Rev Environ Sci Biotechnol (2023) 22:823–885
https://doi.org/10.1007/s11157-023-09662-3
REVIEW PAPER
Comprehensive technology and economic evaluation based
on the promotion of large‑scale carbon capture and storage
demonstration projects
Minghai Shen · Zhihao Hu · Fulin Kong · Lige Tong · Shaowu Yin ·
Chuanping Liu · Peikun Zhang · Li Wang · Yulong Ding
Received: 21 March 2023 / Accepted: 19 June 2023 / Published online: 31 July 2023
© The Author(s), under exclusive licence to Springer Nature B.V. 2023
Abstract The technology known as carbon capture
and storage (CCS) can significantly reduce greenhouse
gas emissions on a massive scale. The whole process
and large-scale CCS projects are still in the exploratory stage from project demonstration stage to commercialization stage because to the significant expenditure,
prolonged operating term, and numerous technological connections involved. The investment cost of CCS,
Minghai Shen, Zhihao Hu and Fulin Kong have
contributed equally to this work.
M. Shen · Z. Hu · F. Kong · L. Tong (*) · S. Yin (*) ·
C. Liu · P. Zhang · L. Wang (*)
School of Energy and Environmental Engineering,
University of Science and Technology Beijing,
Beijing 100083, China
e-mail: tonglige@me.ustb.edu.cn
S. Yin
e-mail: yinsw@ustb.edu.cn
L. Wang
e-mail: liwang@me.ustb.edu.cn
M. Shen · Z. Hu · F. Kong · L. Tong · S. Yin · C. Liu ·
P. Zhang · L. Wang
Beijing Key Laboratory of Energy Saving and Emission
Reduction for Metallurgical Industry, University
of Science and Technology Beijing, Beijing 100083, China
Y. Ding (*)
Birmingham Centre for Energy Storage and School
of Chemical Engineering, University of Birmingham,
Birmingham B15 2TT, UK
e-mail: Y.Ding@bham.ac.uk
the advancement of CCS technology, and the safety of
CCS operation are its primary points of emphasis. There
are several ways to successfully absorb carbon dioxide
­(CO2), but they all have the drawback of having large
investment costs. For the smooth development of capturing technology, the issues of cost and efficiency must be
resolved. Transporting C
­ O2 is usually necessary since its
source and storage location are dispersed and far apart.
This is seen to be the most challenging issue. The secret
to ensuring the success of CCS projects is understanding how to perform efficient economic evaluation when
making investment decisions in light of the high cost of
CCS. The influence of measures like increased carbon
taxes and government subsidies will hasten the commercialization of CCS projects. We advise a thorough
assessment of CCS projects to support their strategic
positioning with nations and investors and deepen decision-makers’ understanding of the technical feasibility
and economics of CCS projects to obtain a more thorough support. This recommendation is based on the progress and challenges in the development of each module.
Keywords Carbon dioxide · Capture · Storage ·
Transport · Economic assessment
1 Introduction
Climate change has been widely recognized as one
of the major issues affecting the normal development
of society and the ecological environment (O’Neill
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et al. 2020; Paltsev et al. 2021). Against the backdrop
of climate warming, countries around the world have
formulated and adopted a series of goals and actions
to mitigate climate change. On November 12, 2014,
China and the United States jointly issued the "SinoUS Joint Statement on Climate Change". According
to the "Statement", the United States plans to reduce
emissions by 26% to 28% in 2015 on the basis of the
reduction in 2005. China plans to reach the peak of
­CO2 emissions around 2030 and increase the proportion of non-fossil energy in primary energy consumption. to around 20% (Schreurs 2019; Cui et al. 2022).
In the "Nationally Determined Contribution" goal
submitted to the United Nations in June 2015, China
plans to reduce C
­ O2 emissions per unit of GDP by
60% to 65% from 2005 levels by 2030, and include
climate change actions in the 13th Five-Year Plan. On
December 12, 2015, nearly 200 parties to the United
Nations Framework Convention on Climate Change
signed the Paris Agreement, committing to keep the
global surface temperature rise within 2 °C before
industrialization by the end of the twenty-first century
(Mallapaty 2020; Chen et al. 2021). As of November 12, 2018, 179 countries have submitted their first
phase of "Nationally Determined Contributions" to
the United Nations (Nath et al. 2021). This series of
action goals for climate change mitigation reflects the
international community’s emphasis on global climate change, and also shows that countries around
the world are taking positive actions on the road to
climate change mitigation.
CCS is an emerging technology that has the potential to reduce C
­ O2 emissions on a large scale and can
effectively control climate warming. According to the
difference of ­CO2 storage location and storage technology, CCS technology can be divided into (Yan
et al. 2021; Chen et al. 2022): ­CO2 Enhanced Oil
Recovery ­(CO2-EOR), ­CO2 saline water layer storage
technology, ­CO2 coal seam storage technology and
­CO2 ocean storage technology. Among them, C
­ O2
flooding and storage technology, as one of the main
utilization technologies in C
­ O2 capture, utilization
and storage technology, can enhance oil recovery and
increase the efficiency of oil resources through ­CO2
injection into oil reservoirs. It can also realize the
reduction of ­CO2 emission of the enterprise, increase
the carbon assets of the enterprise, and achieve a
win–win situation of economic and environmental
benefits. As a result, the C
­ O2 flooding project has
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gradually become a new oil flooding technology pioneered by the petroleum industry (You et al. 2020;
Liu and Rui 2022).
The Global Carbon Capture and Storage Institute
pointed out in "Global Carbon Capture and Storage
Status: 2021 Report Summary" that by the end of
2021, there were 135 CCS projects in operation, construction and development planning around the world
(Martin-Roberts et al. 2021), as Fig. 1a shows. These
projects have proved the safety, reliability, adaptability and economy of CCS and C
­ O2-EOR. Compared
with the development of large-scale integrated CCS
projects in other developed countries, the development of CCS technology in developing countries
(such as China, etc.) is still relatively backward, and
experience is relatively lacking (Fig. 1b). After one
year and one month of construction, on August 29,
2022, China’s first million-ton CCS project—the
Qilu Petrochemical-Shengli Oilfield CCS project was
officially put into operation with gas injection. This
represents that China’s CCS industry has officially
entered into commercial operation. This is China’s
largest demonstration base for the entire industrial
chain of carbon capture utilization and storage, and
it is also China’s first million-ton CCS project (Yao
et al. 2018; Jiutian et al. 2022; Fan et al. 2020). The
main reason for this lag is the lack of scientific economic evaluation and benefit forecast based on China’s demonstration projects, which affects the confidence of investors and decision makers. Therefore,
localization-based CCS economic evaluation is of
great significance for investment decisions and the
completion of large-scale commercial CCS projects.
CCS technology is a general term for multi-technology combinations such as C
­ O2 capture technology, ­CO2 storage technology and ­CO2 transportation
technology. It may involve a wide area, long running
time, large initial investment, and many technical
links. In addition, the development and deployment
of CCS technology is affected by social factors, economic factors, policy factors, environmental factors,
public factors, technical factors and other factors.
Therefore, the whole CCS technology is characterized by complexity and interaction between technologies within each system. Past research related to
CCS mostly focused on the technical and economic
feasibility analysis of a certain module of CCS technology, such as carbon capture (Wilberforce et al.
2021; Olabi et al. 2022), transportation (Zhang et al.
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825
Fig. 1 a By the end of
2021, the distribution of
CCS projects in operation,
construction and development planning around the
world (GCCSI 2021); b the
construction of carbon capture and storage facilities in
various countries
2021; Etzold et al. 2021) or storage (Gholami et al.
2021; Jia et al. 2022). Or focus on the technical and
economic research of a single CCS project, such as
single saline storage (Liu et al. 2023; Qureshi et al.
2022), ­CO2-EOR (Liu and Rui 2022; Li et al. 2022),
­CO2 Enhanced Water Recovery (­CO2-EWR) (Xu
et al. 2022; Wei et al. 2022), etc. One of the important
obstacles for CCS technology from the project demonstration stage to the large-scale deployment and
implementation stage is its huge investment and operating costs. Both the CCS technology system itself
and the derivative application of a single sub-technology have become the focus of concern and research
by scholars and project owners. However, the current
research ignores the interaction and complexity of
the internal subsystems of the CCS system, as well
as the competition between different CCS technology
routes, and lacks the cost comparison between different CCS projects and related low-carbon policies and
value development of downstream products (Such as
carbon price, carbon subsidy policy and oil price)
impact analysis on CCS technology and economy.
These interactions and dynamics lead to great uncertainty among the costs of different CCS technologies,
and at the same time, the cost of CCS technologies
is constrained by factors such as geo-social, political, economic, resource, environmental and security.
These factors have had a huge impact on the largescale development and deployment of CCS technology in all regions of the world.
Therefore, this review aims to analyze the technology and economy of each module of CCS and its integration from the perspective of whole-process system optimization. By discussing the interaction and
dynamics between different CCS technology routes,
the CCS system itself and the internal subsystems of
the system, the uncertainty of the entire CCS system
of the system is analyzed. Through the analysis of the
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research progress of CCS technology, it can be found
that the research directions of CCS technology being
carried out in the world are very extensive. At present, there is no systematic evaluation and economic
evaluation that combines ­CO2 capture and compression, transportation, storage, ­CO2 leakage monitoring,
prediction and early warning. Therefore, this review
collects the development status of global CCS demonstration projects or commercialization projects,
grasps the global dynamics and development trends
of CCS technology and project development, and lays
the foundation for the comprehensive development
of CCS-related technology and economic evaluation models. This article aims to activate the technical feasibility and economic development potential of
CCS under the influence of uncertain factors, so as to
accelerate the strategic positioning of CCS technology in various countries and contribute to the mitigation of global warming.
2 Development status of carbon capture
technology
Flue gases from the combustion of large fossil fuels
such as boilers, cement kilns and industrial furnaces
contain large amounts of C
­ O2. These direct emissions
of ­CO2 are one of the main causes of global warming due to the greenhouse effect. This method is to
separate ­CO2 from flue gas, which is currently mainly
used in coal-fired power plants, and is also suitable
for natural gas boilers (Dods et al. 2021). Coal-fired
power plants tend to have higher flue gas C
­ O2 concentrations than natural gas combined cycles (Jin
et al. 2022). Coal-fired power plant flue gas treatment
by carbon capture technology has greater economic
value and is easy to industrialize, while natural gas
has no impurities, so the flue gas flow is very clean
(Alabi et al. 2022). This means that no cleanup is
required to effectively capture ­CO2, allowing greater
flexibility in the choice and design of carbon capture technologies. The following will review several
mainstream ­CO2 capture technologies currently in the
industry, mainly including process capture, post-capture separation, and direct air capture.
Carbon capture technologies mainly include three
different technologies: pre-combustion carbon capture, post-combustion carbon capture and oxyfuel
combustion capture (Rubin et al. 2012), as shown
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in Fig. 2. Since the capture part accounts for 2/3 or
even more of the entire CCS cost, the international
research and development direction mainly focuses
on "improving capture efficiency and scale and reducing capture cost" (Wilberforce et al. 2019).
Post-combustion carbon capture technology is
mainly used in coal-fired boilers and gas turbine
power generation facilities. Its advantage is that
existing power plants can be retrofitted for postcombustion carbon capture applications, which is
suitable for large-scale carbon capture technology
applications (Farmahini et al. 2020). However, due
to the low concentration of ­CO2 in the flue gas, the
cost of post-combustion carbon capture technology
is relatively high. Therefore, the current research and
development focus is mainly on reducing the cost of
post-combustion carbon capture. At present, postcombustion capture technology is mainly based on
chemical absorption, but the cost and energy consumption are relatively high, and its use is mostly
limited to oil, gas and petrochemical industries (Chao
et al. 2021; Kárászová et al. 2020). Therefore, carbon
capture technology that can be applied to coal-fired
power plants on a large scale is still an international
direction of efforts. On the basis of vigorously developing the chemical absorption method, the carbon
capture technology of the physical adsorption method
is also developing continuously (Liang et al. 2015).
The pre-combustion capture technology has
attracted much attention by combining gasification
technology with carbon capture technology (Olabi
et al. 2022; Porter et al. 2017). Gasification technology produces synthesis gas mainly composed of CO
and ­H2 in a high-temperature furnace (Cao et al. 2021;
Oh et al. 2022). Generally, the reaction between water
vapor and CO is converted into ­H2 and ­CO2, and then
­H2 and ­CO2 are separated by a gas separation device.
The separated and concentrated ­H2 can be directly
used for power generation. High concentrations of
­CO2 can be captured, compressed, purified for utilization or storage. Compared with post-combustion carbon capture, pre-combustion carbon capture has lower
operating costs, but the upfront capital investment is
higher and there is a greater risk to the stability of the
gasifier operation (Carminati et al. 2021).
Oxygen-enriched combustion technology replaces
the air used by coal-fired power plants to react with
pulverized coal with a mixture of oxygen and ­CO2
for combustion (Edge et al. 2011). The combustion
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Fig. 2 Carbon capture technologies under different carbon emission sources
product is mainly C
­ O2, and part of the generated
­CO2 is directly captured, while the remaining flue
gas is reintroduced into the oxygen-enriched boiler
to react with oxygen. The C
­ O2 captured in this way
has a relatively high concentration, and the gas can
usually be processed in a cost-effective manner and
directly compressed for storage (Miao et al. 2021;
Chen et al. 2022). Oxy-fuel combustion capture technology transfers the cost of carbon capture to the air
separation plant, and the future development of this
technology depends on the cost of the air separation
plant (Keivani and Gungor 2022).
Various carbon capture technologies have their
own advantages and disadvantages, but for traditional
coal-fired power plants, post-combustion chemical
absorption carbon capture is currently a relatively
mature solution. For existing coal-fired units, simple
system retrofits for post-combustion carbon capture
are more economical than carbon capture with oxyfuel technology.
2.1 Post‑capture separation technology
For the system through pre-combustion and postcombustion capture, the key technology is the separation of ­CO2. Currently, ­CO2 separation technologies in mixed gases include physical and chemical
methods (Liu et al. 2021). According to the different principles of ­CO2 separation, physical methods
can be divided into solvent absorption, adsorption,
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membrane separation and cryogenic distillation, etc.
The basic characteristics of each method are shown
in Table 1.
Among them, the solvent absorption and the pressure swing adsorption have been industrialized.
The principle of the physical absorption is to use an
organic solvent to absorb the acid gas under pressure to separate and remove the acid gas components
(Sattari et al. 2021). The regeneration of the solvent
is realized by reducing the pressure, and the regeneration energy required is relatively small (Lee et al.
2021). Typical physical absorption include polyethylene glycol dimethyl ether method (called NHD or
Selexol), low-temperature methanol washing, etc. The
physical absorption is suitable for the separation of
­ O2 in the gas is high,
­CO2 when the concentration of C
such as the separation of ­CO2 in Integrated Gasification Combined Cycle (IGCC) (Zhang et al. 2022). It
operates at a higher operating pressure and is not suitable for the separation of C
­ O2 from tail gas. In addition, the new ionic liquid capture ­CO2 is also a physical absorption technology. C
­ O2 solubility is high in
RTILs based on imidazolium-based cations. Because
of their negligible volatility and excellent thermal
stability (no detectable mass loss was observed even
after multiple absorption/desorption experiments),
ILs have been creatively studied as trapping Potential
candidates for C
­ O2 (Sistla and Khanna 2015; Zhang
et al. 2013). The ability to tune ­CO2 physical uptake
by ILs (Gurkan et al. 2010; Niedermaier et al. 2014)
and aprotic heterocyclic anions (AHAs) (Wang et al.
2011) by tuning the properties of cations or anions.
Adsorption hydrogen production has been commercially used to a certain extent, and some studies have
also shown the feasibility of separating ­CO2 on an
industrial scale (Chen et al. 2021).
The main disadvantages of ­
CO2 separation by
physical adsorption are (Liu et al. 2021): the separation rate is low; there are few adsorbents with high
­CO2 selectivity; when used in the power industry,
the adsorption method has the problem of high cost.
Vacuum Swing Adsorption (VSA) or Vacuum Pressure Swing Adsorption (VPSA) based on physical
adsorbents such as zeolite and activated carbon are
relatively mature post-combustion carbon capture
technologies (Dunstan et al. 2021). Taking the VSA
unit filled with 13X zeolite as an example, in order
to achieve a ­CO2 purity higher than 95%, it is usually necessary to reduce the regeneration pressure to
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below 10 kPa (Yoro et al. 2021). To avoid the performance degradation of the physical adsorbent,
the VSA system usually needs to dry the flue gas
in advance, thus increasing the additional capture
energy consumption. The energy consumption of
the VSA process is about 1.5 ~ 3 ­GJe/tCO2, which is
equivalent to 4.5 ~ 9 ­GJth/tCO2.
The membrane separation method separates gases
by utilizing the difference in permeability of membranes made of specific materials to different gases.
Membrane materials are divided into organic polymer membranes and inorganic membranes (Han and
Ho 2021). Organic membranes have higher selectivity and permeability, but are inferior to inorganic
membranes in terms of mechanical strength, thermal
stability and chemical stability. Common membrane
materials include: carbon membranes (Cao et al.
2019), silica membranes (Hu et al. 2020), zeolite
membranes (Ahmad et al. 2020), facilitated transport membranes, hybrid membranes, polyamide
membranes (Sodeifian et al. 2019), and polyphthalate membranes (Lei et al. 2020). Among them, the
silicon dioxide film is considered to be the closest to
industrial application.
Physical membrane separation require high operating pressures and are not suitable for C
­ O2 separation in conventional coal-fired power plants (Han and
Ho 2021). However, the membrane separation has
a compact device, occupies less land, and is easy to
operate, so it has great development prospects (Aghel
et al. 2022). The disadvantage is that the ­CO2 separation rate of general membrane materials is low
­(CO2/N2 selectivity: 1.61–120), and it is difficult to
obtain high-purity ­CO2. To achieve a certain amount
of emission reduction, a multi-stage separation process is often required (Wu et al. 2021; Senatore et al.
2021). And its price is high at present, and service life
is also short, has improved input cost greatly.
Emerging physical membrane materials bring
opportunities and challenges to the development of
gas separation membrane materials due to their regular and ordered nanopore channels and structural
design diversity (Yang et al. 2020). Existing physical membrane materials still cannot meet the requirements of high selectivity and high permeability gas
separation due to their large pore size or mismatch
with gas molecular size. Membrane permeability
can be improved by shortening the molecular transport path and widening the gas transport channel.
