below is a list of important topics based on Bui et al.
(2018) and Napp et al. (2018).
Biomass and land
•
Identify and implement use of sustainable/additional biomass feedstocks, e.g.
crops that need less fertiliser, grow in low quality soil, wastes/residues, 2nd
generation bioenergy crops, winter cover crops.
•
Identify BECCS pathways with a combined minimal water, carbon, energy and
land footprint, e.g. through careful selection of crops, location, cultivation
methods, pre-treatment and conversion technologies.
•
Improvement of pre-treatment processes to biomass (such as densification,
dehydration and pelletisation) to remove geographical limitations for biomass
supply, increase transport efficiency, reduce fossil fuel input and address
supply chain emissions.
•
Develop innovations in farming methods to increase crop yields and decrease
LUC emissions.
•
Assess and implement ways for freeing land, e.g. through crop yield increases,
food waste reduction and other demand side changes.
•
Develop supply chains for sustainable biomass.
Technical
•
Investigation of less mature BECCS technologies, like biomass gasification.
•
Assess how to deal with the high moisture content and specific impurities of
biomass during combustion/conversion, as they can lead to issues such as
corrosion, fouling and slagging.
•
Evaluate high shares of biomass co-firing, i.e. in excess of 20%, regarding their
implications for biomass pre-treatment and boiler modifications.
Economic
•
Quantify expected economies of scale for BECCS.
•
Identify the lowest cost BECCS pathways for every concerning sector.
•
Clarify direction and timings of financial BECCS projects returns.
39
Wetland restoration
Introduction
The term ‘wetland’ refers to a diverse range of shallow water and intertidal habitats, which
occur in various locations around the world. Wetlands are less extensive than forests and
grasslands. However, wetlands, including peatlands and coastal wetlands, e.g., mangroves,
are of great importance in terms of carbon sequestration because they contain the highest
carbon stocks per unit area of any ecosystem (Griscom, et al., 2017).
Draining and conversion of wetlands can lead to rapid rates of organic matter
decomposition and carbon loss rates. Restoring the wetland hydrology and perennial
vegetation can reverse the processes driving soil carbon losses and greatly reduce CO2
losses compared to drained organic soils and in many cases re-establish the carbon
sequestration capacity. Increased methane (CH4) emissions following rewetting can
however offset some of the mitigation impact.
Peatlands are wetlands that built up massive carbon-rich soils over hundreds or thousands
of years. The world’s 26 million hectares of drained peatlands is responsible for roughly 2
percent of annual human-caused GHG emissions (Wold Resources Institute, 2018). Their
conversion for agriculture and plantation forestry typically requires drainage, which causes
the soils to decompose and sometimes burn, releasing large quantities of carbon into the
atmosphere. Rewetting peatlands by blocking drainage ditches can typically eliminate
emissions. Peatlands appear to be far more extensive than previously thought, suggesting
high risk of further losses.
10
Coastal wetlands are extremely productive ecosystems; they act as long-term carbon sinks
by removing carbon from the atmosphere through photosynthesis and storing it in their
soils for long time periods. Compared to other ecosystems, coastal wetlands sequester a
very high amount of carbon per unit area (National Academies of Sciences, 2018).
According to Griscom et al. (2017) wetlands restoration has the potential to deliver
approximately 1.7 GtCO2e/year of GHG mitigation for a reference year in 2030 with equal
parts in coastal and terrestrial freshwater wetlands.
The IPCC Special Report on Land (2020) reaches similar conclusions, estimating coastal
wetlands restoration potential of 0.2-0.84 Gt CO2 equivalent (CO2e) per year, peatland
restoration of 0.15-0.8 Gt CO2-e per year
Mitigation principles
Wetland restoration relates to the rehabilitation of previously existing wetland functions
from a more impaired to a less impaired or unimpaired state of overall function. Wetland
functions can be restored by re-establishing wetland hydrology and/or reinitiating native
vegetation.
10
Researchers have recently discovered the world’s largest tropical peatland in the heart of the Congo
rainforest in central Africa. It stores an estimated 30 gigatons of carbon.
40
Freshwater peatlands
Peatlands are considered degraded when they’ve been drained or subjected to altered water
flow but have not been completely converted for other land uses. In this degraded state, the
carbon stored in plant material buried in peat soil is released into the atmosphere. Peatland
restoration involves restoring degraded/ damaged peatlands, which both increases carbon
sinks, but also avoids ongoing CO2 emissions from degraded peatlands.
While wetlands are known to sequester atmospheric carbon in soils and plants, they also
release CH4 and N2O. Restoration can lead to an increase in methane emissions, particularly
in nutrient rich fens, and the net GHG effect is uncertain (IPCC, 2020).
Dried peat is also susceptible to ground fires, releasing large amounts of stored carbon in
short order.
The primary method of restoration involves “re-wetting” or restoring the natural flow of
water and soil saturation.
Coastal wetlands
Coastal carbon sequestration refers to CO2 removal from the atmosphere in conjunction
with plant growth and the accumulation and burial of plant organic carbon (OC) residue in
the soil of tidal wetland and seagrass ecosystems. Tidal wetlands, including salt marshes
and mangroves, and seagrasses are among the most productive regions on Earth,
sequestering CO2 at a rate of 8 t/(ha,y) CO2 for tidal wetlands and 1.6 t/(ha,y) CO2 for
seagrass meadows (National Academies of Sciences, 2018). Scaled to their current global
areal extent, they are an important component of the global carbon cycle
Approaches for tidal wetland and seagrass ecosystem management that could contribute to
enforced carbon removal and reliable sequestration include:
•
Restoration of former wetlands,
•
Use of nature-based features in coastal resilience projects,
•
Managed migration as sea levels rise
•
Augmentation of engineered projects with carbon rich materials, and
•
Management to prevent expected future losses in carbon capacity.
