Scholarly article on topic 'An overview of current status of carbon dioxide capture and storage technologies'

An overview of current status of carbon dioxide capture and storage technologies Academic research paper on "Environmental engineering"

Share paper
OECD Field of science
{Post-combustion / Pre-combustion / "Oxyfuel combustion" / "CO2 separation" / Transport / "Geological storage" / "Leakage and monitoring"}

Abstract of research paper on Environmental engineering, author of scientific article — Dennis Y.C. Leung, Giorgio Caramanna, M. Mercedes Maroto-Valer

Abstract Global warming and climate change concerns have triggered global efforts to reduce the concentration of atmospheric carbon dioxide (CO2). Carbon dioxide capture and storage (CCS) is considered a crucial strategy for meeting CO2 emission reduction targets. In this paper, various aspects of CCS are reviewed and discussed including the state of the art technologies for CO2 capture, separation, transport, storage, leakage, monitoring, and life cycle analysis. The selection of specific CO2 capture technology heavily depends on the type of CO2 generating plant and fuel used. Among those CO2 separation processes, absorption is the most mature and commonly adopted due to its higher efficiency and lower cost. Pipeline is considered to be the most viable solution for large volume of CO2 transport. Among those geological formations for CO2 storage, enhanced oil recovery is mature and has been practiced for many years but its economical viability for anthropogenic sources needs to be demonstrated. There are growing interests in CO2 storage in saline aquifers due to their enormous potential storage capacity and several projects are in the pipeline for demonstration of its viability. There are multiple hurdles to CCS deployment including the absence of a clear business case for CCS investment and the absence of robust economic incentives to support the additional high capital and operating costs of the whole CCS process.

Academic research paper on topic "An overview of current status of carbon dioxide capture and storage technologies"


An overview of current status of carbon dioxide capture and storage technologies

Dennis Y.C. Leung a,n, Giorgio Caramannab, M. Mercedes Maroto-Valerb

a Department of Mechanical Engineering, The University of Hong Kong, Hong Kong b Centre for Innovation in Carbon Capture and Storage, Heriot-Watt University, UK


Global warming and climate change concerns have triggered global efforts to reduce the concentration of atmospheric carbon dioxide (CO2). Carbon dioxide capture and storage (CCS) is considered a crucial strategy for meeting CO2 emission reduction targets. In this paper, various aspects of CCS are reviewed and discussed including the state of the art technologies for CO2 capture, separation, transport, storage, leakage, monitoring, and life cycle analysis. The selection of specific CO2 capture technology heavily depends on the type of CO2 generating plant and fuel used. Among those CO2 separation processes, absorption is the most mature and commonly adopted due to its higher efficiency and lower cost. Pipeline is considered to be the most viable solution for large volume of CO2 transport. Among those geological formations for CO2 storage, enhanced oil recovery is mature and has been practiced for many years but its economical viability for anthropogenic sources needs to be demonstrated. There are growing interests in CO2 storage in saline aquifers due to their enormous potential storage capacity and several projects are in the pipeline for demonstration of its viability. There are multiple hurdles to CCS deployment including the absence of a clear business case for CCS investment and the absence of robust economic incentives to support the additional high capital and operating costs of the whole CCS process.

© 2014 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY license



1. Introduction........................................................................................................427

2. Approaches to mitigate global climate change.............................................................................427

3. CO2 capture technologies ............................................................................................. 427

3.1. Post-combustion..............................................................................................427

3.2. Pre-combustion ............................................................................................... 429

3.3. Oxyfuel combustion............................................................................................ 429

3.4. Comparison of different combustion technologies for CO2 capture ...................................................... 429

4. CO2 separation technologies ........................................................................................... 430

4.1. Absorption ................................................................................................... 430

4.2. Adsorption ................................................................................................... 431

4.3. Chemical looping combustion....................................................................................431

4.4. Membrane separation .......................................................................................... 431

4.5. Hydrate-based separation.......................................................................................431

4.6. Cryogenic distillation...........................................................................................431

5. CO2 transport....................................................................................................... 432

6. CO2 utilization ...................................................................................................... 432

7. CO2 geological storage................................................................................................ 433

7.1. Enhanced oil recovery (EOR) in oil and gas reservoirs.................................................................433

7.2. Unmineable coal bed storage .................................................................................... 433

7.3. Storage in saline aquifers ....................................................................................... 434

* Corresponding author. Fax: +852 2858 5415. E-mail address: (D.Y.C. Leung).