Basic Principle
Type
Absorption
(Nakao et al.
2019)
Based on Henry’s N-methylpyrrolidone, polylaw, the solubilethylene glycol
ity of ­CO2 in
dimethyl ether,
the absorbent
low temperachanges with
ture methanol,
pressure or
propylene
temperature
carbonate
Selectively
Adsorption
Temperature
adsorb ­CO2
(Ben-Mansour
swing adsorpet al. 2016)
tion, pressure
through solid
swing adsorpadsorbents such
tion, vacuum
as zeolite and
molecular sieve, adsorption
and change the
temperature
and pressure
to achieve ­CO2
desorption
Membrane sepa- Utilize the differ- Inorganic membrane, organic
ence of memration (Ahmad
polymer
brane material
et al. 2016)
membrane,
to different gas
mixed matrix
permeation rate
membrane
Cryogenic distil- After compres–
sion and
lation (Song
cooling, ­CO2
et al. 2019)
is liquefied
or solidified,
and ­CO2 is
separated by
distillation
Technology
Maturity
2.3 k€/(m3/h) ≥ 99% Simple and easy CO2 recovery rate
to operate,
is low and cost
avoiding the
is high
use of chemical
or physical
absorbents
1400m3/h
Difficult to obtain
high-purity ­CO2,
and the durability of membrane
materials is poor
Adsorbent with
limited capacity
and low selectivity
Industrial appliIndustries with
cation
high ­CO2 emissions, such as
IGCC power
stations, recovery of ­CO2
from associated
gas in oil fields,
etc
≥ 95% Simple process,
low energy
consumption
and small
investment
≥ 90% Simple process,
low energy
consumption
and controllable cost
High absorption/
regeneration
energy consumption and
cost, resulting in
high operating
costs
Disadvantages
44.6$/t ­CO2
20$/t ­CO2
0.2–5.5t/d
Advantages
≥ 96% Strong selectivity, large
absorption
capacity, simple operation
Purity
20t
smoke /d
77.5¥/t ­CO2
Cost
5wt/y
Processing
Capacity
Large-scale ­CO2
Hydrogen production, natural
capture is in
gas processing,
the laboratory
etc
development
stage
Industries with
Industrial applihigh ­CO2 emiscation
sions, such as
IGCC power
plants, natural
gas processing,
coal chemical
industry, etc
Synthetic ammo- Industrial application
nia, hydrogen
production,
natural gas
treatment, etc
Application
Industry
Table 1 Current status of ­CO2 separation technology by physical method
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Optimize the properties and structure of the separation membrane to avoid problems such as film-forming defects, resist aging and plasticization, and further improve the stability of the membrane layer (Xie
et al. 2019; Siagian et al. 2019).
In the future, research on C
­ O2 separation membranes, especially ­
CO2 separation membranes for
flue gas capture, will continue to focus on industrial
applications (Kárászová et al. 2020). While focusing
on improving permeability and stability, and realizing the maturity of large-scale preparation technology, it is also necessary to systematically investigate
the technical economy of the membrane process process scheme. Integrate and optimize the complete set
of ­CO2 separation membrane equipment. Design and
develop the whole process process package to realize
the reduction of membrane cost and the improvement
of membrane technology economy.
The cryogenic distillation is to liquefy the gas
by increasing the pressure and lowering the temperature to realize the separation of C
­ O2 (Shen et al.
2022). This method separates ­CO2 in a liquid state,
and the separated C
­ O2 is more convenient for transportation and storage. This method avoids the use of
chemical or physical absorbents, does not have problems such as absorbent corrosion, and consumes less
water (Babar et al. 2021). However, a large amount
of energy is consumed in the cryogenic process, and
equipment investment is relatively large (Maqsood
et al. 2021; Guido and Pellegrini 2022). Since the
separated ­CO2 is easy to transport and store, this
method is mostly used for enhanced oil displacement.
In order to solve the disadvantages of cryogenic
carbon capture technology, it is necessary to develop
its technology and application in a targeted manner.
Due to the common industrial waste gas containing
­CO2, there are a large number of gases with low boiling point ratio (such as N
­ 2, ­O2, Ar, etc.). The presence of these gases results in a lower phase transition
temperature and a corresponding significant increase
in capture energy consumption. By coupling with
other carbon capture technologies (such as membrane method, adsorption method, etc.), enriching
carbon dioxide to a certain extent can greatly reduce
the energy consumption of liquefaction (Font-Palma
et al. 2021).
Generally, flue gas has many components, mainly
­N2, ­O2, ­CO2, ­H2O, ­NOx, ­SOx, Hg, etc. The presence of these components complicates the working
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conditions of the entire process, covering almost all
temperatures from below the triple point to supercritical (Perskin et al. 2022). For pre-combustion
capture technology and oxyfuel combustion technology, although the concentration in the mixed gas
is relatively high, a large amount of energy is also
required for coal gasification or air separation in the
raw gas treatment process. In industry, especially the
iron and steel metallurgy industry equipped with liquefied natural gas (LNG) and oxygen-enriched combustion systems has great advantages in cold energy.
To reduce the cost of equipment, cryogenic storage
tanks, expanders and other equipment are shared with
the gas separation system of cryogenic rectification
in steel and chemical industry. The distribution of
LNG pipelines (usually in coastal ports) and the efficient use of cold energy need to be solved (Shen et al.
2022).
In order to solve the problem of high energy consumption of low-temperature carbon capture, efficient
energy recovery can also be carried out in the following ways. 1) Improve the heat and mass transfer efficiency and reduce the separation energy consumption
in the rectification process. 2) Improve the heat and
mass transfer efficiency of the pre-purification system
(separation of water vapor in advance) and reduce
energy consumption. 3) Integration and optimization
with existing process systems to improve energy utilization efficiency.
In the mixed gas, when the partial pressure is
lower than the triple point, it will be precipitated in
solid state and condensed on the surface of the equipment, even causing blockage of the pipeline. It causes
certain difficulty to system design and industrial
application (Chen et al. 2022). The development of
new cryogenic systems and anti-icing heat exchangers will help advance the development of cryogenic
separation technology.
According to different ­CO2 separation principles,
chemical methods can be divided into solvent absorption (Aghel et al. 2022; Jang et al. 2021), adsorption
(Keshavarz et al. 2021; Zou et al. 2021), membrane
absorption (Cao et al. 2021; Sohaib et al. 2021), electrochemical (Zhu et al. 2021; Sullivan et al. 2021)
and hydrate (Lu et al. 2022; Qureshi et al. 2022), etc.
The basic characteristics of each method are shown
in Table 2. Among them, the chemical absorption
is a mature technology and is the most widely used
­CO2 capture technology, which has been successfully
Electrochemical
(Yaashikaa
et al. 2019)
Membrane
absorption
(Yan et al.
2007)
Adsorption (Yi
et al. 2013)
CO2 chemically Ammonia solu- Industries with
low ­CO2 emistion absorpreacts with the
tion, hot
absorbent to
sions, such as
potash, organic
form unstable
conventional
amine absorpsalts; upon
coal-fired
tion, lithium
heating, ­CO2 is
power plants,
salt absorption
natural gas
released again
processing, etc
Hydrogen
Separation and
Metal oxide
production,
recovery of
adsorbents,
natural gas
­CO2 compohydrotalciteprocessing, etc
like solid
nents in the
adsorbents,
mixed gas by
amino adsorsolid material
bents, and
adsorption or
metal–organic
chemical reacframeworks
tion
(MOFs)
The combination Membrane con- Hydrogen
production,
of membrane
tactor: hollow
natural gas
contactor
fiber memprocessing, etc
and chemical
brane contacabsorption
tor; absorption
realizes the
liquid: the
selective sepaabsorption
ration of ­CO2
liquid used in
ordinary chemical absorption
process
Capture and
–
Molten salt
separation of
electrochemi­CO2 using an
cal system, etc
(Renfrew et al.
electrochemi2020)
cal system
Application
Industry
Absorption (Yu
et al. 2019)
Type
Basic Principle
Technology
Table 2 Current status of ­CO2 separation technology by chemical method
20–56$/t ­CO2
59.5–103.6 $/t
­CO2
1.26 €/kg
0.01–200
Industrial
applications,
not enough
attention
Large-scale ­CO2 30 ­Nm3/h
capture is in
the laboratory
development
stage
Pilot stage
5500 t/y
20 ~ 42$/t ­CO2
Cost
1wt/y
Processing
Capacity
Industrial
application,
large-scale
demonstration
Maturity
Disadvantages
≥ 95% Broad-based
electrochemical technology
with low separation costs
≥ 95% Simple device,
large contact
area, high
selectivity
For molten salt,
high temperature corrosion
is strong, and
the selection of
electrode materials is difficult
(Winnick et al.
1982)
Membrane
material is less
durable
High regeneration
heat consumption, large loss
of absorbent,
high operating
cost, and large
investment in
equipment
Performance is
≥ 90% Simple process
greatly affected
flow, good
by factors such
­CO2 selective
adsorption, and as absorption/
desorption times
high removal
and temperature
efficiency
Advantages
≥ 99% Mature process,
good selectivity, high
absorption
efficiency
Purity
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Hydrate is easy
to corrode the
device, so it has
high requirements for equipment material
selection
≥ 98% The process is
relatively simple, the energy
consumption
is reduced,
the separation
effect is good,
and there is
no loss of raw
materials in
theory
20–40$/t ­CO2
1 × ­106 ­Nm3/h
Coal flue gas
Water and ­CO2
form ­CO2
hydrate at a
certain temperature and
pressure
Hydrate (Ma
et al. 2016)
–
Pilot stage
Cost
Application
Industry
Type
Basic Principle
Technology
Table 2 (continued)
Maturity
Processing
Capacity
Purity
Advantages
Disadvantages
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applied in fertilizer, cement and power generation
industries.
At present, more mature chemical absorption
processes are mostly based on ethanolamine aqueous solutions, such as ethanolamine (MEA), diethanolamine (DEA), N-methyldiethanolamine (MDEA),
etc. Newly developed chemical absorption processes
in recent years include ionic liquids, phase change
solution, enzyme absorption, and high temperature
molten salt carbon capture, etc. Chemical absorption
is suitable for C
­ O2 separation when the C
­ O2 concentration in the gas is low (less than 20%) (Ochedi
et al. 2021; Yamada 2021). The disadvantage is that
the regeneration heat consumption of the absorbent
is high, and the loss of the absorbent is large. Amine
absorption is currently a widely used and mature ­CO2
capture process (as shown in Fig. 3). However, this
method has the disadvantages that the absorbent is
easy to corrode the equipment, the long-term production leads to the reduction of the absorption capacity
of the absorbent, and the high energy consumption of
desorption (Choi et al. 2021; Ratanpara et al. 2021).
The capture costs of monoethanolamine absorption
and pressure swing adsorption are 49 ~ 70$/t ­CO2 and
51 ~ 57$/t ­CO2 (Shao et al. 2013) respectively, and the
capture cost of the most advanced chemical absorption is 20 ~ 42$/t ­CO2. However, the EU believes that
the cost of large-scale carbon capture should not be
higher than 20 ~ 30€ (23 ~ 34$)/t ­CO2 (Hongjun et al.
2011).
For membrane separation, although it has a good
separation effect, the application of this method in
actual production is seriously inhibited due to the
expensive preparation cost and short life cycle of the
membrane. Before chemical membrane separation,
the separation gas needs to be processed in advance,
including basic operations such as dehydration and
filtration, and the membrane separation method also
has related problems such as low selectivity and low
separation purity. At present, ­CO2 membrane separation mainly focuses on the development of membrane materials in order to obtain high-efficiency and
low-cost membrane materials (Buddin and Ahmad
2021; Russo et al. 2021). The application of membrane technology to flue gas carbon capture is still in
the pilot test and demonstration stage. The researchers predicted the carbon capture costs of different
types of gas separation membranes based on process
simulations. To achieve the separation goal of ­CO2
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833
Fig. 3 Part of the process flow of the alcohol amine-based carbon capture demonstration project (Luchang et al. 2021)
purity ≥ 95% and recovery rate ≥ 90%, the ­CO2 capture cost of PVAm composite membrane is about
44.6$/t ­CO2 (Sheng et al. 2021). With the improvement of membrane performance and the optimization of membrane modules and separation processes,
the cost of membrane- ­CO2 capture will be further
reduced. For example, when the C
­ O2 permeation rate
and ­CO2/N2 separation factor of the membrane reach
3000GPU and 140, respectively, the capture cost can
be reduced to below 24$/t C
­ O2 (Ramasubramanian
et al. 2012). To realize the large-scale application of
membrane carbon capture, its expected cost should be
reduced to 20 ~ 40$/t ­CO2.
Due to the low cost of limestone, high ­CO2 capture
and absorption capacity, and almost no pretreatment
of flue gas, calcium cycle ­CO2 capture technology is
considered to be an economical and environmentally
friendly ­CO2 capture technology. It is used as a flue
gas capture process in the cement industry, reducing
energy consumption per unit of production (~ 223 kJ/
mol) (Wang et al. 2012; Grasa et al. 2008). CaO is
used as an absorbent to capture and absorb ­CO2 to
generate ­CaCO3, and then ­
CaCO3 goes through a
process of removing C
­ O2 to complete the recycling
of the absorbent (Khosa et al. 2019). Adding a certain amount of inorganic salts to CaO, such as M
­ gCl2,
­CaCl2 and Green’s reagent, can effectively improve
the pore size distribution of the absorbent, optimize
the best absorption pore size, and thus improve its
absorption cycle capacity (Salvador et al. 2003;
Romeo et al. 2009).
In addition, some salts, such as carbonate-lithium
metal oxide mixtures and molten salts of lithium silicate ­(Li4SiO4), have also been used as ­CO2 capture
agents (Hu et al. 2019; Garcia et al. 2017). Different from the traditional C
­ O2 capture technology, the
hydrate ­CO2 separation and capture technology is
based on the difference in "phase equilibrium conditions between different gases" in the mixed gas, and
by controlling its temperature and pressure, the C
­ O2
molecules preferentially enter the water molecular
cage and form (Semi) solid hydrate crystals. This
can realize the capture, separation and purification of
­CO2. It has the advantages of simple raw materials,
high gas storage density, safe storage and transportation, low energy consumption, and environmental
friendliness (Kim et al. 2017), and is considered to
be an emerging method for capturing ­CO2. This new
technology uses no or very few chemicals and only
uses low-temperature water as the liquid. The technology of ­CO2 capture by hydrate method is still in
its infancy. In order to explore the conditions for the
rapid formation of hydrate, some effective accelerators or additives have been explored to accelerate gas
capture. However, under the conditions of different ­CO2 concentrations, mixed gases with different
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components, different operating conditions, and different accelerators, the research results are quite different, and even different authors draw opposite conclusions, which is mainly due to the formation of
hydrates. The process is complex and highly random,
as well as the diversity of experimental conditions.
The cost of capture (including compression) makes
up the majority of the cost in most CCS systems.
Energy and economic models show that the development of CCS systems in the electricity industry will
be the primary factor in the mitigation of climate
change. Most simulation results show that CCS systems do not start to be deployed at significant scale
until ­CO2 prices start to reach around 25–30$/t ­CO2.
It is estimated that the application of CCS in power
generation will increase the cost of power generation
by about 0.01–0.05 $/kWh, and the specific cost will
depend on fuel, specific technology, site and national
environment. Including the benefits of EOR reduces
the additional electricity production costs incurred
by CCS by approximately 0.01–0.02$/kWh. The cost
of CCS often rises as the market price of the fuel
used to produce electricity does as well. It is unclear
how much oil prices will affect CCS. However, as
oil prices rise, EOR income often increase as well.
Energy prices will rise significantly if CCS is used to
produce electricity from small-scale biomass sources.
Fig. 4 Carbon capture
and storage cost curve ($/t
­CO2-eq) and greenhouse
gas emission reduction
potential (Gt C
­ O2-eq),
Source: Goldman Sachs,
Equity Research 2020
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It will be more cost-effective to use biomass co-firing
in a bigger coal-fired power station using CCS. Comparing retrofitting an existing facility with ­CO2 capture to establishing a new plant with capture, greater
costs and a considerable reduction in overall efficiency are anticipated. The cost disadvantage of retrofitting is reduced for some existing plants that are new
and highly efficient, or for plants that have been substantially upgraded or rebuilt. The current operating
cost of CCS in some industries may be expensive, but
it will gradually reduce the cost on the way to achieve
carbon neutral development. As shown in Fig. 4,
compared to low-cost natural carbon sinks, CCS is
currently more practical in industry. The abscissa
indicates the amount of all carbon sources that can be
replaced by different carbon-emitting industries in the
future (including carbon sources such as electricity,
coal, production materials, and emissions). Moreover,
the cost of capture is inversely proportional to carbon
concentration, which is more conducive to promoting industrial CCS projects (for carbon capture technologies in different industries, please refer to Kosaka
et al. (2021), Molina-Fernández and Luis (2021),
Yang et al. (2021), Dhoke et al. (2021), which have
not been described too much). In the future, direct air
capture will have greater potential and development
space.
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2.2 Direct air capture technology
Direct air capture technology (DAC) was first proposed by Professor Lackner of Columbia University
in 1999. That is to use chemical adsorbents to directly
use air as the transport medium of ­CO2 to enrich
the low concentration (400 ppm) of C
­ O2 (McQueen
et al. 2021; Custelcean 2021). The process of separating reduced-concentration C
­ O2 from gas streams has
a long history. For example, ­CO2 is removed in the
process of natural gas production to ensure the quality of raw gas. In cryogenic air separation equipment,
zeolite or activated carbon is used to remove ­CO2 in
the air to prevent dry ice from being generated and
damage to equipment. And the use of PEI/PEG-based
adsorbents in submarines to absorb C
­ O2 in the cabin
to prevent ­CO2 poisoning of the cabin crew (Madhu
et al. 2021). Although compared with the flue gas
capture technology, this technology has the characteristics of flexible layout, can solve the problem of distributed and point carbon source emissions, and can
avoid the influence of other pollutants in the flue gas.
However, the high capture energy consumption prevents the large-scale application of DAC technology
at present (Keith et al. 2006; Marchese et al. 2021).