Technological readiness
Methods for restoring degraded wetlands and peatlands are in use and ready for wider
adoption. Peatlands rewetting is already being implemented across Europe, as evidenced
by MoorFutures, MaxMoor, Peatland Code and other projects. A TRL 9 has been suggested
for Europe (Umweltbundesamt, 2021).
Although wetland restoration is under way in some regions, uncertainty regarding its
projected capacity for (net) carbon removal is significant (Reise, et al., 2022). Further
research is needed to more accurately quantify the impacts of these strategies on
atmospheric greenhouse‐gas emissions in different settings at landscape scales.
Barriers in the area of wetland restoration include mapping of global wetlands (particularly
peatlands, because peatlands cannot be identified from satellite imagery) and lack of
funding. Improved mapping is needed for both reducing uncertainties in estimating
mitigation potentials and for actually making use of potentials for restoration (Griscom, et
al., 2017; Wold Resources Institute, 2018).
41
Techno-economic analysis
Because the term ‘wetland’ refers to a diverse range of habitats, it is difficult to give
accurate cost estimates. Different types of wetland will require different restorative
measures with varying costs and labour requirements. A number of factors which are likely
to contribute toward variations in costs are given below (Tri, et al., 1998):
• Type of wetland to be restored, expertise availability, and consequent chances of
success.
• Degree of wetland degradation and consequent restoration requirements.
• Intended degree of restoration (for example, it may not be possible to restore all the
ecosystem functions of a wetland if it is located in a highly industrialised/urbanised
environment and the planned restoration measures may be less ambitious).
• Land costs if land purchase is required to convert to wetlands.
• Labour costs.
• Transportation distance between seedling source and planting site.
• Seedling mortality rate between collection and planting.
• Cost of raising specific species in nurseries before transplantation because they
cannot be directly planted on mud flats due to strong wind and wave forces.
• Scale of post-implementation monitoring operations.
The cost of individual projects should be calculated on a case-by-case basis.
Griscom et al., (2017) report cost estimates for wetland restoration which indicate a
significant CDR potential of up to 2 GtCO2e per year at a cost below USD 100 per tCO2e
including a low-cost potential (<10 USD/tCO2e) of 0.2 GtCO2e/year.
According to the Swedish Environmental Protection Agency restoration of wetlands is a
cost-effective GHG abatement measure (Swedish Environmental Protection Agency,
2019). Skogsstyrelsen provide a cost estimate of approximately USD 10/tCO2e.
11
This cost
estimate refers to the overall GHG abatement impact considering reduced emissions of CO2
and or N2O and increases in CH4 emissions.
Implementation barriers and knowledge gaps
Barriers in the area of wetland restoration include mapping of global wetlands (particularly
peatlands, because peatlands cannot be identified from satellite imagery) and lack of
funding. Improved mapping is needed for both reducing uncertainties in estimating
mitigation potentials and for actually making use of potentials for restoration (Griscom, et
al., 2017; Wold Resources Institute, 2018).
Methods for restoring degraded wetlands and peatlands are in use and ready for wider
adoption. Although wetland restoration is under way in some regions, uncertainty
regarding its projected capacity for (net) carbon removal renders it immature as a long-
term NET. Further research is needed to more accurately quantify the impacts of these
strategies on atmospheric greenhouse‐gas emissions in different settings at landscape
scales.
11
http://limnologerna.org/wp-content/uploads/2015/03/%C3%85terv%C3%A4tning-f%C3%B6r-klimatet-
Hillevi-Eriksson.pdf
42
43
Direct Air Carbon Capture and Storage
(DACCS)
Introduction
The direct CO2 capture from air includes the collection of CO2 from ambient air where the
CO2 concentration is much lower relative to CO2 concentrations from other sources like
flue gas and various industrial emissions. The collected CO2 then can be stored
permanently in deep geological formation. Other applications, that do not include CO2
storage are also considered, such as various industrial applications in the food processing
industries or the use of CO2 to produce synthetic fuels.
The technology employs solid or liquid medium that has an affinity to CO2. Since there is
dilute concentration of CO2 in atmosphere, chemical sorbents are required that have strong
binding characteristics. Such sorbents, i.e., solid sorbents, offer new systems with low
pressure drops that are like ‘honeycomb’ structure of monoliths which are widely used as
automobile catalytic converters (Realff & Eisenberger, 2012; Wang, et al., 2011).
DAC technology
Currently, there are two main approaches under development to capture CO2 from air.
These approaches include: (i) liquid-based solvent systems, and (ii) solid-based sorbent
systems.
Liquid-based Solvent Systems
The liquid absorption system uses strong base solutions, e.g., sodium hydroxide (NaOH)
solution, potassium hydroxide (KOH) solution etc. Two main units are employed for liquid
solvent direct air capture, (i) contactor, and (ii) regenerator (see Figure 11).
In the air contactor, the solution of KOH reacts with the CO2 from the air to form water
and potassium carbonate (K2CO3):
2KOH + CO2 → H2O + K2CO3
The ambient air is introduced to the contactor at 400 ppm and then leaves with about 75%
CO2 captured in the solvent as potassium carbonate. The potassium carbonate is then
causticized with Ca(OH)2 in the regeneration step to form calcium carbonate CaCO3 and
the KOH solution that is further reused in the air contactor.
44
H2O + K2CO3 + Ca(OH)2 → 2KOH + CaCO3
Figure 12shows a CO2 direct air capture system based on the aqueous solution of sodium
hydroxide (NaOH). During the first cycle which is known as absorption, the ambient air is
brought in contact with NaOH (solvent) as room temperature and ambient pressure. The
solution is then brought to the regeneration cycle where CO2 depleted air is separated.