1364-0321/© 2014 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY license (

Contents lists available at ScienceDirect

Renewable and Sustainable Energy Reviews

journal homepage:



Article history:

Received 20 January 2014

Received in revised form

27 May 2014

Accepted 7 July 2014

Available online 2 August 2014

Keywords: Post-combustion Pre-combustion Oxyfuel combustion CO2 separation Transport Geological storage Leakage and monitoring

7.4. Deep ocean storage............................................................................................435

7.5. In-situ carbonation............................................................................................435

8. Life cycle GHG assessment............................................................................................435

9. CO2 leakage and monitoring...........................................................................................436

9.1. Potential leakages.............................................................................................436

9.2. CO2 monitoring ............................................................................................... 436

10. Barriers and opportunities for commercial deployment.....................................................................437

11. Conclusions........................................................................................................438



1. Introduction

Rapid economic growth has contributed to today's ever increasing demand for energy. An obvious consequence of this is an increase in the use of fuels, particularly conventional fossil fuels (i.e. coal, oil and natural gas) that have become key energy sources since the industrial revolution. However, the abundant use of fossil fuels has become a cause of concern due to their adverse effects on the environment, particularly related to the emission of carbon dioxide (CO2), a major anthropogenic greenhouse gas (GHG). According to the Emission Database for Global Atmospheric Research [1], global emission of CO2 was 33.4 billion tonnes in 2011, which is 48% more than that of two decades ago. Over the past century, atmospheric CO2 level has increased more than 39%, from 280 ppm during pre-industrial time

[2] to the record high level of 400 ppm in May 2013 with a corresponding increase in global surface temperature of about 0.8 °C

[3]. Without climate change mitigation policies it is estimated that global GHG emission in 2030 will increase by 25-90% over the year 2000 level, with CO2-equivalent concentrations in the atmosphere growing to as much as 600-1550 ppm [4].

The Intergovernmental Panel on Climate Change (IPCC) 5th Assessment Report (AR5) issued in 2013-14 confirmed the 4th Assessment Report's assertion that global warming of our climate system is unequivocal and is associated with the observed increase in anthropogenic greenhouse gas concentrations [2,5]. Furthermore, it is mentioned that 1983-2012 was likely the warmest 30 years period of the last 1400 years in Northern Hemisphere. The same IPCC report (AR5) indicates that to avoid the worst effects of climate change occurring, it is necessary to keep the temperature rise less than 2 °C relative to preindustrial levels and that CO2 emissions should be reduced globally by 41-72% by 2050 and by 78-118% by 2100 with respect to 2010 levels [5]. Although there was not any binding agreement on CO2 emission control in the last United Nations Climate Change Conference (COP19) held in November 2013 in Warsaw, Poland, participating countries unanimously looked forward a green economy leading to sustainable development. The IPCC has conducted a comprehensive review on various CCS technologies providing a valuable reference for researchers and policy makers in developing their GHG emission reduction program [6]. However, most of the information can be dated back to 2005 or before and there are a lot of changes since then. Moreover, reviews in literature only account for separate aspects of the CCS technology chain, with a focus on either capture, transport, storage or environmental impact [7-13]. The purpose of this paper is to provide a holistic review on the state of the art of CCS technologies and various relevant aspects, including CO2 capture (Section 3), separation (Section 4), transport (Section 5), utilization (Section 6), storage (Section 7), life cycle GHG assessment (Section 8), and leakage and monitoring (Section 9). An updated status and outlook for CCS projects together with a discussion on the barriers for commercial deployment (Section 10) will also be provided.

2. Approaches to mitigate global climate change

Different approaches are considered and adopted by various countries to reduce their CO2 emissions, including

- improve energy efficiency and promote energy conservation;

- increase usage of low carbon fuels, including natural gas, hydrogen or nuclear power;

- deploy renewable energy, such as solar, wind, hydropower and bioenergy;

- apply geoengineering approaches, e.g. afforestation and reforestation; and

- CO2 capture and storage (CCS).