The relevant situation of some direct air capture demonstration projects is shown in Table 3.
Due to the low concentration of ­CO2 in the air, it is
necessary to use a chemical adsorbent with a strong
affinity for C
­ O2 for capture. DAC techniques typically
employ hydroxides and amines as active ingredients,
which can be introduced either as liquid solution
components or as surface functional groups on high
surface area solid materials (Ishimoto et al. 2017).
After ­CO2 capture, a certain amount of energy input
is usually required to reach a specific temperature and
pressure for regeneration and concentration of ­CO2
(Wilcox et al. 2017).
One of the keys to DAC technology lies in the
development and design of high-efficiency and lowcost absorption/adsorption materials (Shi et al. 2020).
Physical adsorption based on materials such as molecular sieves and metal–organic frameworks relies on
intermolecular forces to adsorb ­CO2, which usually
occurs on the surface of the adsorbent. Adsorption
materials require that the adsorbent has a high surface
area, such as a material with high porosity or nanometer size as the adsorbent. Physical adsorbents are
easy to regenerate, but since the absorption of C
­ O2
835
from the air generally reacts at room temperature, the
adsorption and selectivity of physical adsorbents are
weaker (Sujan et al. 2019). Chemisorbents mainly
based on amine-based adsorbents rely on chemical
bond force adsorption, and chemical adsorbents have
strong adsorption (Lin et al. 2023). However, due to
the tight combination of molecules due to chemical
bonds, it consumes a lot of energy during C
­ O2 desorption. The absorption operation is realized through
chemical reaction, but the process is complicated and
the absorption efficiency is not high. The advantage
of using an alkaline solution based on NaOH, KOH,
and Ca(OH)2 for DAC lies in the low cost of reaction raw materials. However, the regeneration stage
requires high reaction temperature and high energy
consumption (Madhu et al. 2021).
The researchers wanted to find a material that was
structurally stable and could be regenerated in a lower
temperature range, thereby reducing the cost of the
DAC (Sodiq et al. 2022). Therefore, how to develop
adsorbent materials with both high adsorption capacity and high selectivity is the key to the future commercial application of DAC technology (Deutz and
Bardow 2021). In addition, the ­CO2 desorption process from the sorbent must also be simple, efficient,
and less energy-intensive. Absorbent/adsorbent materials are capable of many cycles (McQueen et al.
2021).
Due to their good adaptability to low partial pressure, chemical absorption and solid adsorption are the
focus of current research and application. Although
the absorption process based on organic amine solution has been widely used in flue gas carbon capture. However, when it is applied to the scene of air
capture with low liquid-to-gas ratio, it will face the
problem of a significant increase in cost (Sabatino
et al. 2021). In addition, water consumption is also a
major consideration when considering the application
of DAC technology. Most of the different technologies need to consume a large amount of water during operation, most of which are lost in the form of
liquid evaporation, which may cause greater pressure
on water resources in the area where the equipment
is arranged. But the technology’s main application
at present is to provide air enriched with C
­ O2, rather
than high concentrations of ­
CO2. Due to the low
grade of heat energy it needs can be directly provided
by industrial waste heat, and the intermittent nature of
renewable energy power supply will not have a great
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Table 3 Status of direct air capture demonstration projects
Year Scale
Cycle process Adsorption/
absorbent
Capture
capacity
EDAC(GJ·t−1) c/( $·t−1)
Canada
Carbon Engineering (Keith
et al. 2018)
2015 Pilot test
TSA
1t/d
10
Canada
Carbon Engineering (Keith
et al. 2018)
2017 Pilot test
TSA
High temperature
solution
absorption
(KOH)
High temperature
solution
absorption
(KOH)
–
0.004t/d
2.47t/a
TVSA
Commercial
Amine
Polymers
Aminopropyl
grafted
nanofibrillated
cellulose
(NFC)
Solid amine
80% synthetic –
diesel
–
Switzerland 2017 Commercial
factory
TVSA
–
900t/a
–
–
Finland
2018 Small test
TVSA
Aminopropyl
Grafted
NFC
DAC/
Enhanced
Weathering
Coupled
System
–
0.0038t/d
–
92
–
–
–
400t/a
–
–
MOF/polymer nanocomposites
0.001t/d
5.76
35–350
Institution
Location
Canada
2023 Commercial
Carbon Engifactory
neering (Keith
et al. 2018)
Netherlands 2019 Prototype
University of
Twente (Brilman 2020)
Switzerland 2011 Prototype
Climeworks
(Gebald et al.
2011; Vázquez
et al. 2018)
TSA
TVSA
Climeworks
(Gebald et al.
2011; Vázquez
et al. 2018)
Climeworks
(Gebald et al.
2011; Vázquez
et al. 2018)
Oy Hydrocell
(Zhu et al.
2022)
Carbfix
(Leonzio et al.
2022)
Germany
Iceland
2017 Commercial
factory
TVSA
Climeworks + Carbfix
University
of Ottawa,
Monash University (Sadiq
et al. 2020;
Wijesiri et al.
2019)
Iceland
2022 Commercial
factory
TVSA
Australia
2020 Prototype
TVSA
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2014 Pilot test
TSA
–
Production of –
liquid fuel
(1 barrel/d)
–
1Mt/a
2.1–4.5
35$/t for EOR
and 50$/t for
storage
150–200
–
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Table 3 (continued)
Institution
Location
Global Thermo- U.S
stat, Georgia
Institute of
Technology
(Choi et al.
2009)
Year Scale
Cycle process Adsorption/
absorbent
Capture
capacity
EDAC(GJ·t−1) c/( $·t−1)
2018 Commercial
factory
S-TSA
10.96 t/d
5.83 ~ 7.9
Amino
honeycomb
ceramics,
MOF
60 ~ 190
In the table, EDAC is capture energy consumption (calculated as C
­ O2)
impact on system operation, so its power consumption
can be better coupled with renewable energy (Deutz
and Bardow 2021). But at the same time, because
the performance of the adsorbent is greatly affected
by the local climate conditions, it is of great practical significance to analyze its actual working performance under different temperatures and humidity.
The above technologies can have a good emission
reduction effect on carbon emissions from stationary
sources, but 40% of carbon emissions contributed by
mobile sources cannot be solved by the above technologies (Lehtveer and Emanuelsson 2021). Even if
all fixed carbon emission sources are equipped with
carbon capture devices, a large amount of C
­ O2 will
still be released into the atmosphere. According to
IPCC forecasts, this will fail to achieve the goal of
keeping global temperature rise below 2 °C. Most climate and integrated assessment models predict that
by the second half of this century, atmospheric ­CO2
concentrations must stop increasing or even decrease
to have any chance of limiting global warming and
associated dangerous climate impacts (Yang et al.
2021; Jaiganesh et al. 2022). Therefore, negative
emission technology is an indispensable technology.
Figure 5 shows the main technical paths of current ­CO2 negative emission technologies, including
coastal blue carbon, terrestrial carbon plant removal,
biomass capture and storage technology, direct air
capture technology, and carbon mineralization technology. Among them, the direct air capture technology has the advantages of relatively small equipment
footprint, flexible equipment without time and space
constraints, and reduced transportation costs, which
means that it can flexibly produce and supply C
­ O2
raw material gas of required purity to the market. It
is thus considered the most promising negative emissions technology (Vuuren et al. 2018). However, since
the concentration of C
­ O2 in the air is about 1/300 of
that of a coal-fired power plant, from a thermodynamic analysis, it is more difficult to separate a lowconcentration airflow than a high-concentration mixture, requiring more energy (Khallaghi et al. 2021).
Fig. 5 Negative ­CO2 emission technologies: coastal
blue carbon, terrestrial
carbon plant removal,
biomass capture and storage
technology, direct air capture technology, and carbon
mineralization technology
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Thus, to produce C
­ O2 of the same purity, DAC processes may be more expensive to capture than fossil
fuel power plants (Melara et al. 2020; Creutzig et al.
2019).
At present, DAC is rarely involved in the industrial field, so there are few research reports on related
DAC equipment. In order to promote the promotion
of DAC technology, on the one hand, it is necessary
to combine DAC with renewable energy to reduce its
operating cost (Beuttler et al. 2019). Considering that
DAC needs to be deployed in a large range outdoors,
DAC can be combined with existing wind and solar
power generation systems (Bos et al. 2020). Scheduling peak and valley electricity and thermal energy
to reduce the operating energy consumption of DAC
technology (McQueen et al. 2020). Secondly, effectively improving the functionality of the DAC system
is also one of the important directions for its future
commercial development. For example, placing
DACs in arid areas such as deserts can capture water
during the carbon capture process. The conversion of
­CO2 into valuable chemicals is achieved through photothermal power generation or catalysis using solar
energy. Overall, the integration, optimization and
empowerment of DAC technology is the key to commercial promotion.
3 Carbon storage technology
New technologies and strategies are required to
ameliorate the issue of climate change and regulate the rising emission and concentration of C
­ O2
in the atmosphere. Generally speaking, there are
three basic ways to combat climate change: increasing energy efficiency, switching to alternate, less
carbon-intensive fuels, and carbon capture and storage (Folger 2017). The reality is that eliminating all
Table 4 CCS geological
storage potential and
­CO2 emissions in major
countries and regions
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petroleum-based products is a near-impossible aim
in the short future, and increasing energy efficiency
alone won’t be enough to stop the emissions from
continuing to climb. In October 2018, the government’s Panel on Climate Change released a special
report on global warming of 1.5 °C, emphasizing that
CCS must play a role in addressing climate change.
To mitigate climate change, the report says, global
net anthropogenic ­CO2 emissions need to be reduced
by at least 45% in 2030 compared to 2010 levels and
reach “net zero” around 2050 (Page et al. 2019). Carbon capture and storage (CCS), a technology that captures ­CO2 and then stores it in geological reservoirs,
is the most promising and economically viable way to
combat global warming (Page et al. 2019; Tcvetkov
et al. 2019). ­CO2 capture and storage is the only clean
technology capable of decarbonizing major industries
and a key technology to address carbon emissions.
Recognized evidence from climate change professional bodies shows that international climate change
goals cannot be achieved without CCS.
To date, more than 230 million tons of ­CO2 have
been safely injected underground (Page et al. 2019).
As shown in Table 4, although some countries and
regions have reduced C
­ O2 emissions in order to
achieve carbon neutrality, global emissions are still
on the rise. Compared with the theoretical storage
capacity, the current storage capacity is less than 1%,
which needs to be developed. ­CO2 sequestration is a
process in which C
­ O2 is captured from power plants
or other large-scale ­CO2 releases, purified and compressed, and then injected deep into the formation
to achieve separation from the atmospheric environment and seal it up. There are many ways of ­CO2
storage (Orr 2009): (1) Geological storage: injecting
supercritical ­CO2 into deep saline aquifers or abandoned oil and gas fields, so that C
­ O2 slowly dissolves
in brine, so as to achieve the purpose of long-term
Country/region
Theoretical storage
capacity (10 billion
tons)
2019 ­CO2 emissions
(100 million tons/year)
2021 ­CO2 emissions
(100 million tons/
year)
China
Asia (except China)
North America
Europe
Australia
121–413
49–55
230–2153
50
22–41
98
74
60
41
4
119
58.35
56.02
24
4.88
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storage. (2) Chemical fixation: use C
­ O2 to chemically
react with underground minerals (basalt) to form stable salts. (3) ­CO2 oil and gas flooding (EOR/ECBM):
use ­CO2 instead of water to displace oil and natural gas, and store C
­ O2 in oil and gas field reservoirs
while producing oil and gas. These geological reservoirs include: (a) deep saline aquifers, (b) depleted
oil and gas reservoirs, (c) oil and gas reservoirs under
­CO2 enhanced recovery, (d) deep unrecoverable coal
seams, (e) coalbed methane and ( f) Shale formations
during enhanced oil recovery (Nguyen et al. 2018;
Godec et al. 2011). However, having an appropriate
strategy in place is crucial for selecting an appropriate storage site (Aminu et al. 2017). Here, we take the
geological storage of ­CO2 as an example, summarize
its storage mechanism and process, and discuss the
technical feasibility of C
­ O2 geological storage.
3.1 CO2 geological storage development and its
mechanism
Only a small fraction of the annual C
­ O2 emissions
may be stored in geological formations, and as of
2017, 220 million tons of man-made C
­ O2 were buried underground. To take use of the huge availability,
capacity, and safety of such geological formations,
­CO2 sequestration at increasing rates is necessary
(Aminu et al. 2017; Kearns et al. 2017). Therefore,
the selection of storage sites must meet three main
conditions: capacity, injection capacity and tightness. Storage site capacity requirements ensure that
the selected site has sufficient pore volume to store
large amounts of C
­ O2. Typically, the site should have
relatively high porosity or have a very large footprint.
If the candidate formation has high permeability, the
­CO2 injection capacity can be guaranteed to ensure
that the lower wellhead pressure can maintain the
required injection rate. To ensure that injected C
­ O2
does not leak to the surface or seep into groundwater,
­CO2 gas is less dense than residual brine, so ensure
a low-permeability caprock (Wang et al. 2021; Chen
et al. 2022; Karvounis and Blunt 2021).
The most practical technique for storing ­CO2 is
believed to be in saltwater aquifers far down. Sedimentary basins may be extremely porous and permeable due to the fact that the majority of salinized
geological formations on earth are found inside these
basins. As a result, when compared to other geological formations, it has the highest storage capacity.
839
Moreover, this type of geological formation has large
pores and high permeability, requires fewer injection
wells, and makes it easier to dissipate pressure. Saline
aquifers have been estimated to have a potential C
­ O2
4
storage capacity of 400 to ­10 Gt (Metz et al. 2005).
Saline aquifers presently recycle brine and water by
injecting ­CO2 from coal sector emissions, in addition
to their vast capacity potential. In addition to meeting
climate requirements, this will improve national water
security (Li et al. 2015). This process creates huge
and safe water storage through controlled pressure
and enables the produced water to be further used for
industrial, agricultural and domestic use after proper
treatment.
Pioneering geological ­CO2 storage projects have
been implemented around the world (Lashgari et al.
2019). Norway’s Sleipner is the world’s first and by
far the longest-running CCS storage project. Over
20 years since 1996. The ­CO2 separated from the
Sleipner gas field is directly injected into the geological layer 1 km below the seabed in the nearby area,
and about 1 million tons of ­CO2 are sequestered every
year. The ­CO2 capture is completed using amine technology. The injection cost is currently 17$/t C
­ O2.
Canada’s Weyburn is the world’s largest onshore
­CO2 storage project. The project, which combines
enhanced oil recovery (EOR) and horizontal drilling
techniques, has achieved the injection of 5,000 tons of
supercritical ­CO2 per day into the Mississippian reservoir at a depth of 1,450 meters (Preston et al. 2005).
In contrast, Ketzin in Germany was the first onshore
storage project in Europe to conduct a pilot-scale C
­ O2
injection study (Martens et al. 2011). ­CO2 storage at
these three sites has reached commercial scale, or at
least demonstration scale.
In Salah in Algeria is a low porosity and low permeability onshore C
­ O2 storage project compared to
Sleipner which has extremely favorable reservoir conditions. Because of the sparse vegetation in the area,
very precise measurements of surface uplift can be
obtained using satellite imagery (InSAR) (Vasco et al.
2010). The cost of storing C
­ O2 is relatively low, with
the 100$ million CCS operation accounting for just
2.5% of the 4$ billion total cost of the In Salah gas
production complex. This puts the cost of sequestering ­CO2 at around 14$/ton. Although this project
ended in 2011, it provided unique and valuable formation uplift data, which provided a strong basis for
the mechanical deformation of the formation caused
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by ­CO2 injection, and also provided a basis for computational analysis of the reservoir’s response to C
­ O2
injection and long-term safe storage. The response
provides a viable benchmark and remains an important site for studying geomechanical processes.
Since the mid-1980s, China has accumulated
knowledge and experience in CCS in a series of
enhanced oil recovery (EOR) projects (Jiang et al.
2022; Liu et al. 2022). However, CCS research is
still in its infancy in China. So far, comprehensive
experience with underground C
­ O2 storage has not
been achieved due to the lack of operational projects
(Zhang et al. 2022; AlRassas et al. 2021; Ranaee
et al. 2022). In 2010, China Shenhua Coal Liquefaction Co., Ltd. (CSCLC), an oilfield operator, started
the first CCS project in a formation with low permeability (less than 1.0 × ­10−14 ­m2) in the Ordos Basin.
Although the reservoirs in this basin are characterized
by low/very low permeability. As an inland basin in
China, the Ordos Basin is considered to be a place
with great potential for geological storage of ­CO2.
Because of its important status as an emerging Chinese coal industry, coupled with its wide distribution
area and widespread distribution in deep saline aquifers below 800 m depth. Therefore, this project has
great research significance.
The ­CO2 geological storage process is shown in
Fig. 6. The first stage: the injected ­CO2 exists in a
supercritical state deep in the formation (Zhang et al.
2021). Since the density of supercritical C
­ O2 is lower
than that of brine in the saline layer (the density of
supercritical ­CO2 is 200–700 kg/m3, the density of
brine is 900–1200 kg/m3), so ­CO2 will continue to
migrate upwards under the action of buoyancy, down
to the bottom of the impenetrable rock formation.
The second stage: due to the impenetrable cover layer
encountered during the upward migration, the migration path is blocked. Supercritical C
­ O2 migrates horizontally along the rock formation to the sides. Under
the rock formation, the accumulation of supercritical
­CO2 occurs to form a ­CO2 pool, and finally a longterm stable interface between supercritical ­CO2 and
brine is formed. The Sleipner project showed significant ­CO2 accumulation after many years of supercritical ­CO2 injection (Boait et al. 2012). The third stage:
In the formation environment, supercritical C
­ O2 can
be partially dissolved in brine (about 3% mass fraction). Moreover, after dissolving C
­ O2, the density
of brine will increase (about 14 kg/m3) (Lindeberg
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and Wessel-Berg 1997). Dissolution at the interface
causes the fluid density at the interface to be greater
than that of the brine below, creating instability that
induces convection.
The first and second phases are relatively short,
taking only a few years or decades (Metz et al.
2005). In these two stages, the storage of ­CO2 mainly
depends on the hindrance of the formation structure,
which can temporarily keep ­CO2 in the formation.