Within the second cycle, the regeneration of NaOH is performed where sodium carbonate
is mixed with calcium hydroxide in the causticizer. The following reactions takes place in
the two cycles.
2NaOH + CO2 → Na2CO3 + H2O
Na2CO3 + Ca (OH)2 → 2NaOH + CaCO3
CaCO3 + heat → CaO + CO2
CaO + H2O → Ca (OH)2
Figure 11. Simplified process description of liquid-solvent based direct air capture (National Academies of Sciences, 2018).
45
A typical liquid-solvent configuration requires a total of about 0.74-1.66 GJ/tCO2 for
electricity and about 9.18-12.18 GJ/tCO2 for thermal energy (National Academies of
Sciences, 2018). This means that about 6-18% of the entire energy demand comes from the
electricity consuming process steps. The electricity demand includes requirements for fans,
pumps, slake, causticizer and air separation units. The heat demands in the heater/dryer and
calciner represents the overall thermal requirements. The most thermal-intensive process
is the thermal regeneration of calcium oxide (CaO) and subsequent highly pure CO2
production.
Solid Sorbent Systems
The solid sorbent systems consist of two main process steps, (i) adsorption, and (ii)
desorption. See Figure 13. In the adsorption unit, air is blown through a suitable CO2-
sorbent where the CO2 present in the air is selectively adsorbed over the sorbent surface.
The major energy consumer in this step is the electrical energy required for fans to blow
the air through the contactor that holds the sorbent. The primary driving force in relation
to energy demand is the substantial pressure drop.
To regenerate the sorbent, the saturated solid sorbent with CO2 is heated to liberate CO2
from the sorbent which is then reused in the adsorption unit. The regeneration step is
considered as the most energy-intensive step in a solid sorbent direct air capture system,
i.e., thermal energy required for CO2 desorption, heating up the sorbent, contactor, and
other equipment together with electrical energy demand in terms of vacuum pumps (if
utilized). For an efficient solid sorbent system, the process design aims to minimize the air
pressure drop through the solvent contactor, maximize the CO2 adsorption with minimum
sorbent mass, and manage the water uptake (Sinha, et al., 2017).
Figure 12. liquid-solvent based direct air capture using sodium hydroxide (Fasihi, 2019).
46
Figure 13. A simple low temperature sorbent-based direct capture system (Fasihi, et al., 2019).
Technological readiness
Following is an overview of existing or planned facilities that demonstrate direct air capture
technologies developed globally:
-
Climeworks has a new large-scale CO
2
removal plant that is operational in
Iceland. The plant uses geothermal energy and has eight collector containers
with an annual capacity of 500 tons each. The capture capacity is up to 4000
tons of CO
2
per year (Climeworks, 2021).
-
Carbon Engineering’s demonstration plant at Squamish (Canada) that is used
for ‘Air-to-Fuels’ using natural gas as the energy supply. The demonstration
plant (Absorption and calcination) has a CO
2
capture capacity of 0.6 t/day (219
t/year) and fuel production capacity of 48 t/year (Keith, et al., 2018; Holmes
& Keith, 2012).
-
Commercial DAC plant in Hinwil (Switzerland) is used for greenhouses and
uses waste heat from an incinerator. The plant has a CO
2
capture capacity of
2.46 t/day (about 900 t/year) (Viebahn, et al., 2019).
-
A pilot facility at Turin (Italy) that is used for ‘Power-to-Chemicals’. The pilot
plant has a capacity of 0.016 t/day (5.8 t/year) of CO
2
capture.
47
-
A Hydrocell’s pilot plant in Finland that is used for ‘Power-to-Liquids’ and
later can be used for ‘Power-to-Chemicals’. The facility has a CO
2
capture
capacity of 0.0038 t/day (about 1.39 t/year) and a fuel production capacity of
22 t/year (Vazquez, et al., 2018).
-
A pilot facility of ZSW at Stuttgart (Germany) that has a CO
2
capture capacity
of 0.0047 t/day (about 0.017 t/year) (Viebahn, et al., 2019).
It is important to note that the TRL indications vary considerably depending on the
literature source and depending on the given technological approach.
The TRLs vary significantly based on different sorbents (Napp, et al., 2017; Lomax, et al.,
2015; Royal Society, 2018; Schmidt, et al., 2016; Viebahn, et al., 2019).
-
TRLs of 3-4 for the systems using hydroxide solutions that are employed in
the absorption and electrodialysis system that use dissolved inorganic
compounds.
-
TRLs of 3-4 for the systems using hydroxide solutions that are employed in
the absorption and calcination that use dissolved inorganic compounds.
-
TRLs of 2-4 to amine-based adsorption and desorption systems.
-
Recent studies (Royal Society, 2018; International Energy Agency, 2020)
classify the systems using absorption and desorption (binding to solids) with a
TRL of 5-6.
-
Schmidt et al., (2016) classify the absorption and desorption system with a
TRL of 6 due to the development and the demonstration of prototypes.
-
Climeworks classify its system of adsorption and desorption technology at
TRL 9, given current costs (Viebahn, et al., 2019).
Techno-economic analysis
DAC captures CO2 from the ambient air with a CO2 concentration around 410 parts per
million (ppm), or 0.041%. This is significantly lower than for CCS processes in power
plants or industrial facilities where CO2 concentrations are in the range or 0.041% 3–30%.
The low concentration of CO2 in air has important implications on the techno-economic
feasibility of DAC plants as it results in high energy requirements and large “capturing”
areas are necessary.