Table 1 compares the application areas, advantages and limitations of these different approaches. Some of these approaches deal with source emissions reduction, such as adopting clean fuels, clean coal technologies, while others adopt demand-side management, i.e. energy conservation. Each approach has intrinsic advantages and limitations that will condition its applicability. It is unlikely that adopting a single approach or strategy can adequately meet the IPCC goal of CO2 reduction, i.e. 50-85% by 2050 from 2000 levels, and therefore, a complimentary portfolio of CO2 emission reduction strategies needs to be developed. Amongst the different approaches, CCS can reduce CO2 emissions (typically 85-90%) from large point emission sources, such as power production utilities, and energy intensive emitters, e.g. cement kiln plants. In this approach, CO2 is first captured from the flue/fuel gases, separated from the sorbent, transported and then either stored permanently or reutilized industrially.

CCS includes a portfolio of technologies, involving different processes for CO2 capture, separation, transport, storage and monitoring that are separately discussed in the following sections.

3. CO2 capture technologies

CO2 is formed during combustion and the type of combustion process directly affects the choice of an appropriate CO2 removal process. CO2 capture technologies are available in the market but are costly in general, and contribute to around 70-80% of the total cost of a full CCS system including capture, transport and storage [14]. Therefore, significant R&D efforts are focused on the reduction of operating costs and energy penalty. There are three main CO2 capture systems associated with different combustion processes, namely, post-combustion, pre-combustion and oxyfuel combustion. These three technologies are shown in Fig. 1 and discussed in the following sections.

3.1. Post-combustion

This process removes CO2 from the flue gas after combustion has taken place. Post-combustion technologies are the preferred

Table 1

Summary of CO2 reduction strategies.


Application area/sector



Enhance energy efficiency and energy conservation Increase usage of clean fuels

Adopt clean coal technologies

Use of renewable energy

Development of nuclear power

Afforestation and

reforestation Carbon capture and storage

Applied mainly in commercial and industrial buildings.

Substitution of coal by natural gas for power generation.

Integrated gasification combined cycle (IGCC), pressurized fluidized bed combustor (PFBC) etc. to replace conventional combustion. Hydro, solar (thermal), wind power, and biofuels highly developed.

Nuclear fission adopted mainly in US, France, Japan, Russia and China. Nuclear fusion still in research and development phase. Applicable to all countries.

Applicable to large CO2 point emission sources.

Energy saving from 10% to 20% easily achievable.

Natural gas emits 40-50% less CO2 than coal due to its lower carbon content and higher combustion efficiency; cleaner exhaust gas (lower particulates and sulfur dioxide emissions).

Allow the use of coal with lower emissions of air pollutants.

Use of local natural resources; no or low greenhouse and toxic gas emissions.

No air pollutant and greenhouse gas emissions.

Simple approach to create natural and sustainable CO2 sinks. It can reduce vast amount of CO2 with capture efficiency > 80%.

May involve extensive capital investment for installation of energy saving device.

Higher fuel cost for conventional natural gas. Comparable cost for shale gas.

Significant investment needed to roll out technologies widely.

Applicability may depend on local resources availability and cost. Power from solar, wind, marine etc. are intermittent and associated technologies are not mature; most current renewable energies are more costly than conventional energy.

Usage is controversial; development of world's nuclear power is hindered due to the Fukushima Nuclear Accident in 2011, e.g. Germany will phase out all its nuclear power by 2022. Restricts/prevents land use for other applications.

CCS full chain technologies not proven at full commercial scale.

Metal oxidation

Chemical Looping C02 Capture Process

Power + Heat

»-Depleted air

C02 + H20

Fig. 1. CO2 capture technologies.

option for retrofitting existing power plants. The technology has been proven at small-scale with CO2 recovered at rates up to 800 t/day [15]. However, the major challenge for post-combustion CO2 capture is its large parasitic load. Since the CO2 level in combustion flue gas is normally quite low (i.e. 7-14% for coal-fired and as low as 4% for gas-fired), the energy penalty and associated costs for the capture unit to reach the concentration of CO2 (above 95.5%) needed for transport and storage are elevated [16-18]. The

U.S. National Energy Technology Laboratory estimated that CO2 post-combustion capture would increase the cost of electricity production by 70% [19]. A recent study reported that the cost of electricity would increase by 32% and 65% for post-combustion in gas and coal-fired plants, respectively [20]. It has been identified that 16 large scale integrated CCS projects are currently operating or under construction but two of them are of post-combustion technology [21].