The third stage can last for hundreds or even thousands of years (Ponzi et al. 2021). During this sequestration, ­CO2 slowly dissolves into the subsurface
brine, stopping upward migration. It will also induce
the occurrence of convection, further accelerate the
slow dissolution of ­CO2, and form a solution. In this
process, it is also accompanied by chemical reactions.
In the formation, C
­ O2 will combine with calcium
and magnesium ions in silicate to form precipitates,
thereby fixing C
­ O2 and forming chemical storage
(Raza et al. 2022). Meanwhiles, the acidic C
­ O2 can
react with the carbonate and dissolve the carbonate.
The chemical reaction will accelerate the dissolution
of ­CO2, and at the same time affect the permeability
of the rock formation, and even induce cracks to cause
leakage. There is a risk of ­CO2 leakage in the first
stage. The second stage can only temporarily store
­CO2. The third stage achieves the long-term stable
storage of ­CO2. Since the convective flow generated
in the third stage can greatly promote the dissolution
of ­CO2, accelerate the long-term stable sequestration
of ­CO2. Therefore, the convective flow in the process
of ­CO2 geological storage has extremely important
research value (Kumar et al. 2020).
The efficacy of the different C
­ O2 storage methods
has a major impact on how well the geological storage
process works. The geology of the target formation
and the physical characteristics of the rocks affect the
ability to store and inject ­CO2. Supercritical ­CO2 that
has been injected safely remains underground thanks
to two major storage technologies: chemical storage and physical storage. To ensure long-term storage, the combination of the two storage mechanisms
determines the effectiveness of the storage process
(Kheshgi et al. 2012). Physical storage is the process
by which C
­ O2 maintains its physical properties after
injection into a saline aquifer. It can be divided into
structural storage and residual gas storage. In general,
the time period of physical storage is considered to be
no longer than 1 century (Juanes et al. 2006). When
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841
Fig. 6 CO2 geological storage process (Biniek et al. 2020)
­ O2 interacts with the fluids and surrounding rocks
C
in the saline aquifer, a number of chemical processes
take place. Chemical sequestration occurs when an
element alters its physical and chemical characteristics while remaining in the mobile or immobile phase
in the form of bicarbonate or carbonate minerals.
Mineral storage and solution storage are two categories. As a result of this interaction, ­CO2 separates into
its own phase and vanishes. and further enhance the
storage amount, turning it become a standard attribute
of long-term storage. The four storage techniques will
next be thoroughly explained.
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3.1.1 Stratigraphic and structural storage
When ­CO2 is injected supercritically or in the gaseous form into reservoirs beneath low- or impermeable
caprocks, it becomes trapped there and is referred
to as stratigraphic and structural storage (Zhang
and Song 2014). Figure 7 depicts the buoyancy
effect caused by the difference in densities of brine
(approximately 1.05 g/cm3) and supercritical ­
CO2
(about 0.6–0.7 g/cm3) in the saline water layer. Thus,
injected ­CO2 often migrates laterally along preferred
channels and upward through porous and permeable rocks. till the arrival of a caprock, fault, or other
closed discontinuity (Han and McPherson 2009). The
integrity of the caprock and the storage capacity both
have an impact on how long this storage mechanism
can hold C
­ O2. The first type of geological storage
typically encountered is stratigraphic and structural
storage, and related mechanisms enable oil and gas to
be securely kept underground for thousands of years.
For the injected C
­ O2 to stay underground over time,
it is essential to make the most of this storage system.
There are some related studies on storage structure
models. Xue et al. (2020) studied the variation law of
gas injection rate and coal seam permeability during
the process of ­CO2 sequestration in coal seams. And
based on the pore-fracture dual pore structure characteristics of coal (as shown in Fig. 8), a fluid–solidthermal coupling model for ­CO2 sequestration was
established. The change law of the C
­ O2 gas injection
rate "decreases rapidly at the initial stage and then
basically stabilizes" is illustrated. Ajayi et al. (2019)
Fig. 7 Schematic diagram
of stratigraphic and structural storage (GCCSI 2021)
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conducted a detailed assessment of ­
CO2-storage
saline aquifers near Abu Dhabi. And through the
comprehensive information of deep well and formation, the geological model and numerical model of
saline water layer are established. Sensitivity analysis shows that salinity and relative permeability are
important reference factors for storage site selection. Wang et al. (2020) proposed a fractal model to
explain the evolution process of the transformation of
original long and complex pores into short and simple pores, and the transformation of closed pores into
connected pores during the formation of tectonic coal.
This helps to understand the advantages of structural
coal reservoirs as targets for geological ­CO2 storage.
The ­CO2 geological storage potential calculation
method is based on the assumptions of the geological
storage mechanism, geological storage site and time
scale (Hong et al. 2019). The commonly used methods in the world mainly include calculation methods
proposed by the European Union (Stojic et al. 2022),
the US Department of Energy (Lau et al. 2021), Carbon Sequestration Leadership Forum (CSLF) (Fan
et al. 2021), and Ecofy (Grant et al. 2022). However,
there is no unified calculation method for the calculation of ­CO2 geological storage potential. Taking the
calculation of C
­ O2 storage potential in deep saline
water layer as an example (Vishal et al. 2021), the
calculation method proposed by CSLF is mainly used
in this case. In this method, the storage potential of
­CO2 in deep saline aquifers is mainly divided into
solution storage and residual gas storage.
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843
Fig. 8 Coal double pore
structure characteristics
(Xue et al. 2020)
Different sequestration mechanisms have different sequestration time scales, as shown in Fig. 9.
Structural sequestration starts to work from the initial stage of gas injection, while other sequestration
methods have a relatively long time of action (Saraf
and Bera 2021; Tewari and Sedaralit 2021). In terms
of the safety and contribution of storage, as the time
scale increases, the safety of ­CO2 geological storage
is also increasing (Ma et al. 2021). The contribution
of various storage mechanisms is different. Initially,
structural storage plays the main role and has great
potential. With the passage of time to more than a
hundred years, residual gas storage, solution storage
and mineral storage began to play a role and gradually occupied a dominant position.
Injecting ­CO2 fluid into the oil reservoir to enhance
oil recovery ­(CO2-EOR) is one of the enhanced oil
recovery technologies. ­
CO2-EOR can increase oil
recovery while sequestering ­CO2 to reduce emissions.
Figure 10a shows the distribution of some EOR projects in China. China is currently evaluating enhanced
­CO2-water-based mixed recovery, a brine geological
storage method (not oil recovery) that can be combined with reverse osmosis, offering the potential to
increase water resources in China’s coal chemical and
petroleum basins (Hill et al. 2020). Figure 10b shows
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Fig. 9 Action time of different storage mechanisms (Yao
2017)
the three stages in the ­
CO2 flooding process: gas
injection, soaking and oil production. During flooding
(steps 1 and 2), ­CO2 is injected through fractures into
the reservoir and surrounds the matrix; the concentration gradient drives C
­ O2 penetration into the matrix
(Jia et al. 2019). In the process of water injection,
it is unfavorable for C
­ O2 to carry oil from fractures
to rock matrix, and pushing crude oil from matrix
to fractures is beneficial to oil recovery. During the
soaking phase, the well is shut in (step 3), so it can
also be called the "shut in phase" (Saxena et al. 2022;
Cao et al. 2021). During this time, the C
­ O2 expands
the oil, reducing its viscosity. The flow or production
pressure limits the production well during the flooding process, and diffusion forces the matrix’s miscible
or immiscible oil and ­CO2 toward the crack. The bulk
fluid then returns to the production well through the
crack (step 4).
In recent years, ­
CO2-enhanced shale gas recovery ­(CO2-ESGR) has attracted extensive attention.
Although the ­CO2 displacement shale gas enhanced
shale gas recovery ­(CO2-ESGR) technology is not yet
mature, it has not yet reached the stage of commercial
application. However, some experimental sites have
been established around the world to study the feasibility of this method (Klewiah et al. 2020), as shown
in Fig. 10c. The degree to which rock mechanics,
adsorption isotherms, and hydrological (permeability,
porosity) qualities are impacted by expansion during ­CO2 injection is crucial. Among them, Guo et al.
(2017) observed through a series of experiments that
the adsorption effect has a significant impact on shale
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permeability at both low and high pressures. Deep
coal seams that are difficult to mine can be used for
structural ­CO2 sequestration, which can increase coal
bed methane (ECBM) recovery while storing C
­ O2 in
the coal seam (Pan et al. 2018).
Adsorption isotherms are frequently used as the
foundation for employing thermodynamic concepts to
describe adsorption processes during C
­ O2 displacement. Calculating parameters like adsorption energy,
binding energy, activation energy, or heat of adsorption is what this normally entails. The latter has been
particularly utilized to assess the adsorption of C
­ O2
and methane on shale (Chen et al. 2019). The intensity of the interaction between the adsorbent and
the adsorbate (in this example, the shale surface and
the gas species) is indicated by the isosteric heat of
adsorption. Stronger adsorbate–adsorbate bonding
is indicated by larger values). The traditional definition is that it represents the energy produced when
one more adsorbed molecule is introduced to the
adsorption system. Gas type, surface chemistry, and
pore structure all play a role in this. Adsorption density and surface area play a significant role. Shale has
a higher affinity for C
­ O2 than for methane, as evidenced by the fact that its heat of adsorption for C
­ O2
is higher than that for methane (Cao and Yu 2022;
Dai et al. 2021). The minimal amount of energy
needed for a gas molecule to engage or react with
an adsorption site in a shale formation (overcoming
adsorbate-adsorbent repulsion) is known as the activation energy in adsorption (Kumar and Ojha 2021).
Furthermore, when adsorbed (gas) molecules interact with the surface of the adsorbent, the adsorption
energy ( Eads) is defined as:
Eads = Esys − (Emol + Esurf )
(1)
where Esys, Emol and Esurf are the energies of the gas
phase molecules, the shale surface, and the whole
adsorption-adsorbent system, respectively. Eb, which
describes the interaction between a single isolated gas
molecule and the shale surface, and adsorption stabilization energy, which takes into consideration the
intermolecular interactions between gas molecules,
are added together to form Eads.
Existing pilot and commercial projects demonstrate the feasibility of subsurface storage (Dalkhaa
et al. 2022; Ma et al. 2021). And with the increasing
demand for ­CO2 storage, the application of formation
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Fig. 10 The distribution
map of EOR and ESGR
research in recent years
and the basic mechanism
of EOR: a distribution map
of some EOR projects in
China (Hill et al. 2020); b
map of ­CO2 gas injection
stages in oil reservoirs (Jia
et al. 2019); c distribution
map of ­CO2-ESGR related
research around the world
(Klewiah et al. 2020)
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storage will become more and more extensive. Many
current projects combine ­CO2 storage with enhanced
gas and oil recovery, which provides industrial value
while solving the greenhouse gas problem. However,
under the influence of carbon tax policy, C
­ O2 sources
may be restricted (Nong et al. 2021; Hu et al. 2021;
Kiss and Popovics 2021). As the main underground
­CO2 storage mechanism, formation storage directly
affects the overall ­CO2 storage effect. Future scientific
research will include detailed analysis of geochemical
reactions such as mineral precipitation reactions and
geomechanical effects such as stress–strain relationships. And how this will affect storage capacity, storage efficiency and cap rock integrity.
3.1.2 Residual gas storage
Capillary forces may have an impact on the twophase flow dynamics of the water- ­
CO2 system
when ­CO2 is introduced into subterranean formations like saline aquifers. Remaining gas sequestration is the process of ­CO2 being detached as a
non-wetting phase and trapped in the pores (Altman
et al. 2014), as shown in Fig. 11. However, until an
equilibrium condition is attained, the largely immobile remaining C
­ O2 will dissolve in the formation
fluid through molecular diffusion. The eventual
quantity of C
­ O2 transported and dispersed in the
formation is significantly influenced by residual gas
storage, often referred to as capillary storage, which
in turn influences the efficiency of other storage
mechanisms (Niu et al. 2014). Additionally, residual
Fig. 11 Schematic diagram of residual gas storage (Jayasekara
et al. 2020)
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sequestration is regarded as a crucial mechanism for
storage security. However, capillary sequestration is
the only method that can permanently immobilize
all of the ­CO2 in subsurface plumes, according to
Hesse et al. (2008) and Ide et al. (2007).
As it only pertains to C
­ O2 migration plumes, the
idea of residual gas capture is inextricably tied to
hydrodynamic capture (Wu et al. 2021; Muromachi
2021). This capture process is predicated on the idea
that ­CO2 does not saturate in the plume’s wake as it
migrates. Then, due to the hysteretic nature of relative
permeability, water returns to the pore space. The saturation of ­CO2 rises during injection. By moving laterally from the injection hole to the top of the aquifer
due to buoyancy, ­CO2 creates vertical and lateral flow
paths (Ge et al. 2022; Hamza et al. 2021). When the
injection operation is over, C
­ O2 keeps rising. Water
also replaces ­CO2 at the plume’s trailing edge while
­CO2 is replaced by water at the plume’s leading edge.
As the plume migrated upward, it left behind a trail
of fixed residual ­CO2. Thus, residual gas sequestration mostly occurs after injection ceases, while only
structural sequestration occurs when ­CO2 is injected.
Ni et al. (2019) performed ­
CO2/water displacement experiments on nine core samples with different degrees and types of heterogeneity under reservoir conditions. The experimental results show that
the residual ­CO2 capture capacity decreases with the
increase of porosity and increases with the increase of
heterogeneity. For the nine sandstone samples, porescale trapping mechanisms accounted for 46%–97%
of the remaining captured C
­ O2. Mesoscale capillary
heterogeneous trapping mechanisms account for 3%
to 54% of the remaining trapped C
­ O2. El-Maghraby
and Blunt (2013) conducted coreflood experiments on
Indiana limestone. The amount of captured C
­ O2 was
measured at a temperature of 50 °C and a pressure of
4.2 and 9 MPa using the perforated plate method (see
Fig. 12). The results show that capillary trapping contributes to the fixation of ­CO2 in carbonate aquifers.
Zuo and Benson (2014) demonstrated that the nature
and extent of residual ­CO2 capture depended on the
process by which the C
­ O2 phase was introduced into
the rock. Residual gas disproportionately reduces
the relative permeability of water. And the process
parameterization will help to better simulate the subsurface flow process and prevent gas leakage.
If the volume of the aquifer, the effective porosity of the rock and the residual ­CO2 saturation are
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Fig. 12 Residual gas capture stage diagram (El-Maghraby and
Blunt 2013)
known, the capillary residual storage capacity can be
calculated according to the formula (2) proposed by
Bachu et al. (2007):
Vt = Vtrap × ∅ × Sgr
(2)
Among them, Vt represents the capillary residual
storage volume of ­
CO2 in the aquifer; Vtrap represents the volume of rock that is saturated with ­CO2
and then intruded by water; ∅ represents the effective
porosity of the rock in the aquifer; Sgr represents the
captured ­CO2 after groundwater backflow residual
gas saturation.
The captured ­CO2 saturation Sgr depends on the
actual ­CO2 saturation at the time of backflow and
the hysteresis of the relative permeability of the
­CO2-brine system of the respective aquifer (Luu
et al. 2022). Unlike formation and structural storage, the amount of gas stored in residual gas storage
varies with time. Gas storage increases over time
as the injected ­
CO2 plume spreads and migrates
(Safaei-Farouji et al. 2022; Cui et al. 2021). Therefore, the ­CO2 capture potential of residual gas storage needs to be assessed at a specific point in time.
­CO2 capture potential is generally assessed by mass
rather than volume (Yang et al. 2021). Because the
mass of C
­ O2 that can be stored is obtained by multiplying the storage volume by the C
­ O2 density at site
conditions, which is time and location dependent.
This is also due to pressure and temperature variations along the flow path. And for the same location,
depending on the stage of the storage operation, the
pressure may rise or fall.
A fractal-dimensional capillary model is constructed to address multiphase seepage in unsaturated porous media while taking into account pore
size distribution, capillary cross-sectional area
inhomogeneity, and pore-throat hysteresis effect
(Chen et al. 2020; Sun et al. 2022). The results of
the investigation revealed a clear capillary head hysteresis effect caused by the porous media’s capacity
to retain water. Furthermore, parametric research
demonstrates that pore throats have a significant
impact on fluid migration, particularly during the
non-wetting phase, in addition to being a significant
contributor to the hysteresis effect. In Fig. 13, the
fractal capillary model is displayed. In unsaturated
porous media, increasing the fractal dimension
of the pore area can improve water saturation and
Relative Air Permeability (RAP) while decreasing
Relative Hydraulic Conductivity (RHC). For example, water–oil or hydrocarbon systems in oil and
gas reservoirs are thought to be examples of saturated porous media where immiscible multiphase
flow is difficult to grasp without the aid of the current Water Retention Curve (WRC), RHC, and RAP
models (Elkady et al. 2022; Lasseux and ValdésParada 2022).
A significant storage safety measure is residual
gas storage. The capillary range may potentially
approach 25%, depending on the formation’s porosity and permeability. This is typically between
15 and 25% for a normal reservoir. Different contaminants could be present depending on the ­CO2
source and the capture method, which might potentially have an impact on the capacity as well as
the remaining capture efficiency (Rasmusson et al.
2018). These impurities will not only reduce the
volume fraction of liquid C
­ O2, but also reduce the
density of liquid C
­ O2, thereby increasing the injection pressure and reducing the sequestration capacity. These impurities also increase the interfacial
tension, resulting in less effective residual gas storage (Mintsop Nguela et al. 2021; Ravichandran
et al. 2022). Purification to reduce impurities is also
an important direction for the development of residual gas storage.
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Fig. 13 Fractal capillary model in porous media: a cross-section of a REV with the primary capillary segment (pore); b fluid flow
route and pore-throat capillary; and c pore-throat capillary geometry (Chen et al. 2020)
3.1.3 Dissolving and storing
As mentioned earlier, after injecting ­CO2 into the
formation, due to the influence of density difference,
the ­CO2 will migrate upward until it is captured
by the cap rock at the top of the reservoir. Subsequently, due to molecular diffusion, C
­ O2 begins
to dissolve at the separation interface between the
­CO2 plume and the brine, resulting in the formation
of high-density C
­ O2-saturated brine. This process
is called dissolution and storage (Rochelle et al.