A wide range, from 300-820 USD/tCO2, of cost estimates for solvent-based direct air
capture have been reported in the literature (IEA GHG, 2021). The large spread is partly
explained by dissimilar system boundaries and the absence of normalising conditions. The
cost estimates may reflect the overall cost for the removal of 1 tonne CO2 from the air on
a basis of 1 tonne CO2 captured. In all cases, it is important to clearly distinguish between
the cost of CO2 captured and the cost of CO2 removed, due to the impact of indirect
emissions (associated with the significant energy demand) on the cost of net CO2 removed.
48
Table 4 reports cost for solid sorbent-based direct air capture system depending on the
energy sources.
Table 4. Estimated costs for CO2 captured and net CO2 removed using sor bent-based direct air capture (adapted
from National Academies of Sciences, Engineering, and Medicine, 201 8).
Energy source
Capture cost
(USD/t CO2)
Electricity
Heat
CO2 captured
Net CO2 removed
Solar
Nuclear
Solar
Wind
Natural gas
Coal
Solar
Nuclear
NG
NG
NG
Coal
88-228
88-228
88-228
88-228
88-228
88-228
89–256
89–250
113–326
113–226
124–407
166–877
IEAGH (2021) converted recent Climeworks cost estimates for DAC installation, 600–700
USD/tCO2,captured on a “gross CO2 removed”, to the cost of CO2 removed assuming energy
supply from a natural gas fired plant, resulting in costs in the range 1100-1500 USD/t
CO2,removed. These estimates exclude the cost of compression, transportation and storage.
Hence, the supply of low-carbon energy is an important prerequisite for the techno-
economic feasibility of DAC systems.
According to IEAGHG (IEAGHG, 2021b) first-of-a-kind DACCS projects are likely to
range from approximately 400-700 USD/net-tCO2, when global average solar
photovoltaics costs are used, or 350-550 USD/net-tCO2, when lowest-cost renewables are
used. The study proposes that significant cost reduction can be achieved for nth-of-a-kind
DACCS plants, reaching around 200-230 USD/net-tCO2 for 1 MtCO2/year scale, driven by
reduced electricity prices, cost of capital and upfront capital investment. Costs in the range
of 150-200 USD/net-tCO2 may be achieved if very low-cost solar energy is used.
In a study, Fasihi (2019) reported the levelized cost of DAC and projected the cost figures
for 2050 to $60-$79/t CO2 when using absorption and calcination-based DAC system. For
an absorption and electrodialysis system, the costs are in the range of $42-$60/t CO2.
Deployment barriers and knowledge gaps
Land use
Another key issue to commercial implementation of direct air capture systems is footprint
and the respective land usage as a substantial land demand can be barrier for the successful
deployment. An aqueous based direct air capture system with a capacity of 1 Mt CO2/a
requires a total area of 1.5 km2 that results in a footprint of about 1.5 km2 per Mt CO2
(Socolow, et al., 2011).
49
Climeworks capture facility has tried to reduce the land use and offers a maximum vertical
expansion of their system but still the overall footprint of Climeworks system is about 3300
km2 to capture 8 Gt CO2 per annum (Viebahn, et al., 2019).
However, a comprehensive study by Johnston et al., 2003 showed that the local CO2
depletion could be in the range of natural CO2 flections and may not have a large impact
on the DAC implementation. A potential solution is to spread large DAC system into
smaller units across different regions to avoid CO2 shadows among each other. Keith et al.
(2006) conclude that the direct area demand could be reduced by effectively using the land
between the units.
Water requirements
The aqueous-based DAC system requires considerable amount of water and the water loss
in the process could be in the range of 0-50 tons per ton of CO2 captured (Keith, et al.,
2006; Zeman, 2007). The amount of water loss could depend on the temperature and
humidity of the ambient air and on the concentration of the solution.
It is important to note that the DAC deployment will highly depend on water availability
in water stress regions that will result in higher costs by using water desalination together
with transportation costs, e.g., $3 - $9 per cubic meters (Caldera, et al., 2016). According
to Keith et al. (2018), the Carbon Engineering design may require about 4.7 tons of water
to capture 1 ton of CO2.
On the other hand, Climeworks DAC design has potential to capture water as a by-product,
e.g. 2-5 mol of water per mol of CO2 captured that is equivalent to about 0.8-2 tons of water
capture per ton of CO2 capture (Viebahn, et al., 2019). In addition, Hydrocell’s system can
also produce about 4.6 mol of water per mol of CO2 capture when the system is operated
in the Finnish climate (Vazquez, et al., 2018).
Thus, the water requirement may be a constraint in water stress regions but may not offer
a significant barrier to deployment in other regions as it may provide water needed for other
processes like electrolysis process in Power-to-Fuel and Power-to-Chemical systems
(Fasihi, et al., 2017).
50
Accelerated Mineralization (AM)
Introduction to the concept
Accelerated mineralization is a process where CO2 is reacted with metal cations, e.g.,
magnesium, calcium, and iron, to form mineral carbonates. The accelerated mineralization
is a promising technique because the generated CO2 from fossil fuels can be directly fixed
as carbonates of magnesium and calcium. The process is safe and stable for significantly
long period of times since carbonates are naturally occurring minerals and shows very low
energy of formations.
Accelerated Mineralisation technology
There are two main categories of mineralization: (i) in situ mineralization, and (ii) ex situ
mineralization.
In situ mineralization is a geological sequestration where CO2 is injected below ground
and reacted with alkaline minerals to form solid carbonates.
Ex situ mineralization is a process where the carbonation reactions are performed in a
controlled reactor or in an industrial process above the ground.