3.2. Pre-combustion

3.3. Oxyfuel combustion

In this process, the fuel (normally coal or natural gas) is pre-treated before combustion. For coal, the pretreatment involves a gasification process conducted in a gasifier under low oxygen level forming a syngas which consists mainly of CO and H2, and is mainly free from other pollutant gases (Eq. 1). The syngas will then undergo water gas shift reaction with steam forming more H2 while the CO gas will be converted to CO2 (Eq. 2):


Coal e CO+H2

water - gas shift

CO + H2O e H2 + CO2

CH4 + ^O^eCO + H2

The high CO2 concentration (> 20%) in the H2/CO2 fuel gas mixture facilitates the CO2 separation [18], and typical CO2 separation methods are discussed in Section 4. Subsequently, the H2 is burned in air producing mainly N2 and water vapor. Pre-combustion capture can be applied to Integrated Gasification Combined Cycle (IGCC) power plants using coal as fuel, but this will incur an efficiency loss of 7-8% [15,22]. EPRI and US DOE have developed a roadmap of IGCC technology developments that can potentially improve the IGCC efficiency matching or exceeding the current IGCC technology without capture [22].

Natural gas, as it mainly contains CH4, can be reformed to syngas containing H2 and CO (Eq. (3)). The content of H2 can be increased by the water gas shift reaction (Eq. (2)) and the rest of the process is similar to that described above for coal [23]. Hoffmann et al. [24] conducted a performance and cost analysis on advanced combined cycle gas turbine plants operated by natural gas with a pre-combustion CO2 capture system and obtained a CO2 capture efficiency of 80% with the cost of CO2 avoided reaching $29/t CO2 for an advanced design concept.

In oxyfuel combustion, oxygen, instead of air, is used for combustion. This reduces the amount of nitrogen present in the exhaust gas that affects the subsequent separation process. Substantial reduction in thermal NOx is another advantage of this process [25]. With the use of pure oxygen for the combustion, the major composition of the flue gases is CO2, water, particulates and SO2. Particulates and SO2 can be removed by conventional electrostatic precipitator and flue gas desulphurization methods, respectively. The remaining gases, contain high concentration of CO2 (80-98% depending on fuel used [26]), can be compressed, transported and stored. This process is technically feasible [25] but consumes large amounts of oxygen coming from an energy intensive air separation unit [27]. This results in high cost and the energy penalty may reach over 7% compared with a plant without CCS [28,29]. Also, high SO2 concentration in the flue gas may intensify the system's corrosion problems. At present, there is no full scale oxyfuel-fired projects in the range of 1000-2000 MWth under development but a few sub-scale commercial demonstration plants are under development worldwide such as the 25 MWe and 250 MWe oxy-coal units proposed by CS Energy and Vatten-fall, respectively [29].

3.4. Comparison of different combustion technologies for CO2 capture

Table 2 compares the three CO2 capture technologies described above. Pre-combustion is mainly applied to coal-gasification plants, while post-combustion and oxyfuel combustion can be applied to both coal and gas fired plants. Post-combustion technology is currently the most mature process for CO2 capture [26,30]. On the cost side, Gibbins and Chalmers [31] compared the three technologies for both gas and coal-fired plants (Table 3). They reported that for coal-fired plants the pre-combustion technology presented the lowest cost per tonne of CO2 avoided, while the post-combustion and oxyfuel technologies are of similar costs. However, for gas-fired plants, the cost per tonne of CO2

Table 2

Advantages and disadvantages of the different CO2 capture technologies.