2004), as shown in Fig. 14. Since brine density rises
by 0.1% to 1% as a result of ­CO2 dissolution, the
system becomes unstable and convective mixing
with density-driven natural convection occurs (An
et al. 2021; Jeon and Lee 2021). The ­CO2 dissolving
process is accelerated by convective mixing, and it
can only continue for a very long period by molecular diffusion (Fatah et al. 2022), and over time sink
to the formation’s base, creating a safer ­CO2 storage
(Zhang and Song 2014). The following is the reaction process of ­CO2 dissolved in water:
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Fig. 14 Schematic diagram of dissolution and storage
(Jayasekara et al. 2020)
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⎧ CO (g) ⟺ CO (aq)
2
2
⎪
−
+
⎨ CO2 (aq) + H2 O(l) ⟺ H (aq) + HCO3 (aq)
−
2−
+
⎪ HCO3 (aq) ⟺ H (aq) + CO3 (aq)
⎩
849
(3)
During geological storage of ­CO2, dissolution capture mechanisms are critical for the safe removal of
injected ­CO2. Figure 15 shows ­CO2 transport phenomena leading to solution capture in geological
formations with and without anticline domes (see
Fig. 15a, b). During injection, due to the injection
pressure, the ­CO2 forms a steady plume and moves
upward, spreading laterally under the impermeable
cover (Punnam et al. 2022). As the ­CO2 dissolves
into the water, a thin interface layer slowly begins to
form between the ­CO2 plume and the reservoir water.
Once the interfacial layer becomes thick enough, fluid
channels can occur (Ge et al. 2022; Liu et al. 2021;
Khanal and Shahriar 2022). These channeling effects
frequently result from variations in density between
reservoir water and water with dissolved ­CO2, which
eventually causes diffusive convection in local pore
spaces. Additionally, this results in the formation of
the dissolution fingering geological network pattern
(Punnam et al. 2022; Shafabakhsh et al. 2021). As
a result of gravity pulling down on the denser fluid
during this process, the dissolved ­CO2 fluid travels
lower and comes into touch with fresh water. In the
end, more C
­ O2 dissolves in the underground area as
a result. This convective flow keeps the stratigraphic
domains from dissolving and traps them. Geochemical reactions are sparked by the easy interaction of
dissolved ­CO2 with the nearby rocks ­(CO2-water–rock
interaction) (Li et al. 2021; Park et al. 2021; Niu et al.
2022). Through mineral capture systems, C
­ O2 is subterraneanly trapped. When minerals are captured,
Fig. 15 Diagrammatic representation of how geological features like anticline
domes affect the effectiveness of cleaning and solute
fingering during geological
­CO2 storage (Punnam et al.
2022)
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formation rocks interact with the C
­ O2 and water in
the reservoir and go through a number of geochemical processes. The effectiveness of mineral capture is
directly impacted by the magnitude of the solubility
capture rate, which determines the future of carbon
sequestration technology. In this instance, the phenomena of solution capture is crucial to improving
­CO2 geological storage.
Singh et al. (2018) performed experimental and
modeling studies to demonstrate the feasibility of
injecting brine on top of the C
­ O2 gas cap to accelerate ­CO2 dissolution. Previous studies have shown
that it takes a long time (500 years) for ­CO2 to fully
convect in the brine, and eventually only 8% of the
­ O2 injected into
­CO2 gas cap dissolves. But with C
the brine, the convection seemed to be stronger than
without it (Tang et al. 2021). The stationary C
­ O2 that
remained below the free C
­ O2 bubbles in the event of
­CO2 cap injection into the brine was shown to create
a saturated brine plume that was much greater than
the saturated brine layer formed under no-brine situations (Kou et al. 2021; Tawiah et al. 2021; Wang et al.
2021). This further leads to density instability, which
leads to faster onset of convection, confirming that an
accelerated dissolution process is possible.
The process of ­CO2 dissolution is discovered to be
controlled by formation qualities, particularly permeability, which may be further assessed by dimensionless Rayleigh number (Ra). In porous media, natural convection develops when the Rayleigh number
exceeds 40 (Reun and Hewitt 2021). This also shows
that the Ra value controls the stability of the system,
and natural convection at high Rayleigh numbers
leads to more ­CO2 dissolution. Natural convection
significantly affects mass transfer and ­CO2 sequestration at higher Rayleigh values. The variability of
geological formations has a significant impact on the
quantity of ­CO2 absorbed in addition to the influence
of permeability. Al-Khdheeawi et al. (2018) investigated how heterogeneity affected the solubility of
­CO2. Three alternative flow regimes, including fingered, diverted, and diffuse, can exist depending on
the system’s heterogeneity. In heterogeneous formations, the mass transfer rate of C
­ O2 in the brine phase
is greater. Additionally, in the case of aquifers that are
vertically fractured, increasing the fracture density
encourages the ­CO2 dissolving process (Mahmoodpour et al. 2022; Wang et al. 2022). In general, cracks
can enhance convective mixing in an aquifer because
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they speed up the fluid’s movement and lead it to dissolve more in a shorter amount of time.
3.1.4 Mineral storage
The reaction between dissolved C
­ O2 in water and host
rocks/minerals to form solid carbonates leads to the
formation of minerals, which is known as mineral
sequestration (Farajzadeh et al. 2009). This entrapment is thought to be relatively slow. Because it
occurs during/after solubility trapping, permanently
attaching ­CO2 to rocks in the form of carbonate
minerals is considered the most permanent form of
sequestration. However, this process is slower compared to other storage mechanisms. So the overall
impact could take hundreds of years or more to materialize. The main benefit of mineral sequestration is
that it stops C
­ O2 from existing as a distinct phase,
halting the upward migration of the gas. and encourages the development of stable precipitates (Spycher
et al. 2003). Overall, nevertheless, it would result in
safer ­CO2 storage techniques. C
­ O2 reacts with water
to create a mild acid. Depending on the mineralogy
of the formation, it combines with rock minerals to
produce bicarbonate ions and other cations. The most
basic chemical reactions are as follows (Bachu 2008):
2−
−
−
⎧ HCO3 (aq) + OH (aq) → CO3 (aq) + H2 O(aq)
⎪ CO2−
(aq) + Ca2+ (aq) → CaCO3 (s)
⎨ CO32− (aq) + Fe2+ (aq) → FeCO (s)
3
3
⎪
2+
⎩ CO2−
(aq)
→
MgCO
+
Mg
(aq)
3 (s)
3
(4)
During and after the C
­ O2 injection, all of these
storage mechanisms and procedures change in a
dynamic manner. The safety of these storage systems
and subsequent analysis of the potential leaking of
stored ­CO2 back to the surface provide the biggest
challenges for scientists and researchers. Any geological carbon sequestration project also has to take economic and environmental concerns into account (Li
and Liu 2016; Dean and Tucker 2017). Infrastructure
costs are influenced by the location and complexity of
the storage site, whereas storage costs are primarily
influenced by formation depth, rock characteristics,
the number and position of injection wells (onshore
or offshore), and other variables (Solomon 2007).
Chemical methods fix ­CO2 rapidly (Matter et al.
2016), but uptake is limited. The ­CO2 that can be
stored in the way of C
­ O2 flooding oil and gas is far
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less than the C
­ O2 produced by industry. This also
determines that it cannot be used for carbon emission reduction on a large scale (McCoy and Rubin
2009). However, the dissolution method can absorb
a large amount of ­CO2 and store it stably for a long
time (Gilfillan et al. 2009). The C
­ O2 storage capacity
of saline aquifers is far greater than that of oil and gas
field reservoirs. The IPCC special report also pointed
out that deep saline aquifers are the most promising
option for long-term ­CO2 storage (Raad et al. 2022).
Compared with oil and gas fields and coal seam storage, saline water layer storage has the largest storage
capacity and extensive resource division, and due to
the large injection volume, the scale effect is more
obvious. Therefore, the storage cost per ton is lower
than that of oil and gas fields and coal seams, and it
is the preferred solution for future C
­ O2 storage systems. However, the problem of saline aquifer storage
is also very obvious, that is, its income source is relatively weak, and its commercialization prospect is not
clear (Safaei-Farouji et al. 2022; Fagorite et al. 2022;
Verma et al. 2021). At present, saline aquifer storage
can only rely on carbon trading to obtain certain benefits, and it is difficult to achieve cost coverage. Currently, there are relatively few saline aquifer storage
commercial operation projects, and only a few projects in Australia and Norway are in commercial operation. Therefore, there is relatively little analysis and
research on it, and more theoretical and experimental
progress is needed to promote its commercialization.
3.2 CO2 Geological storage leakage
Carbon dioxide storage aims to store carbon dioxide
safely and long-term in geological sites, so leakage is
the biggest problem it faces. The occurrence of leakage will lead to many effects (Li et al. 2019). It is specifically manifested in the impact on climate change,
impact on groundwater environment, impact on ecological environment, impact on human health, etc
(Gholami et al. 2021). The carbon dioxide geological
storage system includes wellbore systems (injection
wells, production wells and abandoned wells), reservoir-caprock systems and possible faults and fractures (Wang et al. 2023). ­CO2 leaks can occur due to
incomplete storage systems, such as leaks along wellbores in the storage area, leaks along faults, and leaks
along fractured caprock (Chen et al. 2022). Therefore, to ensure long-term and safe storage of C
­ O2, the
851
storage system needs to have good integrity so that
the ­CO2 cannot escape.
The ­CO2 storage process includes three main processes, namely injection-transport-storage. The captured and purified C
­ O2 is injected into the reservoir
through the injection well and continuously migrates
in the reservoir. As time goes by, the ability of the
wellbore system and the reservoir-caprock system
to store ­CO2 continues to decline, and ­CO2 will leak
upwards through the leak path. It has been proved by
many studies that the risk and harm of leakage along
the wellbore are the largest (Celia et al. 2011). The
purpose of studying risk is to correctly assess the
possibility of ­CO2 leakage. The risk of ­CO2 leakage
is mainly caused by the buoyancy of ­CO2 (Gholami
et al. 2021; Lichtschlag et al. 2021; Qiao et al. 2021).
This means that leakage may occur during the injection phase, the migration phase and the storage phase.
The biggest advantage of ­CO2 geological storage
is that it can effectively isolate C
­ O2 in the deep part
of the earth. However, from the perspective of storage safety, this method is not once and for all, and
there are still risks of C
­ O2 leakage and escape (Xiao
et al. 2023). The ­CO2 escaping through the vadose
zone has a density nearly 50% heavier than that of
air. Under the action of gravity and atmospheric flow,
the escaping ­CO2 accumulates along the surface and
in low-lying areas, causing the concentration in local
areas to increase (Amir Rashidi et al. 2022; Zhao
et al. 2022). When the C
­ O2 concentration exceeds
2%, it will seriously affect the human respiratory system. If the concentration reaches 7% ~ 10%, people
will lose consciousness and even cause death. Therefore, escaped C
­ O2 will bring great danger to people or
animals moving around (Kappelt et al. 2021).
The ­CO2 intrusion into the aquifer may also pollute the groundwater quality, induce earthquakes and
other natural disasters, bring negative effects on surface vegetation and soil, and endanger human health.
Since ­CO2 is an acidic gas, when it invades the shallow surface vadose zone, it will expel the original gas
in the soil, resulting in a decrease in soil pH (Zhang
et al. 2019). This low pH and high ­CO2 environment can encourage some organisms to multiply,
causing others to gradually shrink or even disappear
(Lichtschlag et al. 2021). Usually the ­CO2 concentration in the soil should be kept at 0.2%-0.4%. When
the ­CO2 concentration rises to 5%, it will inhibit the
respiration of plants, which will be detrimental to
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their growth. When it rises to 20%, C
­ O2 will turn into
toxic substances, supply soil microbial species and
soil nutrients, and have a serious impact on biological diversity, species complexity, and plant growth
(Molari et al. 2019).
During the ­
CO2 injection and storage process,
factors such as formation pressure fluctuations and
formation water pH reduction can lead to wellbore
cement sheath corrosion and reservoir rock damage,
thereby inducing the risk of C
­ O2 leakage (Shang et al.
2022; Calamita et al. 2021). ­CO2 leakage will not
only cause air pollution, but also seriously threaten
groundwater safety and personal safety (Graziani
et al. 2022). Therefore, it is particularly important
to study the leakage risk of ­CO2 geological storage
system.
The long-term, stability, and safety of ­CO2 sequestration cannot be directly observed because ­CO2 is
stored in several kilometers of underground saline
aquifers or oil reservoirs. This has raised enormous
concerns and anxieties about CCS. Therefore, how to
quickly, accurately and effectively identify whether
­CO2 leakage has become a key link in the current
implementation of this process technology, and environmental monitoring is one of the most widely used
methods. At present, the monitoring objects of carbon
dioxide geological storage mainly include groundwater, soil, atmosphere and ecosystem.
1. Groundwater environment monitoring. Its purpose is mainly to arrange monitoring points at
the ­CO2 geological storage site and its surrounding environmental sensitive points (Roberts and
Stalker 2020). By observing indicators such as
­CO2 concentration, ­HCO3− concentration, ­Ca2+
and ­Mg2+ concentration, conductivity, temperature, pressure and pH value, it is possible to
identify whether C
­ O2 is leaking and the severity
of groundwater pollution (Jeong et al. 2020). In
addition, in order to increase the real-time performance, accuracy and efficiency of C
­ O2 monitoring as much as possible, vertical and horizontal
spatial monitoring systems should also be established.
2. Underground soil monitoring. The monitoring
of the underground soil layer is mainly to identify the leakage of carbon dioxide and its pollution to the underground soil by monitoring the
dynamic changes of carbon isotopes, ­O2, Ar, N
­ 2,
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pH, methane, and humidity in the soil gas (Zhang
et al. 2021; Gupta and Yadav 2020). The specific
method can use portable C
­ O2 soil respiration
measurement system, portable weather station to
carry out multi-indicator observation.
3. Atmospheric ­CO2 concentration monitoring.
Since the concentration of C
­ O2 is higher than that
of the air, it is easy to accumulate in poorly ventilated or low-lying areas (Yang et al. 2019). When
the concentration accumulates to a high level, it
will cause harm to humans and animals. Monitoring points should be arranged in environmentally
sensitive points such as closed wellheads, downwind of dominant winds, and low-lying areas
(Ajayi et al. 2019). Use remote sensing technology and spectral difference to obtain infrared
images of specific spectral bands and abnormal
vegetation data to determine whether C
­ O2 leakage occurs and where it leaks. It is recommended
to monitor once a month. If the deformation rate
is large, intensive monitoring is required (Kumar
et al. 2020).
4. Monitoring of ­
CO2 migration. After ­
CO2 is
injected into the formation, it will migrate and
escape. Therefore, it is necessary to monitor and
analyze the situation of ­CO2 diffusion and escape
(Appriou et al. 2020). At present, it is mainly
through 3D–4D time-lapse seismic, electromagnetic, gravity and other geophysical methods to
determine the time–space space–time distribution
saturation and storage capacity of C
­ O2 fronts in
reservoirs, plugging layers, near-surface formations and wellbores to grasp the migration of ­CO2
after geological storage (Yang et al. 2019; He
et al. 2021). In addition, people also use remote
sensing technologies such as synthetic aperture
radar and differential interferometry to measure
surface deformation to observe surface deformation monitoring before and after perfusion. By
comparing the time baseline, space baseline, season and other data to determine whether surface
deformation occurs. With the rapid development
of Unmanned Aerial Vehicle (UAV) technology,
the atmospheric environment monitoring system based on UAV remote sensing platform has
also begun to be applied (Zhang et al. 2022; Li
et al. 2022). It has the advantages of fast response
speed, small terrain interference, 3D monitoring,
and wide monitoring range. It effectively makes
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up for the shortcomings of the traditional environmental monitoring system. It is one of the
important development directions in environmental monitoring.
As far as the injection phase is concerned, the most
important concern is affecting the mechanical stability of the containment system seals (Ali et al. 2022).
Because the increase in pore pressure may damage
the wellbore cement and open closed fractures and
faults in the caprock near the wellbore. Therefore, it
is necessary to evaluate the risk of wellbore cement
rupture after ­CO2 injection, and the risk of sealing
cracks and opening faults by cap rocks. There are also
many risks that must be assessed for both the transport and storage phases. Example: Risk of leakage of
­CO2 through injection wells (Cao et al. 2021). Risk of
leakage of ­CO2 through abandoned oil and gas wells
(Kurnia et al. 2022). Risk of ­CO2 leaking through
undetected flaws or cracks (Hachem and Kang 2022).
Risk of C
­ O2 leaking through existing faults or fractures (Yue et al. 2022). Increased pore pressure due
to ­CO2 injection could trigger the risk of earthquakes,
etc. (Damen et al. 2006)
Many of the above risks can be effectively avoided
by choosing a suitable storage place. In addition, ­CO2
leakage can also be detected through effective monitoring methods. The Intergovernmental Panel on Climate Change identified areas to monitor, such as the
amount of C
­ O2 injected and stored, possible leaks,
microseismic activity, changes in wellbore pressure,
and geology in reservoirs. ­CO2 leakage can be estimated through risk assessment, as shown in Fig. 16.
That is to conduct qualitative or quantitative analysis of leakage risk through probability calculation or
technical evaluation (Loizzo et al. 2011; Pawar et al.
2014)
Relevant scholars have conducted a large number
of indoor experiments and numerical simulations for
research. Walton et al. (2004) simulated ­CO2 leakage
in the Weyburn area using a fully probabilistic modeling approach. The results showed that the cumulative
leakage of ­CO2 was very small, only about 0.1% of
the total. Shipton et al. (2004) confirmed the problem
of ­CO2 migration through low-permeability faults
to upper aquifers through field testing of ­CO2 reservoirs. They think the faults are pathways for upward
migration of C
­ O2. In addition, some scholars have
established mathematical models of C
­O2 leakage
853
and risk assessment methods. Meyer et al. (2009),
Houdu et al. (2008) based on Darcy’s law two-phase
flow model and degradation kinetics to quantitatively
evaluate the leakage of wellbore for long-term storage
of ­CO2, and conducted numerical simulation research
on wellbore injection of supercritical ­CO2. Tao et al.
(2010) extended the leakage rate model of natural gas
production wells to the ­CO2 leakage model, providing a new idea for the mechanical-chemical coupling
model of ­CO2 leakage. Checkai et al. (2012) quantifies the leakage risk of the wellbore through the distribution of leakage channel permeability, which further
improves the reliability of leakage risk assessment.