In both, In situ and Ex situ mineralization, the idea is to achieve a similar process of natural
weathering where the carbonates of magnesium and carbonates are formed from the
calcium and magnesium silicates that react with CO2 (IEAGHG, 2013). See following
chemical reactions:
(Ca, Mg) SiO3 (s) + CO2 (g) → (Ca, Mg) CO3 (s) + SiO2 (s)
In this report, the ex-situ accelerated mineralization as a potential option for carbon dioxide
sequestration is studied. Sanna et al., (2014) has shown some specific reactions within the
accelerated mineralization process using minerals like wollastonite, olivine, brucite etc.:
Wollastonite CaSiO3 + CO2 → CaCO3
Olivine Mg2SiO4 + 2CO2 → 2MgCO3 + SiO2
Pyroxenes CaMgSi2O6 + 2CO2 → CaMg(CO3)2 + 2SiO2
Serpentine polytypes Mg3Si2O5(OH)4 + 3CO2 → 3MgCO3 + 2SiO2 + 2H2O
Brucite Mg(OH)2 + CO2 → MgCO3 + H2O
Apart from natural ores, alkaline wastes are also considered to be suitable alternatives
reactants in the carbonation process since the alkaline wastes are cheap and widely
51
available from the industrial CO2 emission points. Figure 14 shows an integrated
mineralization process together with waste utilization.
Figure 14. Integrated carbonation process with waste utilization (Pan, et al., 2015).
Among industrial wastes for the accelerated mineralization, the municipal incinerator ash
is a promising raw material. The bottom ash from the municipal solid waste (MSW)
incineration accounts for 20-30% by mass of the original waste and tends to have a bit
lower CaO and higher SiO2 content in comparison with the fly ash (Romanov, et al., 2015).
Another alternative is combustion fly ash where the mineral carbonation depends on the
dissolution of CO2 in the liquid phase, mobilization of Ca and Mg ions and precipitation of
carbonate solids (Bauer, et al., 2011). The average CO2 absorption is 5.5 g CO2 per 100 g
of ash at temperature of 35oC. Ukwattage et al. (2013) reports that increase in pressure
results in increase in carbonation rate for alkaline fly ash.
Steelmaking slag is another raw material for the accelerated mineralization that accounts
for about 25-55 wt.% of CaO (Romanov, et al., 2015). A study by Perez-Lopez et al. (2008)
shows the potential of alkaline paper mill waste and estimated that about 218 t CO2 in
calcite form could be sequestrated through 1 tonne of the alkaline paper mill waste that
contains 55 wt.% of portlandite (Ca (OH)2). Table 5 reports potential waste streams that
are suitable for the accelerated mineralization.
52
Table 5. Potential waste streams for AM (Wilcox, 2012).
Relevant Industry
Potential Alkaline waste
Cement industry
Cement bypass dust, cement kiln dust
Coal combustion
Fly ash
Steel Industry
Steel slag, furnace slag
Waste-fuelled power plants
MSW ash and air pollution control residues
Wastewater treatment plants
Sludge from water treatment
Mining industry
Mine tailings
Construction industry
Mineral waste (concrete)
Technological readiness
It is clear from the literature survey that most of the studies on accelerated mineralization
are performed on lab-scale where the reaction conditions for the carbonation reactions are
studied. However, there is lack of knowledge on the utilization and end-of-life processing
of carbonation products. The implementation of CO2 mineralization using the industrial
solid wastes is in the experimental stage, but a few research institutes and companies have
demonstrated pilot facilities.
A very recent study by Meng et al. (2021) shows the progress of technology readiness level
(TRL) of accelerated CO2 mineralization during 2011- 2020 and then projected the
advancement of the technology till 2030 where the technology will reach a TRL of 8-9
(Fel! Hittar inte referenskälla.). Currently, there are lab-scale demonstration of the CO2
mineralization resulting a TRL of 5-6.
Figure 15. Projected TRL of accelerated mineralization with reference case in China (Meng, et al., 2021).
53
Another study by Alberici et al., (2017) shows the TRL of the carbonation technology in
the range of 4-8. The SkyMine process resulted from the SkyMine® Carbon Mineralization
Pilot Project shows a TRL of 6-7 (Alberici, et al., 2017).
There are few facilities that have been developed in the recent past:
Carbon8: is a company in the United Kingdom that claims to achieve a TRL 8 of their
accelerated carbonation technology (ACT). The company operates two ACT plants in UK
and each facility treats about 30-40 kt per year of Air pollution control residues. The
company’s plants can collectively use about 5 kt CO2 per annum. Their process
manufactures lightweight materials as construction materials. As per current developments
of ACT, Carbon8’s technology is expected to reach a TRL 9 by 2030 (Alberici, et al.,
2017).
Skyonic: is a US company that is developing SkyMine technology which mineralises flue
gas into carbonates. Skyonic is operating a demonstration plant in San Antonio (Texas)
that has potential to capture 83 kt CO2 per year and has a capacity to produce 160 kt of
sodium carbonate per year (Alberici, et al., 2017).
Carbon Clean Solutions: is a UK company which has built a pilot plant in Chennai (India)
to capture about 60 kt CO2 per year (Carbon capture journal, 2016). The facility is
integrated with a 10 MW coal-fired power plant. The captured CO2 is utilized to produce
sodium carbonate (soda ash).
Twence BV: is operating a pilot-scale facility to demonstrate the AM and captures about 2
kt CO2 per year from the flue gas of a waste-fuelled power plant (Twence, 2021). The
captured CO2 is used to manufacture sodium bicarbonate (NaHCO3). In future, the
company is expecting to capture 50-200 kt CO2 per annum (Alberici, et al., 2017).