Capture process Application area Advantages Disadvantages

Post-combustion Coal-fired and gas-fired plants Technology more mature than other alternatives; can easily retrofit into existing plants; Low CO2 concentration affects the capture efficiency;

Pre-combustion Coal-gasification plants High CO2 concentration enhance sorption efficiency; fully developed technology, commercially deployed at the required scale in some industrial sectors; opportunity for retrofit to existing plant; Temperature associated heat transfer problem and efficiency decay issues associated with the use of hydrogen-rich gas turbine fuel; high parasitic power requirement for sorbent regeneration; inadequate experience due to few gasification plants currently operated in the market; high capital and operating costs for current sorption systems;

Oxyfuel combustion Coal-fired and gas-fired plants Very high CO2 concentration that enhances absorption efficiency; mature air separation technologies available; reduced volume of gas to be treated, hence required smaller boiler and other equipment; High efficiency drop and energy penalty; cryogenic O2 production is costly; corrosion problem may arise;

Chemical looping combustion Coal-gasification plants CO2 is the main combustion product, which remains unmixed with N2, thus avoiding energy intensive air separation; Process is still under development and inadequate large scale operation experience;

Table 3

Cost comparison for different capture processes [211]. Costs include CO2 compression to 110 bar but excluding storage and transportation costs.

Fuel type Parameter Capture technology

No capture Post-combustion Pre-combustion Oxy-fuel

Coal-fired Thermal efficiency (% LHV) 44.0 34.8 31.5 35.4

Capital cost ($/kW) 1410 1980 1820 2210

Electricity cost (c/kWh) 5.4 7.5 6.9 7.8

Cost of CO2 avoided ($/t CO2) - 34 23 36

Gas-fired Thermal efficiency (% LHV) 55.6 47.4 41.5 44.7

Capital cost ($/kW) 500 870 1180 1530

Electricity cost (c/kWh) 6.2 8.0 9.7 10.0

Cost of CO2 avoided ($/t CO2) - 58 112 102

Table 4

Comparison of different separation technologies.






High absorption efficiency ( > 90%).

Sorbents can be regenerated by heating and/or depressurization. Most mature process for CO2 separation.

Absorption efficiency depends on CO2 concentration.

Significant amounts of heat for absorbent regeneration are required. Environmental impacts related to sorbent degradation have to be understood.



Process is reversible and the absorbent can be recycled. High adsorption efficiency achievable ( > 85%).

Require high temperature adsorbent. High energy required for CO2 desorption.


Chemical looping - CO2 is the main combustion product, which remains unmixed with N2,

combustion thus avoiding energy intensive air separation. Membrane - Process has been adopted for separation of other gases. separation - High separation efficiency achievable ( > 80%).

- Process is still under development and there is no [58-60] large scale operation experience.

- Operational problems include low fluxes and [35,61,63,213] fouling.


separation Cryogenic distillation

Small energy penalty.

- Mature technology.

- Adopted for many years in industry for CO2 recovery.

- New technology and more research and [13,19,67,68]

development is required.

- Only viable for very high CO2 [ 72,74] concentration > 90% v/v.

- Should be conducted at very low temperature.

- Process is very energy intensive.

avoided for the post-combustion capture was almost 50% lower than the other two capture technologies. Moreover, the postcombustion CO2 capture is normally the least efficient option, with an energy penalty of about 8% and 6% for the coal-fired and gas-fired plants, respectively [32].

4. CO2 separation technologies

This section describes the main CO2 separation technologies that can be applied to isolate the CO2 from the flue/fuel gas stream prior to transportation. Advanced technologies, such as wet scrubber, dry regenerable sorbents, membranes, cryogenics, pressure and temperature swing adsorption, and other advanced concepts have been developed. These technologies are compared in Table 4 and discussed below.

4.1. Absorption

A liquid sorbent is used to separate the CO2 from the flue gas. The sorbent can be regenerated through a stripping or regenerative process by heating and/or depressurization. This process is the most mature method for CO2 separation [30]. Typical sorbents include monoethanolamine (MEA), diethanolamine (DEA) and potassium carbonate [33]. Among the various aqueous

alkanolamines, such as MEA and DEA, Veawab et al. [34] found that MEA is the most efficient one for CO2 absorption with efficiency over 90%. Subsequently, Aaron et al. [35] conducted a review on various CO2 capture technologies and concluded that the most promising method for CO2 capture for CCS is absorption using MEA. An absorption pilot plant with 1 t CO2/h was constructed and successfully tested together with the postcombustion capture technology for a coal-fired power plant using a solvent containing 30% MEA [36]. Some other sorbents, such as piperazine and anion-functionalized ionic liquid have also received attention in recent years [37]. Piperazine has been found to react much faster than MEA, but because it has a larger volatility than MEA, its application in CO2 absorption is more expensive and is still under development [38].