Compared with other technologies, the biggest
advantage of CCS is that it can store C
­ O2 in stable geological structures for a long time. However,
in the actual geological storage process, there is a
risk of leakage of stored ­CO2 due to changes in the
geological environment and the impact of human
activities (Yu et al. 2022; Lichtschlag et al. 2021).
Moreover, due to various problems such as special
marine geological conditions and a relatively complex ecological environment, the risk of ­CO2 leakage is much higher than that in other regions. The
injected ­CO2 may be released through undiscovered faults, fractures, abandoned wells, and ruptured cap rocks. The released C
­ O2 may dissolve in
groundwater, pollute the groundwater environment,
and even cause surface uplift, earthquakes, etc.
(Gholami et al. 2021; Esposito et al. 2021). When
it leaks into the shallow formation, it may change
the soil environment, affect the growth and development of vegetation, and destroy the ecological
environment. Leakage into the atmosphere may
affect human health (Zhang et al. 2022). Therefore,
while developing CCS technology, it is also necessary to study the environmental impact of ­CO2
leakage that may occur during the storage process.
The factor restricting the development of carbon
sequestration technology is not the carbon sequestration potential, but the certain risks in the longterm safety and reliability of the technology. And it
is difficult for enterprises to choose a suitable storage location. Currently, the global onshore theoretical storage capacity is 6–42 trillion tons, and the
seabed theoretical storage capacity is 2–13 trillion
tons. According to McKinsey research, the total
storage capacity of onshore saline aquifers is 50–70
times the total demand for CCS (Zhang et al. 2022).
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Fig. 16 a Potential migration leak sites for various
features of C
­ O2 geological
storage; b simulated risk
scenarios for ­CO2 leaks in
the next 1000 years (Pawar
et al. 2014)
As the last option of CCS, the storage potential of
saline aquifer is relatively large in the long-term
goal of CCS (Postma et al. 2022). However, the
regulations and reporting process for high-concentration ­CO2 storage are complex, and the stability
of geological structures needs to be considered. Not
all proven geological structures with storage capacity can be successfully stored in the end, and further
exploration and evaluation will still take time and
cost, otherwise carbon leakage may occur.
Leakage monitoring is the basis for analyzing and
managing the risk of C
­ O2 geological storage, and
its theoretical research is helpful for the design of
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monitoring well layout (Fawad and Mondol 2021).
At present, the monitoring of several large-scale storage projects in the world adopts three-dimensional or
four-dimensional seismic monitoring of ­CO2 plume
(Waage et al. 2021). However, the disadvantage
of plume monitoring is that it is not predictable in
advance, and its significance is limited from the perspective of leakage prevention. Because the range of
reservoir pressure disturbance caused by ­CO2 injection is much larger than that of ­CO2 plume diffusion,
monitoring the fluid pressure and geochemical characteristics of the overlying formation has been proved
to be an effective means of leak detection (Caesary
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et al. 2020). Since the saline water in the reservoir is
displaced by the injection of C
­ O2, it first leaks to the
overlying aquifer along the leakage channel, so the
signal of C
­ O2 leakage can be obtained in advance by
monitoring the pressure change of the overlying aquifer (Ju et al. 2022).
There are many analytical solutions to detect
­CO2 or reservoir saline water leakage by monitoring pressure changes (Fawad and Mondol 2022). The
basic idea of the research is to use analytical methods to establish the correlation between fluid pressure changes and leakage rates, so as to quantitatively
evaluate the possible leakage characteristics of reservoir fluids. These methods are not effective in monitoring caprock diffusion leakage unless the caprock is
very permeable. Other scholars use numerical simulation methods to study the C
­ O2 leakage monitoring of
­CO2 geological storage projects, and analyze the sensitive factors affecting leakage and pressure changes
(Dean et al. 2020; Das and Hassanzadeh 2021).
However, maintaining the integrity of the storage
system is not that simple. During the process of carbon dioxide injection and sequestration, due to the
change of temperature and pressure conditions, the
cemented interface will debond in the wellbore (Li
and Zhiwei 2021). The cap rock will be damaged by
hydraulic fracturing. After injection, carbon dioxide
has a strong corrosive effect under formation conditions, and the microstructure and physical properties
of the wellbore and caprock will undergo changes
that are not conducive to storage during the long-term
storage process (Thanasaksukthawee et al. 2022).
Potential carbon dioxide leakage pathways are created, thereby compromising the integrity of the storage system. To this end, it is necessary to clarify the
changing law of the integrity of the storage system
during the process of ­CO2 injection and storage to
ensure the safety of storage (Miocic et al. 2019).
In addition, there are two other points that should
not be ignored regarding the leakage of ­CO2 through
the cap rock (Zhu et al. 2021). First, the permeability
of the cap rock itself is relatively good, and the storage conditions are poor, so that ­CO2 seeps and leaks
in the fracture network (Jeong et al. 2019). At the
same time, diffusion leakage occurs in the caprock
matrix. Second, considering the high reservoir pressure, the time span of ­CO2 leakage is relatively long.
Carbon sequestration technology does not produce additional economic benefits, and there are
855
early exploration costs and post-monitoring costs, so
the relative cost is relatively high. Based on current
state of the art and considering monitoring costs for
20 years after shut-in. Onshore saline aquifer storage costs about 60 ¥/t C
­ O2. The storage cost of seabed saline aquifer is about 300 ¥/t C
­ O2. The storage
cost of depleted oil and gas fields is about 50 ¥/t C
­ O2.
The above costs do not take into account the upfront
exploration costs. For enterprises, the cost of carbon
sequestration technology is relatively high, and it
does not have economic value, so policy incentives
are needed.
To sum up, there is a risk of leakage in the process of ­CO2 flooding and storage, which will affect
the ecological environment and human life, and even
threaten life. Therefore, it is necessary to comprehensively use multidisciplinary knowledge and technical
means such as geophysics, geology, reservoir sedimentology, and geochemistry to monitor the integrity
of ­CO2 storage bodies, C
­ O2 migration characteristics,
leakage pathways and consequences. It is necessary
to comprehensively evaluate the durability, safety
and effectiveness of the storage project by adopting
systematic response strategies such as risk assessment, scientific site selection, monitoring and early
warning, and emergency remediation. Establish a set
of operating mechanisms suitable for the complete
life cycle of ­CO2 geological storage projects, so as
to minimize the risk probability or degree of hazard
of geological environmental disasters that may be
induced by ­CO2 leakage.
4 Transport of ­CO2
CO2 transportation is the intermediate link of CCS
capture compression, transportation and storage utilization, and the optional transportation methods at
this stage include pipeline transportation and transportation by various means of transportation (Zhang
et al. 2021). As shown in Table 5, at present, pipeline transportation and tanker transportation are the
main ones. Among them, there are four main modes
of ­CO2 pipeline transportation, namely, gaseous ­CO2
pipeline transportation, liquid ­CO2 pipeline transportation, supercritical ­CO2 pipeline transportation and
dense phase ­CO2 pipeline transportation. Due to the
complex physical properties of C
­ O2, the phase state
is easily affected by temperature and pressure. Only
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Shipping
Railway
Highway
Continuous and stable transporta- Large investment, high allowable
cost
tion, little external influence,
high reliability, economical and
environmental protection
Small batch, non-continuous
Small scale, low investment, low Small transportation volume,
transportation
risk, flexible transportation
short distance, high freight,
poor continuity
Railway transportation and manIt is used when the transportation The transportation volume is
agement and scheduling are
large, the transportation disvolume is large, the transportarelatively complicated, limited
tance is long, and the reliability
tion distance is long, and the
by railway lines, require related
proofreading
pipeline transportation system
distribution equipment, and
has not yet been built
high transportation costs
Large investment, high operating
Large-scale, ultra-long-distance
Large transportation volume,
costs, need related distribution
or ocean transportation
flexible destination, avoiding
equipment, greatly affected by
underground drinking water
climate and ports
pollution
Suitable for large capacity, long
distance, consistent with stable
one-way transportation
Disadvantages
Pipeline
Advantages
Applicable conditions
Mode of
transportation
Table 5 Comparison of various ­CO2 transport routes (Hasan et al. 2015; Ringrose 2018)
Rich experience, the United States
has more than 5000 km of C
­ O2
transportation pipelines
There are short-distance trial pipelines in various countries
There is currently no precedent for
transportation in the world
Small ships put into operation
Mature technology
Mature technology
Mature technology
Mature technology
Technology maturity Application
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when ­CO2 is in supercritical/dense phase state, its
state is relatively stable (Godil et al. 2021). Moreover,
it has the characteristics of low viscosity of gas and
high density of liquid, which is more conducive to
transportation. According to the simulated data, with
the increase of transportation volume and transportation length, the total investment of pipeline transportation increases continuously, and the cost of C
­ O2
transportation per unit length and unit transportation
decreases gradually. In addition, through calculation and analysis, it can be seen that the investment
and cost of supercritical transportation are the lowest
for long-distance transportation (Anwar et al. 2021;
Ülker et al. 2021). The advantages of supercritical
conveying are more obvious when the conveying volume and conveying length increase. Generally speaking, due to the influence of factors such as terrain and
the pipeline itself, the pressure along the pipeline
changes all the time. In order to make the C
­ O2 pressure of the self-capture system meet the requirements
of the pipeline transportation system and avoid pipeline rupture caused by two-phase flow due to insufficient pressure, it is necessary to pressurize the pump
station to reach the minimum operating pressure of
the pipeline, and then make it flow along the pipeline go ahead (Barta et al. 2021; Jarvis and Samsatli
2018). The end of the pipeline is usually closer to the
place where the C
­ O2 is stored, and specialized personnel will store the ­CO2. In addition, the airtightness
and corrosion resistance of the pipeline also need to
be considered (Vree et al. 2015).
In most cases, transportation costs are well under
a quarter of the total cost of a CCS project. Transportation distance and C
­ O2 flow are the main factors affecting the cost of carbon transportation.
Among them, the transportation cost increases with
the increase of the distance in a power function, and
decreases with the increase of the flow in a power
function (Fan et al. 2019; d’Amore et al. 2020). For
pipeline transportation, it is also affected by factors
such as pipeline diameter, pipeline material type,
geographical location, planned life of the system,
and whether it is based on idle natural gas pipelines
(Yang et al. 2020; Handogo et al. 2022). In terms of
unit transportation cost, the cost of tanker transportation is the highest, and the cost of ship transportation
(inland ships) is the lowest. However, compared with
maritime ship transportation, the unit cost of submarine pipeline transportation decreases significantly
857
with the increase of transportation scale. It has more
cost advantages within a certain transportation distance (650 km) (Mahmoud and Dodds 2022; Lu et al.
2020).
CO2 pipeline transportation can learn from the
experience of natural gas pipeline network transportation, and is also suitable for scenarios with large
amounts of C
­ O2 and long-distance transportation.
Although the cost of pipeline transportation is high,
this method has also been widely used in the actual
deployment of CCS. Many scholars have also done
research on pipeline transportation of supercritical
­CO2 (compression pressure > 8 MPa and above) (Liu
et al. 2019; Tian et al. 2017). Supercritical ­CO2 has
high density, low viscosity, good fluidity, strong diffusivity, and good dissolution characteristics. Therefore,
supercritical ­CO2 has good advantages in terms of oil
displacement and storage (Al-Abri and Amin 2010).
A lot of practical experience shows that supercritical
or dense-phase transportation is the safest and most
economical way for long-distance and large-scale
­CO2 pipeline transportation, as shown in Fig. 17.
When the annual ­
CO2 transportation volume is
greater than 1 million tons, supercritical C
­ O2 pipeline
transportation is the most economical and safest ­CO2
land transportation (Li et al. 2016). The supercritical form of transport can not only reduce electricity
consumption, but also reduce energy costs (Dongjie
et al. 2012; Wei et al. 2016). Because the temperature
and pressure of most ­CO2 storage sites are greater
than the critical temperature and critical pressure of
­CO2, ­CO2 is injected into the storage site and stored
in a supercritical state. Therefore, for large-scale
­CO2 transportation and storage projects, supercritical
­CO2 transportation can effectively reduce the cost of
repressurization in the storage area, thus making the
whole process more economical (Wang et al. 2019;
Cui et al. 2019).
Tanker transportation refers to the transport of captured ­CO2 by tanker to a storage location, usually in
the ocean. Tanker transportation has limited capacity and cannot transport C
­ O2 on a large scale, so it is
suitable for small volume and medium distance situations. Since the transportation link can learn from
the experience of natural gas storage and transportation, the relevant technology is relatively mature (Al
Baroudi et al. 2021). The research on the CCS transportation link is mainly to study the safety issues such
as the corrosion of the pipeline itself and the leakage
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Fig. 17 Economic comparison of submarine pipeline transportation and ship transportation
during the transportation of ­CO2 in the supercritical
state (Peletiri et al. 2018; Xiang et al. 2012).
Achieving high-efficiency and low-cost transportation of captured carbon dioxide to storage sites has
increasingly become a concern of various countries.
The selection of the specific transportation method
needs to comprehensively consider the location and
distance of the transportation starting point and the
terminal point, the transportation volume of C
­ O2, the
quality of ­CO2, the temperature and pressure of ­CO2,
the cost of transportation process, and transportation
equipment (Mazzoldi et al. 2011).
At present, the global large-scale ­CO2 ship transportation is still in the development and test stage,
and small ships are used to transport cryogenic liquid ­CO2, and no large ships have participated in ­CO2
transportation (Aspelund et al. 2006). The oil and gas
transportation industry has commercialized the transportation of liquefied petroleum gas (LPG) and liquefied natural gas (LNG) by ships. Japan, Norway, etc.
are referring to the concept and experience of LPG
and LNG transport ships to develop large-scale ships
for large-scale C
­ O2 transportation (Xiang et al. 2017).
According to the experience of transporting LPG and
LNG, unloading on shore is relatively simple. However, neither offloading C
­ O2 to offshore platforms
prior to processing and injection, nor injecting ­CO2
directly into storage sites after onboard treatment has
not been validated and the processes are still immature (Cole et al. 2011).
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Oil and gas transport ships can be divided into
three types according to different temperature and
pressure parameters: low temperature type, high pressure type and semi-refrigerated type. Cryogenic ships
keep oil and gas in liquid or solid state through low
temperature control under normal pressure (Tan et al.
2016). High-pressure ships keep oil and gas in a liquid state through high-pressure control at room temperature. Semi-refrigerated ships keep oil and gas in a
liquid state under the combined action of pressure and
temperature (Geske 2015). Existing C
­ O2 ship transportation generally adopts semi-refrigerated ships,
with a pressure of 1.4–1.7 MPa and a temperature
of − 25 °C to – 30 °C. The capacity of existing small
­CO2 transport ships is about 850–1400 tons, which
cannot meet the needs of large-scale application of
CCS, and it is necessary to develop large-capacity
­CO2 transport ships (Collie et al. 2017). When C
­ O2 is
stored or utilized at sea, the transportation of C
­ O2 by
ship is flexible and convenient, which can effectively
reduce transportation costs. If there are multiple offshore storage facilities and mooring devices that can
­ O2 is greater.
receive ­CO2, the flexibility of shipping C
In recent years, coastal countries such as Norway,
Japan, and South Korea have proposed to store ­CO2
at sea, and shipping ­CO2 is becoming the most important option, but the transportation network has not yet
been fully established (Jung et al. 2013).
The acquired ­CO2 products should be in dense liquid phase, supercritical phase, or solid phase to lower
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transportation costs and improve transit volume. The
cheapest form of transportation is via pipeline. If the
yearly pipeline traffic volume exceeds 1000 × ­104 t,
the transportation cost is 2–6 $/(100 kmt), according
to official APEC figures. However, the transportation
of pipelines is only appropriate under limited circumstances, particularly to address the issues of corrosion
and leaking while in transit (Martynov et al. 2016).
Only situations with high transmission volume and
short distance are appropriate because of the initial
investment’s comparatively high cost. The cost of
moving a car tanker is the largest; it may cost up to
17 $/(100 kmt), but it is more adaptable and suited
for situations requiring a limited amount of moving.
Compared to automotive tank cars, railroad transportation is less expensive and offers a greater amount of
cargo than tank cars provide. However, it is dependent on pre-existing railroad infrastructure; otherwise,
the initial expenditure is considerable. Ship transportation volume is more than that of vehicle tanker
transportation and equal to that of rail transportation.
However, it is expensive and dependent on rivers
or seas. ­CO2 storage equipment must be resistant to
extreme pressure or temperature changes. One advantage of solid-phase C
­ O2 is that it is easy to carry;
however, it also has a wider variety of uses and can
act as a cold source during cold chain transportation.
However, making solid-phase ­CO2 also necessitates a
substantial initial outlay (Zhang et al. 2006).
The triple point pressure of ­CO2 is 0.52 MPa, and
the temperature is − 56 °C; the critical point pressure
is 7.38 MPa, and the critical temperature is 31.1 °C.
The pressure drop of multi-phase flow in the pipeline
is large, and ­CO2 is easy to change phases and cause
pipeline cavitation, so C
­ O2 in pipeline transportation is single-phase (Aursand et al. 2013). According to the phase state of transported C
­ O2, pipeline
transportation can be divided into four transportation
modes: gas phase, cryogenic liquid state, dense phase
(between liquid and supercritical) and supercritical phase. There are also big differences in pipeline
transportation of C
­ O2 in different states (Witkowski
et al. 2013). The larger the C
­ O2 transportation volume and the larger the pipe diameter, the lower the
unit investment. When the transportation volume is
the same, the pipeline unit investment from high to
low is gas phase, cryogenic liquid phase, dense phase,
and supercritical phase (Knoope et al. 2013).
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The cost of ­CO2 pipeline transportation is one of
the important links affecting the successful implementation of CCS projects. The main influencing factors of transportation cost are ­CO2 transportation volume, diameter, length and material of pipeline, etc.
(Onyebuchi et al. 2018). At present, there are many
researches on the cost of ­CO2 pipeline transportation
(Lu et al. 2020; Peletiri et al. 2018; Ansaloni et al.
2020). The technical and economic model process
of ­CO2 pipeline transportation is shown in Fig. 18.
Dahowski et al. (2012) and Man et al. (2014) calculated the cost of C
­ O2 transportation and geological
storage in China to be in the range of 2–8$/t. However, the ­CO2 pipeline transportation cost model is
based on US natural gas pipeline cost data and cannot
accurately estimate pipeline transportation costs in
China (Zhao et al. 2014). Moreover, the cost of pipeline transportation varies in different environments.