Cambridge Carbon Capture: is a UK company which is working on the low energy
digestion of silicate minerals with sodium hydroxide and to produce a relatively cheaper
magnesium hydroxide (MgOH2) for the carbon capture stage. The Mg (OH)2 is then reacts
with CO2 to produce magnesium carbonate (MgCO3). The technology developed by
Cambridge Carbon Capture is at lab-scale (Cambridge Carbon Capture, 2021). Their
technology is at a lower TRL level.
Techno-economic analysis
The accelerated mineralization could play an important role for CO2 reduction in the
industrial sector by efficiently using the industrial wastes. However, there are important
issues related to the market competitiveness and global nature of relevant industries that
must be addressed. There are associated energy and cost penalties in relation to plant scale-
up, operating conditions and the requirements of pre-treatment processes such as grinding
and thermal activation coupled with post-treatment processes like separation of required
products and waste disposal (Pan, et al., 2012). Based on the lack of commercial plant
investigations, the techno-economic analysis is roughly based on either lab or pilot scale
studies.
54
According to a study from Sanna et al. (2014), the costs of indirect carbonation through
chemical extraction but without chemicals regeneration are very high, e.g. $600–$4500 to
capture one tonne of CO2. Since the costs do not include the chemical regeneration, this
means the chemical regeneration could generate 2-2.5 times more CO2 than CO2 fixation
during the carbonation (Teir, et al., 2009).
The literature shows the cost of Ex situ mineralization in the range of $54–$133 to capture
one tonne of CO2. But this cost is highly dependent on the type of the raw material and the
operational modulus (Yu, et al., 2012). A study by Gislason and Oelkers (2014) shows an
overall cost of In situ mineralization in the range of $72–$129/t CO2. The cost estimation
includes a transportation and storage costs of $17/t CO2.
Table 6 shows a summary of costs related to ex situ accelerated mineralization when using
different feedstocks and processes.
Table 6. Estimated costs and energy demand of the direct accelerated carbonation
Feedstock
Process
Costa
($/t CO2)
Reference
Wollastonite
Wollastonite
Olivine
Serpentine
Mix waste
Pre-treatment (grinding
to 38-75μm)
Lab-autoclave reactor
Pre-treatment (grinding
to 38-75μm)
Thermal heat
Lab-scale spraying gas
chamber
91
133
54-55
70
8
Gerdemann et al., 2007
Huijgen et al., 2007
Gerdemann et al., 2007
Rayson et al., 2008
Stolaroff et al., 2005
aSome costs have been converted to USD.
Deployment barriers and knowledge gaps
Availability of raw materials/waste resources
One of the major long-term concerns for the commercialization of accelerated
mineralization is the availability of sufficient amounts of mineral ores and waste materials,
e.g., availability issues due to the potential decline in the coal-based power plants and the
steel manufacturing in Europe. This decline means that there will be less waste available
for the accelerated carbonation but except for the air pollution control residues which are
55
projected to increase in future. The projected growth in the availability of such residues is
mainly due to the commissioning of more and more waste-to-energy facilities but the
amounts of air pollution control residues are relatively much smaller in comparison with
other waste streams. Despite the decline in resources, the historical waste deposits could
offer potential sources that can be effectively utilized.
Accelerated mineralization faces major limitations in terms of scalability and associated
costs due to high demand of minerals. For example, 2-3 tonnes of silicate mineral are
required in the carbonation reaction to sequester about 1 tonne of CO2 (Royal Society,
2018). This means about 10 Gt of rock per year will be required to sequester about 3.7 Gt
of CO2 per year. Silicate minerals are the primary raw materials in case of ex situ
mineralization together with sufficient energy supply. The energy demands in the
accelerated mineralization varies significantly and is in the range of 1.5 – 8.8 GJ/t CO2
(Gerdeman, et al., 2007). It is interesting to note that in case of full life cycle considered,
there is potential GHG emissions in the range of 0.5-1.1 tCO2 per tCO2 potentially removed
(Cuellar-Franca & Azapagic, 2015).
To reduce the energy demands in this process, the utilization of pre-ground materials like
wastes from various industries can offer a viable solution by eliminating the energy costs
related to material grinding and additional mining.
Legal
Another barrier to the accelerated mineralization with using waste resources is the
requirement to meet the EU End of Waste Regulations. According to the study by Alberici
et al. (2017), an approval would be required in case the plant capacity is over 30 kt/year
that will result in prolonged waiting times for the approvals. In addition, the carbonation
materials produced using waste resources will be required to meet the EU End of Waste
Regulations before the products could be sold to the market. As per Ecofys and Imperial
college (2016), it is not allowed to sell and market products made from various waste
resources and such materials are regulated by the Environment Agency.
Possible leaching of heavy metals
Another potential barrier is the conservative nature of the building sector that may not be
able to utilize the carbonation materials unless there is an established data available related
to the reliability and safety of the carbonation materials. For example, the carbonation
material produced from the air pollution control residues may contain relatively high traces
of heavy metals and there could be issues due to the possible leaching of such heavy metals
(Alberici, et al., 2017). This challenge can inhibit the market to adapt the carbonation
materials.
To address such issues and to warrant long-term reliability and performance of carbonation
materials, more research is needed related to the engineering properties coupled with the
characteristics of carbonation materials. From a policy perspective, it is important to
support high taxes on landfills to encourage the use of waste streams in the accelerated
mineralization process but to conduct more research to demonstrate the long-term
performance, reliability of carbonation materials and safety in terms of potential leaching.
Environmental challenges
The increase in the mining activity (especially for ex situ mineralization) and injection
activities (for in situ mineralization) could result in environmental issues and challenges.
56
There is no comprehensive study, e.g., LCA, to show detailed data on net CO2 removal
when using in situ mineralization but the results from CarbFix project demonstrates more
than 95% removal of CO2 when injecting into Icelandic basalts (Royal Society, 2018).
However, in case of ex situ mineralization, the studies are performed to show the
competitiveness of the technology where the waste streams can be converted into products
such as aggregates. Such products can readily be measured, and less monitoring would be
needed in case the stable products are formed.
Social and Policy factor
The accelerated mineralization through ex-situ carbonation could create environmental
impacts in terms of huge mineral requirements and associated scale of mining. Gerdemann
et al. (2007) estimated that approximately 5 times as much ore as coal must be mined to
sequester all the CO2 generated by the combustion of that coal (assuming complete
conversion). Opening new mines to meet the increased demands of required minerals
would likely meet the opposition from the public (Royal Society, 2018).
Other challenges and impacts
- Generation of possible harmful by-products such as hydrochloric acid
- Drawback related to surface impacts, e.g., noise and traffic, as well as the
disturbances caused during the mining operations
- Use of non-renewable energy to meet increased energy demands of ex-situ
carbonation process
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Summary and conclusions
An analysis of technology readiness, costs and deployment barriers for the NETs BECCS;
Biochar as soil additive; Wetland Restoration; DACCS; and Accelerated Mineralization
has been carried out and is presented in this report. Below, the principles of each NET is
first summarised and, thereafter, conclusions regarding TRL, costs and practical
implementation hurdles are presented in sections 8.6-8.8.
Biochar as soil additive
Biochar constitutes the solid remains of biomass that has been heated to temperatures
typically between 300 ˚C and 800 ˚C under oxygen-depleted conditions. The primary
technology for biochar is pyrolysis. Production technologies also include gasification,
which has significantly lower biochar yields, and hydrothermal carbonisation, which
produces biochar (or “hydrochar”) from feedstock with very high moisture content.
Pyrolysis generally has biochar yields in the range of 30% as compared to gasification
where the yield is typically 10% or less.
Organic materials fundamentally change their chemical composition through such
thermochemical conversion and are then dominated by aromatic carbon forms. This is in
contrast to the original biomass feedstock that mainly contains cellulose, hemicellulose,
and lignin. The creation of biochar from biomass places C into a recalcitrant form which is
suitable for the safe and long-term storage of carbon in soils.
For any given feedstock it is possible to vary the product distribution between char, liquid
and gas, within limits, by choice of feedstock pre-treatment and process type and operating
conditions. Higher char yields are obtained by slow pyrolysis processes with lower
temperatures and low flow rates; higher liquid yields arise from fast pyrolysis processes,
specific temperatures and high flow rates. In general, biochars produced at lower pyrolysis
temperatures have a more diversified organic structural makeup because there is less loss
of volatile compounds. These biochars are potentially more amenable as soil amendments
for improving soil microbial properties and increasing soil cation-exchange capacities.
High-temperature biochars have higher amounts of carbon in aromatic structures which
makes them more recalcitrant to soil microbial oxidation, with longer half-lives and, thus,
a more appropriate selection for increasing long-term carbon storage.
The combined production of biochar and application to soil has the potential to bring one
or more of the following overlapping and interlinked benefits:
•
Reduce atmospheric GHG concentrations through CO
2
removal and avoided
GHG
•
Improve the structure, properties and ‘health’ of soils;
•
Increase crop productivity;
•
Provide energy (e.g. electricity from syngas, heat from syngas and bio-oil or
liquid fuel);
•
Safely dispose of certain waste materials with potentially useful recovered by-
products;
•
Absorb pollutants, contaminants and reduce nitrate leaching to water courses;
•
Suppress soil emissions of nitrous oxide and methane.
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BECCS
The application of CO2 capture and permanent geological storage to CO2 from sustainably
sourced biomass would lead to negative emissions. The entire value chain consists of
biomass production, CO2 sepatation in connection with larg-scale biomass conversion and
the supsequent CO2 compression or liquefation (depending on mode of transport),
transportation of compressed or liquefied CO2 to the storage site and final storage by
injection into a deep underground geologic reservoir. Biomass production and harvesting
exists in commercial operation throught the world. Technologies for CO2 capture from gas
streams is well established in some applications. Post-combustion capture using chemical
solvents is a mature capture technology and the processes involved have been applied in
some industrial applications for several decades. Several CO2 transportation options are
technically and commercially viable including shipping, pipeline, freight train, and trucks.
The injection and permanent geological storage of CO2 is technically feasible which has
been demonstrated through a number of industrial scale projects.
Pre-combustion and oxyfuel capture technologies can bring lower energy penalties and
reduced incremental cost compared to post-combustion capture, but are less mature. Post-
combustion capture technologies are, in addition, generally more suited to retrofitting than
pre-combustion and oxyfuel capture as there is less need for fundamental overhauls in
combustion equipment.
In total there were 26 commercial CCS projects in operation around the world in 2020 with
a total capture capacity of around 40 million tonnes CO2 per year. The vast majority of
existing project use the captured CO2 for enhanced oil recovery (EOR). Most of the projects
are in natural gas processing applications using chemical solvents, but a growing number
are in other sectors. There are two power plants in the world that have been equipped with
CCS both of which apply post-combustion capture using chemical solvents.
12
Biogenic CO2 is captured in a number of projects world-wide. Most of the existing projects
are in the ethanol sector which can be considered ”low-hanging fruit” due to low
incremental capture cost. In many of the cases where biogenic CO2 is captured, the CO2 is
used for productive purposes rather than permanently stored, thus not generating CDR.