Existing cost models in the United States and the
European Union cannot assess pipeline transportation
costs in the Chinese market (Bai et al. 2013). Therefore, others Dongjie et al. (2012), Wei et al. (2016)
have proposed calculation methods for C
­ O2 pipeline
transportation costs in China. Gao et al. (2011) constructed a model including total pipeline capital cost,
annual O&M cost and normalized cost. However,
the cost of the pipeline is obtained by multiplying
the weight of the pipeline steel and the price of the
steel, and there are relatively few links to consider.
Liu and Gallagher (2011) established a techno-economic model based on Chinese pipeline design standards and codes. The results show that transportation
costs depend on the amount of ­CO2 transported and
the length of the pipeline. When the pipeline length
is 100 km, the capital cost of pipeline construction
is between 18 million $ and 102 million $, and the
standardization cost of transportation is 1.84–3.06
$/t ­CO2. Dongjie et al. (2012) used a hydrodynamic
model to economically optimize China’s ­CO2 pipeline transportation system to calculate unit pipeline
transportation costs. The results show that when the
annual CO2 transportation volume is 1-5Mt and the
transportation distance is 100–500 km, the unit ­CO2
transportation cost is 0.015–0.09 $/t/km. Among
them, the power consumption cost of the transportation pipeline compressor accounts for more than
60% of the total cost. Wei et al. (2016) established a
technical and economic model of pipeline transportation to make a more detailed estimate of the cost
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Fig. 18 Schematic flow
chart of CO2 pipeline transportation technology and
economic model
of specific CO2 pipeline transportation projects in
China. The results show that the normalized cost of
pipeline construction projects depends heavily on the
­CO2 transport flow. When the annual ­CO2 transportation volume is between 350,000 and 1 million tons,
the quasi-transformation cost of a 100 km transportation pipeline is 0.83–11.7$/t ­CO2.
On land, road tank cars and railway tank cars
are the most important ­
CO2 transportation methods besides pipeline transportation. The tank truck
transportation technology is relatively mature, but
its application range is narrow, and it is only used in
small-scale oil flooding experiments and food processing fields. There are mainly three loading and
transportation methods: dry ice, cryogenic insulated
containers and non-insulated high-pressure bottles
(Gao et al. 2011). The transportation capacity of the
road tanker is about 2–30 tons, the transportation
pressure is 1.7–2.08 MPa, and the temperature is
– 30 °C ~ -18 °C. Railway tank cars can realize longdistance and large-scale transportation of C
­ O2. The
­CO2 capacity of one tank car is about 50–60 tons,
and the transportation pressure is about 2.6 MPa.
The transportation of cryogenic liquid ­CO2 requires
additional compression (cryogenic rectification) cost,
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even if the transportation cost is reduced, the cost
of the whole chain CCS is relatively high. Road and
rail tanker transport is less economical than pipeline
transport (Smith et al. 2021). High-pressure tank
cars have advantages over low-pressure tank cars,
and low-pressure refrigerated tank cars have advantages over low-pressure non-refrigerated tank cars.
Cost factors and storage and transportation conditions
(storage and loading and unloading are troublesome
and take up a lot of time) limit the development of
road tanker and railway tanker C
­ O2 transportation
(Gu et al. 2019). With the exception of small-scale,
short-distance CCS opportunities and pilot projects,
road and rail tanker transport is unlikely to play a significant role in large-scale CCS deployment (Lin et al.
2016).
Pipeline transportation is the most cost-effective
way to transport carbon dioxide in the CCS technology chain. Although the cost of laying pipelines is
high, the service life is long. The maintenance cost is
low, it can withstand high pressure, and the loss rate
of the transportation medium is low. According to
research, nearly 8000 km of C
­ O2 pipeline transportation network has been built in the world (Huang et al.
2021). Developed countries such as the United States
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and the United Kingdom have more than 6,000 km of
transportation pipelines due to their early research.
The transportation pressure exceeds 10 MPa, and the
transportation capacity exceeds 100 million tons per
year and increases year by year. China’s technology
is immature, there are few pipeline laying projects,
the transportation capacity of long-distance pipelines is insufficient, and corresponding standards for
long-distance pipelines have not yet been formed
(Wang et al. 2022). According to the IEA’s assessment, the number of ­CO2 pipelines will increase rapidly year by year, and it is estimated that by 2050, the
total length of ­CO2 pipelines in the world will reach
95,000–550,000 km (Page et al. 2020).
When considering the choice of ­CO2 transportation
mode, it should be considered based on various factors such as enterprises, countries, investment costs,
and industrial distribution (Dongjie et al. 2012). As
shown in Fig. 19, ­CO2 pipelines in the United States
are mainly distributed in the central and southern
regions where the natural gas industry is developed.
For Russia, China, and the United States, which have
vast land areas, the cost of building pipelines cannot
be borne by individual companies, and more often
they rely on government loans or joint construction of
multiple companies. Considering the geological differences, it is necessary to develop multiple modes of
transportation and expand the scope of transportation.
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For countries with a relatively small land area,
the ­CO2 transportation method can be determined
according to the amount of carbon emissions. For
enterprises with large carbon emissions, separate
collection and transportation pipelines are more
investment than other transportation methods. ­CO2
transportation methods are time-sensitive. With the
development of emission reduction policies, a large
number of enterprises consider the implementation
of carbon negative emissions and new energy alternatives, and rationally recycle C
­ O2 or replace fossil
fuels. In the future, most companies will use green
new energy for production and power generation, and
a small number of companies will use carbon-negative emission technologies to reduce emissions. The
transportation pipeline will be transformed into clean
energy transmission, and it can only be used as a transitional bridge. This requires more complex upgrades
to the pipelines that deliver it. Therefore, appropriate
transportation methods should be selected reasonably
according to the progress of CCS technology in various countries.
The most common and most difficult problem to
solve during pipeline transportation is pipeline leakage. Due to mechanical damage, material defects,
pipeline corrosion and other reasons, the pipeline
breaks and the medium leakage spreads (Farhadian et al. 2023). Pipeline leakage of ­CO2 will cause
Fig. 19 Existing ­CO2 transportation pipelines in the United States as of 2018 (Edwards and Celia 2018)
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serious hazards and consequences, not only causing
serious damage to the environment near the pipeline,
but also causing heavy casualties to people and animals in places with high ­CO2 concentrations (Quynh
Hoa et al. 2019).
For pipeline transportation, the most suitable
transportation state should be selected according to
the geographical location of the pipeline, transportation capacity, transportation distance, and public
safety. Supercritical or dense-phase transport options
have lower investment (Knoope et al. 2014). Small
pressure drop for long-distance transportation. High
tolerance to impurities. No liquefaction required. The
cost of capture purification and compression is low.
For large-scale transportation, under the same pipe
diameter, the transportation capacity of the supercritical or dense phase transportation scheme is large. Its
transportation cost is low, and it is suitable for longdistance, large-volume, and sparsely populated situations (McCoy and Rubin 2008).
Under low pressure conditions, gaseous C
­ O2 transport is bulky and uneconomical to transport over long
distances. However, in densely populated areas, the
pressure of gas phase transportation is low, which
meets the safety requirements of existing laws and
regulations. If the dense-phase transportation scheme
is adopted, a large number of stop valves and valve
chambers need to be installed to ensure safety, or a
large number of demolition is required by laws and
regulations to control the safety distance. This will
increase the cost and difficulty of pipeline transportation. Therefore, under the conditions of existing laws
and regulations, gas-phase pipeline transportation
is more suitable for short-distance, low-volume, and
densely populated situations.
5 CCS economic evaluation
5.1 Economic evaluation of C
­ O2 storage
One of the important obstacles for CCS technology
from the project demonstration stage to the largescale deployment and implementation stage is its
huge investment and operating costs. Both the CCS
technology system itself and the derivative application of a single sub-technology have become the
focus of concern and research by scholars and project
owners.
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There are many studies on the estimation of DSF
storage and EOR storage potential (Hill et al. 2020;
Wei et al. 2022; Núñez-López and Moskal 2019), but
few scholars have carried out technical and economic
evaluation of storage. Among them, Fukai et al.
(2016) used a cost–benefit analysis model to assess
the economic viability of a ­CO2-enhanced oil recovery project in Ohio. When the crude oil price is 70$/
bbl, the income of oil fields is low, and some oil fields
even suffer losses. When oil price is 100$/bbl, EOR
technology is economically feasible.
Taking the overall economics of CCS technology as a potential choice in the US power generation industry from 2005 to 2045 to analyze and study
(Wise et al. 2007), the impact of four different natural
gas price and ­CO2 emission scenarios on the application of CCS technology in the US power industry
is compared. Estimate the basic demand of the future
power industry based on the existing power capacity
and newly invested power equipment. There are four
important viewpoints in the research: (1) Low-carbon
policies can stimulate ­CO2 emission reduction, which
plays an important role in the expansion of CCS
technology. (2) If there is not enough carbon price
to stimulate the development of CCS technology, the
significance of long-term carbon emission policy is
that higher fuel prices will lead to an escalation of
­CO2 emission pressure. (3) The main indicator for the
development of CCS technology in the power industry in a region is not based on whether the region
has greater C
­ O2 storage capacity and storage potential, but whether CCS technology is used as the main
method of carbon emission reduction. (4) Although
CCS technology has low-cost and even profitable
opportunities in some applications, the condition for
this to happen is that the carbon price is 20$ /t.
In terms of individual sub-links in the CCS system, scientists also conduct research from the perspectives of capture modules, transport modules and
storage modules. Rubin et al. (2007) conducted a cost
analysis on four types of pulverized coal power plants
combined with post-combustion capture, natural gas
combined cycle power plants combined with postcombustion capture, integrated coal gasification combined cycle power plants combined with pre-combustion capture, and pulverized coal combined with
oxyfuel combustion capture. Abadie and Chamorro
(2008) consider two stochastic scenarios, the Spanish large-scale electricity market and the European
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Emissions Trading Price (ETS) ­CO2 capture subsidy,
in which they analyze coal-fired power plants combined with carbon capture investments in Europe.
Broek et al. (2009) assessed the future development
of power plants incorporating carbon capture using
the concept of cost variables and performance curves,
as shown in Fig. 20a. It also provides insight into the
energy loss of power plants combined with carbon
capture, capture efficiency and whether future power
plants can be utilized.
Carbon trading price is a key factor affecting the
development trend of CCS technology in the iron
and steel industry. The average carbon price in the
Chinese market in 2020 is 6.3 $/t ­CO2. The 2019
China Carbon Price Survey Report predicts that
the carbon price will reach 17.1 $/t C
­ O2 in 2030
and 27.4 $/t ­CO2 in 2050. Some agencies estimate
that the cost of carbon capture is 75$/t ­
CO2 in
2020, which will be reduced by 20$/t ­CO2 in 2030.
Through different transportation methods such as
pipeline or road transportation, the carbon transportation expenditure fluctuates between 0.04$/t
­CO2 per kilometer and 0.2$/t ­CO2 per kilometer.
Knoope et al. (2013, 2014) developed an economic
model of C
­ O2 pipeline transport. The model takes
into account different ­CO2 physical phases, different
pipeline steel grades, the latest steel pipe materials,
and pipeline construction costs. Through the analysis of model calculation results, it can be seen that
under the same topographical conditions, the gas
phase transportation of CO2 in a simple pipe network is the most economical transportation method,
as shown in Fig. 20b. However, when the injection
pressure is required to be greater than 8Mpa, it is
more economical to transport ­CO2 in a liquid state
than in a gaseous state. In a certain period of time
in the future, if the amount of ­CO2 cannot be captured in a timely manner, it is relatively uneconomical for relatively large pipeline transportation. However, relative to the situation where the amount of
­CO2 that can be obtained in a short period of time
will suddenly increase, relatively large pipelines can
be considered.
Buscheck et al. (2012) studied pressure management strategies for ­
CO2 storage regional reservoirs, providing an analysis of the trade-off between
Fig. 20 a 2050 technology component cumulative capacity
projections (Broek et al. 2009); b breakeven vs. distance relationship between pipeline transport of liquid and gaseous C
­ O2
(Knoope et al. 2014); c well spacing and d distribution impact
on costs (Eccles et al. 2012)
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reservoir pressure relief/improved CO2 injectability
and delayed CO2 breakthrough point in the reservoir. Eccles et al. (2012) conducted an analysis of
the impact of the layout (well spacing, well pattern)
of injection wells and production wells in geological
storage areas on cost and environmental footprint, as
shown in Fig. 20c. Cihan et al. (2015) obtained the
optimal well spacing layout of injection wells and
production wells in the ­
CO2 storage area through
Constrained Differential Evolution (CDE), which
solved the pressure management problem of C
­ O2 geological storage areas.
The above studies are discussed based on the transport storage and geological storage of C
­ O2. Although
some economic and feasibility analyzes have been
carried out. But there are still some problems. The
mismatch between transportation and storage conditions has caused storage companies to perform secondary compression and cooling of ­CO2 gas, and the
costs incurred should be considered when comparing
transportation costs. There are no clear requirements
for the purity of ­CO2 used for oil flooding and subsea
storage. If standard ­CO2 transport requirements were
established, it would limit the source of its acquisition. According to the needs of different industries,
CCS technology should be diversified. Under the
current circumstances, improving the ­
CO2 capture
purity after oxyfuel combustion will increase the
operating cost of the enterprise. This measure is not
conducive to the development and promotion of CCS
technology.
Large-scale deployment of CCS projects is the
result, and safe and economical large-scale deployment is the purpose. In order to realize the safe and
economical large-scale deployment of CCS projects,
it is necessary to solve the systematic scientific problems in the early stage and process of large-scale
deployment of CCS projects.
1. First of all, it is necessary to ensure that the CCS
project is safe and feasible. The premise of largescale deployment of CCS projects is that it is safe
and feasible. In recent decades of development,
CCS technology itself has basically matured, and
safety and feasibility are one of the requirements
for large-scale deployment of CCS projects (Read
et al. 2019; Stigson et al. 2012). A series of policies and regulations need to be issued to effectively reduce and control various environmental
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and safety risks that may arise in the entire process of CCS projects. Scientific site selection of
­CO2 storage sites is a key step to ensure the safety
and feasibility of geological utilization and storage (Rock et al. 2017). The scientific location
selection of CO2 storage sites is based on the
evaluation results of the storage sites and their
storage capacity. Therefore, to ensure the safety
and feasibility of a CCS project, it is necessary to
conduct a scientific assessment of the storage site
selection and its storage capacity.
2. Promoting a safe and feasible global CCS project
implementation path is economically optimal.
What needs to be done next is to promote a safe
and feasible global CCS project implementation path that is economically optimal (Durmaz
2018). There are huge differences in the cost of
­CO2 capture from various emission sources and
the storage cost of each storage site (sink). At
the same time, the distances between different
sources and sinks are not the same, that is, there
are differences in transportation costs (Karayannis et al. 2014). In this context, all emission
sources and storage basins in each region will
be randomly combined into countless possible
CCS projects with different costs. Among these
potential CCS projects, there is an economically
optimal (minimum cost) implementation path
to realize carbon capture utilization and storage
from all emission sources. Exploring this path
requires systematic planning of all safe and feasible source-sinks (Li et al. 2018).
3. To ensure the smooth implementation of CCS
projects. Based on the optimal implementation
path of the global CCS project economy, national
or regional administrative units can conduct
policy intervention or overall regulation of CCS
project deployment (Fan et al. 2018). But specifically, the implementation of CCS projects is
a kind of investment behavior of enterprises to
cope with climate change. The implementation of
CCS projects will inevitably affect the operating
economy of the entire enterprise.
Whether the CCS project is successfully implemented
depends on the economic feasibility of the project
judged by the application of scientific investment
decision-making methods (Kapetaki et al. 2017).
CCS project investment is faced with multiple
uncertainties in costs, benefits, and policies. The
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uncertain investment environment, which makes
investors face a dilemma, is one of the key factors
behind the slow development of CCS projects
(Wang and Du 2016). In an uncertain investment
environment, we need to construct an investment decision-making method that fully considers investment uncertainty, and make investment
decisions on this basis.
4. Promote the optimal operation of CCS projects.
Project investment decision-making determines
the economic feasibility of the project, and operation decision-making pursues the economic optimization of project operation (Ming et al. 2014).
After successful investment, CCS project investors will pay attention to its operating environment to optimize the operation of the project
(Ashworth et al. 2012). Uncertainty exists not
only in the investment stage of CCS projects, but
also in the operation stage of the projects. How
can a CCS project achieve the economic optimum of operation under an uncertain operating
environment? This requires us to construct a scientific decision-making method and make operational decisions on this basis.
To sum up, in order to solve the scientific problems
in the early stage and process of large-scale deployment of CCS projects, and promote its safe and economical large-scale deployment, it is necessary to do
a good job in storage site selection and storage capacity assessment, CCS project planning, investment and
operation decision-making aspects of work.
5.2 CCS technology investment decision research
The above-mentioned cost-economic analysis of each
link of CCS is mainly based on the traditional Discount Cash Flow (DCF), without considering the flexibility and uncertainty of CCS technology investment
decisions. In fact, CCS investment has the characteristics that most of the investment cost is irreversible,
the investment timing is flexible, and the investment
faces multiple uncertain risks. Therefore, the real
option model is widely used to analyze the investment
decision evaluation of CCS technology (Yao et al.
2019; Fan et al. 2019; Agaton 2021), but the current
research mainly focuses on the installation of carbon
capture technology in coal-fired power plants.
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Zhu et al. (2011) established a real option model
to evaluate the investment in carbon capture technology for power plants on the basis of considering
uncertain factors such as thermal power generation
cost, carbon market price, and investment in CCS
technology deployment. Subsequently, Zhu et al.
(2013) analyzed the investment decisions of installing carbon capture devices in supercritical pulverized
coal (SPCC) power plants that have been in operation
based on the real option model of discrete sequences.
The most important factors are operating and maintenance costs. Zhang et al. (2014) used the ternary
tree real option model to calculate the investment
value of carbon capture equipment installed in power
plants, and analyzed the critical carbon market price
of investment under different subsidy coefficients and
power plant lifetimes. Li et al. (2015) analyzed the
impact of carbon market price, fuel price fluctuation
and the development of CCS technology on China’s
power industry carbon emission reduction. Chen et al.