There are currently five projects world wide that can be described as BECCS, meaning that
biogenic CO2 is captured and stored. Four out of the five BECCS projects store the captured
CO2 in EOR applications. A handful of BECCS projects in power and CHP applications
are in the planning stage with planned commissioning from 2026 and onwards.
Although individual technologies along the BECCS value chain are mature, integrating the
entire value chain at large scale needs demonstration. Developing BECCS at scale,
including multiple projects, would require careful planning of transport and storage
infrastructure to evolve over time in sync with the ramping up of the capture of biogenic
and fossil CO2. On the more technical side, application of CO2 capture technologies to
12
One of the two projects has been temporarily suspended due to low oil prices leading to reduced incentives
for EOR.
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combined heat and power plants in industrial facilities or coupled to district heating
involves additional integration challenges compared to the vast majority of currently
existing biogenic CO2 capture projects in the ethanol sector.
Wetland restoration
The term ‘wetland’ refers to a diverse range of shallow water and intertidal habitats, which
occur in various locations around the world. Wetlands, including peatlands and coastal
wetlands, e.g., mangroves, contain the highest carbon stocks per unit area of any
ecosystem. While draining and conversion of wetlands can lead to rapid rates of carbon
loss rates, their restoration can greatly reduce CO2 losses compared to drained organic soils
and in many cases re-establish the carbon sequestration capacity. Increased methane (CH4)
emissions following rewetting can however offset some of the mitigation impact. Dried
peat is also susceptible to ground fires, releasing large amounts of stored carbon.
Wetland restoration relates to the rehabilitation of previously existing wetland functions
from a more impaired to a less impaired or unimpaired state of overall function. Wetland
functions can be restored by re-establishing wetland hydrology and/or reinitiating native
vegetation.
Barriers in the area of wetland restoration include mapping of global wetlands (particularly
peatlands, because peatlands cannot be identified from satellite imagery) and lack of
funding. Improved mapping is needed for both reducing uncertainties in estimating
mitigation potentials and for actually making use of potentials for restoration.
Methods for restoring degraded wetlands and peatlands are in use and ready for wider
adoption. Although wetland restoration is under way in some regions, uncertainty
regarding its projected capacity for (net) carbon removal renders it immature as a long-
term NET. Further research is needed to more accurately quantify the impacts of these
strategies on atmospheric greenhouse‐gas emissions in different settings at landscape
scales.
DACCS
Direct air CO2 capture uses chemical reactions to capture CO2 directly from the atmosphere.
When air moves over these chemicals, they selectively react with and remove CO2,
allowing the other components of air to pass through. These chemicals can take the form
of either liquid solvents or solid sorbents in the two types of DAC approaches currently
under development: (i) liquid-based solvent systems, and (ii) solid-based sorbent systems.
Once the carbon dioxide is captured from the atmosphere, heat is typically applied to
release it from the solvent or sorbent. Doing so regenerates the solvent or sorbent for further
use for CO2 capture. The DACCS value chain is completed by injecting the captured CO2
into deep underground geologic formations for permanent storage.
For liquid solvent DAC, two main units are employed, (i) contactor, and (ii) regenerator.
The ambient air is introduced to the contactor at 400 ppm and then leaves with CO2
captured in the solvent. The absorbent is then regenerated in the regenerator for further
reuse in the air contactor.
The solid sorbent DAC systems consist of two main process steps, (i) adsorption, and (ii)
desorption. In the adsorption unit, air is blown through a suitable CO2 sorbent where the
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CO2 present in the air is selectively adsorbed over the sorbent surface. To regenerate the
sorbent, the saturated solid sorbent with CO2 is heated to liberate CO2 from the sorbent
which is then reused in the adsorption unit.
Both the solid sorbent and liquid solvent DAC approaches require roughly 80% thermal
energy and 20% electricity for operation. In both approaches, the thermal energy demand
results from the regeneration steps. For both approaches, electricity is required for
contactor fans to overcome system pressure drop. In the solid sorbent approach, the another
source of electricity consumption is for vacuum pumps, which remove residual air in the
regeneration part of the process. The liquid solvent system requires electricity for pellet
reactors, steam slaker and filtration units.
The two approaches have quite different temperature requirements, which impacts the
types of energy required to operate them. Solid sorbent systems require 80 degrees C to
120 degrees, whereas liquid solvent systems require 900 degrees C. This means that solid
sorbent systems can use lower-grade residual heat.
Accelerated mineralization
Accelerated mineralization is a process where CO2 is reacted with metal cations, e.g.,
magnesium, calcium, and iron, to form mineral carbonates. This involves fixing CO2
directly as carbonates. The process is safe and stable for significantly long periods of time.
Carbonates are naturally occurring minerals showing very low energy of formations.
There are two main categories of mineralization: (i) in situ mineralization, and (ii) ex situ
mineralization. In situ mineralization is a geological sequestration where CO2 is injected
below ground and reacted with alkaline minerals to form solid carbonates. Ex situ
mineralization is a process where the carbonation reactions are performed in a controlled
reactor or in an industrial process above the ground. In either case, the idea is to achieve a
similar process of natural weathering.
In this report, the ex-situ accelerated mineralization as a potential option for carbon dioxide
sequestration is studied. Accelerated mineralization can make use of naturally occurring
minerals like wollastonite, olivine, brucite etc. Apart from natural ores, alkaline wastes are
also considered to be suitable alternatives as reactants in the carbonation process since the
alkaline wastes are cheap and widely available.
Most of the studies on accelerated mineralization are performed on lab-scale where the
reaction conditions for the carbonation reactions are studied. However, there is lack of
knowledge on the utilization and end-of-life processing of carbonation products. The
implementation of CO2 mineralization using the industrial solid wastes is in the
experimental stage, but a few research institutes and companies have demonstrated pilot
facilities.