(2016) established a real option model for carbon capture technology investment decision considering the
uncertainty of carbon price, electricity price and coal
price. A few scholars have analyzed the investment
decision in the C
­ O2 storage link. Among them, Narita
Klepper (2016) used the real option method to evaluate the impact of uncertain factors such as ­CO2 leakage in storage sites, carbon market prices, and investment costs on the investment time and profits of ­CO2
storage projects. Compernolle et al. (2017) took the
North Sea offshore EOR project as an example, and
used the real option model to analyze the investment
decisions of carbon emission source enterprises and
oil companies. The results show that accounting for
uncertainty in the real option model leads to higher
critical ­CO2 prices and oil prices for EOR project
investments than when analyzed using the net present value method. The results of the study show that
when the carbon market price is below 40 €/t, additional oil production revenues are required to invest in
early ­CO2 capture and ensure permanent underground
storage of C
­ O2. Only when the oil price is higher than
100 €/bbl, oil companies will be willing to pay for
­CO2 purchase and invest in EOR projects.
In addition, some scholars have analyzed CCS
investment decisions from the perspective of related
policies. Yao et al. (2020) analyzed CCS technology
investment decisions using a real options model with
stochastic dynamic programming and Monte Carlo
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Fig. 21 The impact of
economic decisions on CCS
projects: a government
subsidies can increase CCS
investment potential (Yao
et al. 2020); b the impact
of oil prices on long-term
CCS investment (Yang et al.
2019); c the impact of carbon tax on CCS investment
(Wang and Zhang 2018)
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simulations. The findings show that government
subsidies can promote investment in CCS, as shown
in Fig. 21a. The subsidy range from 0.01$/kWh to
0.05$/kWh can increase the CCS investment potential by 9.66% ~ 39.18%, and shorten the CCS investment period by 0.39 ~ 1.95 years. Yang et al. (2019)
analyzed the impact of cost subsidies and operating
subsidies on the value of CCS projects. The results
show that the subsidy method is affected by the project life cycle and carbon tax policy. As shown in
Fig. 21b, due to the uncertainty of oil price changes,
with the intervention of government subsidies, the
impact of oil price changes can be stabilized and the
operating life of investment can be improved. Moreover, the carbon tax rate has a significant impact on
the implementation of CCS projects. Wang and Du
(2016) compared and analyzed the impact of government subsidies for carbon capture technology investment and power generation subsidies on CCS investment. The results show that when the total amount of
subsidy is small, the effect of subsidizing technology
investment is better. Wang and Du (2016) analyzed
the impact of government subsidies on the investment
threshold of carbon capture technology for coal-fired
power plants under different scenarios. The results
show that government subsidies have a significant
effect on lowering the critical carbon market price of
CCS investment. Under the scenario of full subsidies,
the critical carbon market price is 15.2 $/t, and under
the scenario of no subsidies, the critical carbon market price is 32.1 $/t. When the carbon market price
rises from 0 $/t to 4.4 $/t, the change of the critical
tax rate for CCS project investment exceeds 4.4 $/t.
Duan et al.258 established an energy-environmenteconomic model to analyze the cost and emission
reduction potential of CCS technology. The results
show that the key factor affecting the cost of CCS
technology is the technology learning rate, and the
implementation of subsidy policy can stimulate the
development of CCS technology. Wang and Zhang
(2018) used the ternary tree real option model to
evaluate the investment in installing CCS equipment
in coal-fired power plants from the perspective of carbon tax, as shown in Fig. 21c. The results show that
the critical carbon tax rate for SCPC investment in
carbon capture technology is 21.4 $/t, and the critical
tax rate for IGCC power plant investment in capture
technology is 11.7 $/t.
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It can be seen that when project investment is
faced with multiple uncertain factors, it is necessary to make project investment decisions compared
with the conventional net present value method. And
highlighting the real option method can consider the
management flexibility and strategic value brought by
uncertainty. It is necessary to analyze the real option
characteristics of CCS technology to make a decision,
including the irreversibility of investment cost, multiple uncertainties in investment, and optional investment timing.
6 Challenges and prospects
6.1 Challenges of CCS technology development
CCS has been widely discussed in recent decades as
a technology that is considered a reasonable option to
allow the continued use of fossil fuels while reducing CO2 emissions. As shown in Fig. 22, the current
CCS technology has been comprehensively developed in terms of capture, transportation, and storage.
However, the carbon capture module in CCS technology is an expensive and energy-consuming process,
and the average cost of its capture exceeds 30$/t ­CO2
(Zhong et al. 2018). CCS requires a large-scale ­CO2
transport network, which can only be realistically
achieved by pipeline or ship transport. Hammond
et al. (2011) pointed out in 2011 that for long-distance
(> 1000 km) transportation of ­CO2, ship transportation is more economical than pipeline transportation,
but the technical bottleneck of ship transportation is
difficult to overcome. Currently, the most attractive
and mature geological utilization option for C
­ O2 utilization technology is enhanced oil recovery (EOR),
which has been widely used in the United States.
EOR, which can be profitable by selling the additional volume of oil captured by injecting ­CO2, has
received considerable attention, but progress in ­CO2
storage has been slow for nearly a decade due to its
high cost.
There are extensive and complex stakeholder
relationships among different industries involved in
CCS technology, which makes it difficult to achieve
extensive cooperation in various fields of CCS. The
lack of financing mechanisms has also become one
of the main obstacles to the development of CCS.
Countries, especially developing countries, should
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Fig. 22 CCS technology development level in 2022 (Shen et al. 2022)
actively seek CCS financing channels. Therefore, for
the large-scale deployment of CCS technology, it is
very important to study a feasible commercialization
model and reduce costs. According to the above summary of CCS module technologies, it can be seen that
compared with high-concentration emission sources,
low-concentration ­CO2 emission sources require more
investment in purification and compression costs. The
cost of C
­ O2 capture from high-concentration emission sources is lower, and it is an industry where CCS
technology should be deployed first. The high-concentration emission sources involved include some
chemical processing plants, such as ethylene oxide
and bioethanol processing plants, as well as IGCC
power plants, hydrogen production plants, and natural
gas processing plants. Due to the large ­CO2 emissions
of coal-fired power plants, most of the world’s current
deployment of CCS technology is coal-fired power
plants.
In the ­CO2 capture module, the pre-combustion
capture technology and post-combustion capture
technology have matured and reached the economically feasible stage. However, there are still disadvantages of high cost, which affects the deployment
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of CCS technology. As shown in Fig. 23, compared
with carbon capture from high-concentration carbon
sources, carbon capture from low-concentration carbon sources still has certain challenges in terms of
technology and cost. Due to the technical difficulty of
chemical cycle combustion, there are few studies on
it. However, this technology does not require air separation before combustion, and has good economic
benefits. It is a key technology in the future research
field of capture technology. The separation technology selected in the capture process is mainly chemical absorption at the current stage, and the absorption
technology based on MEA is the most cost-effective.
Membrane separation technology does not need to
add chemicals and absorbents. If the technical bottleneck of low capture efficiency can be overcome in
future research, lower separation and capture costs
can be achieved. An advanced assessment of the
development of DAC technology was carried out by
Fasihi et al (Fasihi et al. 2019). The study found that
LT DAC systems were favored due to lower heating
costs and the possibility to use waste heat from other
systems. The ­CO2 capture cost of an LT DAC system
powered by a hybrid PV-wind battery system without/
Rev Environ Sci Biotechnol (2023) 22:823–885
869
Fig. 23 Comparison of
carbon capture costs across
sectors globally (2019)
with free waste heat is 222/133 (2020), 105/60 (2030),
69/40 (2040) and 54 /32(2050) EUR/t C
­ O2. Osman
et al. (2021) compared carbon sequestration technology with ­CO2 sequestration technology. As the most
common carbon adsorbent, monoethanolamine can
regenerate up to 3.5 GJ per ton of ­CO2. By researching new materials or optimizing the solvent ratio, the
regeneration energy consumption can be effectively
reduced.
In the ­CO2 transportation module, except for ship
transportation which is affected by weather and other
uncertainties, pipeline transportation and tanker transportation technologies are mature. Pipeline transportation is currently the most vigorously promoted C
­ O2
transportation method in the world. In the future, the
construction of pipeline network-type pipeline transportation will greatly reduce the transportation cost of
CCS technology. Kang et al (2014). estimated the cost
of offshore pipeline transportation in South Korea in
2014 through an engineering economic model. The
cost of transportation capacity is 1 million tons/year
is 180￥/ton, and the cost of transportation capacity is 3 million tons/year is 86￥/ton. Knoope et al.
(2013) analyzed the case of general liquid pipeline
transportation at sea in 2010. The capacity is 5 million tons per year, and the transportation cost of the
pipeline with a distance of 100 km is 3.6–13.5 ￥/ton.
As the transportation distance increases, the transportation cost increases. With the increase of transportation capacity, the cost of pipeline transportation
decreases greatly at first, and then the reduction rate
gradually decreases. A review by Onyebuchi et al.
(2018) included assessing the main issues associated
with ­CO2 transport, identifying knowledge gaps, and
improvements to ­CO2 transport systems after addressing these gaps. It is necessary to promote the cooperation between scientific research and the actual site,
and scientifically solve various problems in the process of project implementation.
For the C
­ O2 storage module, ocean storage faces
certain resistance in practical application due to its
irreversibility and the possibility of causing marine
ecological damage. The current C
­ O2 storage mainly
chooses physical storage in deep saline aquifers. In
the future, due to the great storage potential of coal
seams and the fact that methane can be replaced to
improve economic benefits, the research on physical
storage in coal seams should be intensified. So far,
there has been no commercial application of ocean
storage via tanker technology. The levelized annual
cost of storing ­CO2 in the deep sea via subsea pipelines from the shoreline to a depth of 2 km is estiCO 2
mated at $2.90/t ­
CO2 avoided and $14.23/t ­
avoided, including transport, injection and monitoring costs. Meanwhile, three 22,000 ­m3 oil tankers
supply 22 kt ­CO2 per day to shoreline collection
points, inject C
­ O2 to a depth of 2 km through vertical pipelines, and the average annual cost of storing
­CO2 in deep sea is estimated to be between $15.76/
ton. A reduction of $22.79 per ton of C
­ O2 including
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transaction, transport, injection and monitoring
costs (Heddle et al. 2003). For CCS projects on the
U.S. Gulf Coast, indicative costs for C
­ O2 injection
and geological storage in 2020 range from $1.72/
tCO2 for onshore high-quality geological storage to
$18.97/tCO2 for offshore geological storage. ­CO2
monitoring and verification costs range from $1.72/
tCO2 to $4.14/tCO2 (Kheirinik et al. 2021; Hong
2022).
Among ­CO2 utilization technologies, geological utilization is the most widely used at present,
among which C
­ O2 enhanced oil recovery technology has been carried out on a large scale, and under
certain conditions, it can generate benefits. Future
­CO2 utilization technologies should focus on chemical utilization and biological utilization. The benefits brought by these two technologies are more
abundant and the fields of application are wider.
There are many technical routes for C
­ O2 chemical, biological and mineralization utilization, which
can be coupled with the existing production process,
and the products have high added value (Chauvy
and Weireld 2020; Chai et al. 2022). The technologies whose maturity has been demonstrated in the
industry include methanol from ­CO2, synthesis gas,
organic carbonate, degradable compounds, isocyanate, polyester, etc (Li et al. 2022). Among them,
­CO2 hydrogenation to methanol can be deeply coupled with green hydrogen or hydrogen-rich purge
gas from coal chemical industry. While improving
the ability to absorb renewable energy and reducing
carbon emission intensity, it can also produce products with high market demand (Zimmermann et al.
2020).
Although ­CO2 geological utilization technologies
are relatively abundant, only in-situ leaching mineral mining (mainly uranium mining) technology
can be commercially applied. Only the technology of
enhanced oil recovery (that is, oil flooding and storage) has been industrially demonstrated (Hepburn
et al. 2019; Fu et al. 2022). Around 2030, with the
completion and operation of more million-ton or even
tens-of-million-ton oil flooding and storage projects,
­CO2 enhanced oil recovery technology will be able
to be applied commercially. Geological C
­ O2 storage
technologies, including storage in terrestrial saline
aquifers and subsea saline aquifers, are currently
being demonstrated industrially.
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6.2 Limitations of CCS technology investment
decisions
Most of the previous studies only focused on a certain
link in the whole process of CCS to conduct investment decision-making evaluation research. The current research on CCS investment decision-making
mainly focuses on the transformation of carbon capture devices in existing coal-fired power plants (Singh
and Rao 2016; Zhang et al. 2020; Aliabadi 2020), that
is, the ­CO2 capture link of power plants, and very few
scholars consider the ­CO2 transportation and storage
links (Michaelides 2021; Ogland-Hand et al. 2022).
The characteristic of CCS technology is that it is not
a single technology, but a complete technical system
that combines the capture, compression, transportation, storage and utilization of ­CO2 and other links.
Moreover, the technology options for different process links will have an impact on the overall investment decision of CCS technology. For example, if the
­CO2 geological storage method is EOR storage, the
power plant needs to take into account the investment
decision of oil companies investing in EOR projects
when making investment decisions on CCS-EOR projects, which will ultimately affect the overall investment decision of CCS technology. Therefore, it is
necessary to scientifically make a systematic investment decision evaluation of CCS technology from the
perspective of the whole process.
The traditional Net Present Value (NPV) does not
consider the influence of multiple uncertain factors,
and cannot accurately evaluate the investment value
of CCS. Many researchers (Hong 2022; Subraveti
et al. 2021; Battaglia et al. 2021; Fan and Friedmann 2021) have carried out technical and economic
evaluation research on the C
­ O2 capture link. However, conventional NPV methods cannot consider the
management flexibility involved in CCS technology
investment and the impact of multiple uncertain factors on investment decisions. CCS technology investment has complex characteristics such as irreversible
investment cost, uncertainty of investment income,
optional investment timing, and technical uncertainty.
In contrast, using the real option model to analyze
CCS technology investment decisions can not only
describe the risk value of uncertain factors, but also
allow investors to further adjust investment decisions
when uncertain factors change. In addition, most real
option values ​​use the binomial tree model pricing
Rev Environ Sci Biotechnol (2023) 22:823–885
method, but the binomial tree only considers two scenarios of price rise and fall, which leads to a reduction in the accuracy of the option investment value
(Wang and Zhang 2018). In fact, the ternary tree pricing model more accurately describes the CCS investment decision-making process and value formation
mechanism, and improves the accuracy of investment
value calculation.
Based on the existing literature, the current
research mainly focuses on the technical and economic analysis of one or several links of CCS technology. There is a lack of a complete whole-process
system analysis research and technical and economic
evaluation based on system analysis for C
­ O2 capture,
transportation and storage in the coal-fired power
plant industry. Moreover, the techno-economic analysis of CCS projects in different countries is not precise enough. In the technical and economic analysis
of CCS technology, the selection of corresponding
indicators and parameters mostly refers directly to
the published parameters and indicators related to
CCS technology. But in fact, there are differences in
the actual development and application of CCS technology in different countries. For example, Hu and
Zhai (2017) pointed out that in the process of capturing ­CO2 in power plants, the reference cost index
of thermal power projects in China should be used
to analyze the cost of ­CO2 capture, otherwise the
results will be quite different from the actual situation in China. In the ­
CO2 pipeline transportation
link, the pipeline transportation costs vary under different environments. Pipeline transportation costs in
other national markets cannot be assessed using existing cost models in the US and EU (Zhao et al. 2014;
Smith et al. 2021; Vitali et al. 2021). Ultimately, the
existing research cannot improve comprehensive,
complete and systematic information. It cannot help
the government to issue relevant CCS subsidy policies to promote the further implementation and development of CCS technology, and make investment
decisions for CCS technology with related enterprises
and investors.
7 Summary
This review analyzes the role of each module in the
CCS project and its development limitations from
multiple perspectives. In the ­
CO2 capture process,
871
various ­CO2 capture methods are discussed. The
development of capture technology in CCS is
reviewed from the perspectives of capture technology, post-capture separation technology and direct
air capture. Economical industrial CCS and promising DACCCS are the future development priorities
under the goal of carbon neutrality. In ­CO2 Storage
Options, the feasibility of ­CO2 storage is discussed
through a review of C
­ O2 geological storage. Through
the analysis of the storage process and C
­ O2 leakage,
the current research focus of geological storage is
summarized. In the transportation process of ­CO2,
the pipeline transportation of ­CO2 is compared with
that of tank trucks and ships, and the transportation
state of C
­ O2 in the transportation process (supercritical state, liquid state and gaseous state) is considered.
For long-distance transportation, pipeline transportation has advantages in cost and scale. However, each
CCS project should be specific to the region and
project size. In the current development and application of CCS technology, it is necessary to analyze
the incremental cost and net storage capacity of different CCS projects combined through the technical combination of different options among the ­CO2
capture method, transportation method and storage
type. Under the model calculation, the economic cost
and net storage capacity of the project are optimal.
In addition, CCS projects have the characteristics
of huge investment, long operation cycle, and many
technical links involved. The total system cost will be
affected by internal and external factors such as technology, economy, and policy. Therefore, it is necessary to further analyze and discuss the ­CO2 trading
market price scenario, crude oil price scenario, C
­ O2
utilization coefficient scenario and utilization value
scenario. Deepen decision-makers’ comprehensive
and in-depth understanding of the economics and
carbon emission reduction potential of relevant CCS
projects, and provide scientific and reliable decisionmaking basis and support for government departments, investors and owners.
Acknowledgements The work was financially supported by
National Key Research and Development Program of China
(No. 2018YFB0606104).
Author contributions MS, HZ, and FK: conceptualization, formal analysis, writing-reviewing and editing; LT: data
curation, visualization, writing-original draft preparation,
supervision; SY & CL & PZ and LW: Writing-reviewing and
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Rev Environ Sci Biotechnol (2023) 22:823–885
editing; YD: Formal analysis, writing reviewing and editing.
The author(s) read and approved the final manuscripts.
Funding The work was financially supported by National
Key Research and Development Program of China (No.
2018YFB0606104).
Availability of data and materials All data generated or
analysed during this study are included in this published article
(and its supplementary information files).
Declarations
Competing interests
financial interest.
The authors declare no competing
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