One important challenge for the large deployment of this technology for CCS is its potential amine degradation, resulting in solvent loss, equipment corrosion and generation of volatile degradation compounds [39,40], while that atmospheric degradation has not been included. Moreover, amine emissions can degrade into nitrosamines and nitramines [41], which are potentially harmful to the human health and the environment. Chilled ammonia process uses aqueous ammonium salts (such as ammonium carbonate) to capture CO2 that can make use of waste heat to regenerate the CO2 at elevated temperature and pressures to reduce downstream compression [42]. This process will generate

less problem as compared to those that amine is facing with degradation.

4.2. Adsorption

In contrast to absorption processes which use a liquid absorbent, a solid sorbent is used to bind the CO2 on its surfaces. Large specific surface area, high selectivity and high regeneration ability are the main criteria for sorbent selection. Typical sorbents include molecular sieves, activated carbon, zeolites, calcium oxides, hydro-talcites and lithium zirconate.

The adsorbed CO2 can be recovered by swinging the pressure (PSA) or temperature (TSA) of the system containing the CO2-saturated sorbent. PSA is a commercial available technology for CO2 recovery from power plants that can have efficiency higher than 85% [43,44]. In this process, CO2 is preferentially adsorbed on the surface of a solid adsorbent at high pressure, which will swing to low pressure (usually atmospheric pressure) to desorb the adsorbent and release CO2 for subsequent transport. In TSA, the adsorbed CO2 will be released by increasing the system temperature using hot air or steam injection. The regeneration time is normally longer than PSA but CO2 purity higher than 95% and recovery higher than 80% can be achieved [45]. Operating cost of a specific TSA process was estimated to be of the order of 80-150 US $/tonne CO2 captured [46]. Finally, the use of residues from industrial and agricultural operations to develop sorbents for CO2 capture has attracted significant attention to reduce the total costs of capture [47-50].

4.3. Chemical looping combustion

A metal oxide is used as an oxygen carrier instead of using pure oxygen directly for the combustion as in the case of oxyfuel combustion. During the process the metal oxide is reduced to metal while the fuel is being oxidized to CO2 and water. The metal is then oxidized in another stage and recycled in the process. Water, the process by-product, can be easily removed by condensation, while pure CO2 can be obtained without consumption of energy for separation. There are a wide variety of metal oxides that are of low-cost and suitable for this process including Fe2O3, NiO, CuO and Mn2O3. The effectiveness of different metal oxides in this process has been studied by various researchers [51-56]. Adanez et al. [54] found that support inert materials can be used to optimize the performance of the metal oxides, but the choice of inert material will depend on the type of metal oxide used. Lyngfelt et al. [57] studied experimentally the feasibility of chemical looping in a boiler with a design of two interconnected fluidized beds. This technology has been reviewed recently by Lyngfelt and Mattisson [58]. Both Lyngfelt and Mattisson [58] and Adanez et al. [59] found that this process is a very promising technology for CO2 capture. Erlach et al. [60] compared the CO2 separation of IGCC using pre-combustion with that of chemical looping combustion and found that the net plant efficiency of the latter is 2.8% higher than the former case.

4.4. Membrane separation

Membranes can be used to allow only CO2 to pass through, while excluding other components of the flue gas. The most important part of this process is the membrane which is made of a composite polymer of which a thin selective layer is bonded to a thicker, non-selective and low-cost layer that provides mechanical support to the membrane [61]. This method has also been used to separate other gases such as O2 from N2, and CO2 from natural gas. Through the development of high efficient membranes, Audus [62] and Gielen [63] achieved a CO2 separation

efficiency from 82% to 88%. The development of ceramic and metallic membranes [35] and polymeric membranes [64] for membrane diffusion could produce membranes significantly more efficient for CO2 separation than liquid absorption processes. Brunetti et al. [65] conducted a general review on current CO2 separation technology using membranes and compared with other separation technologies such as adsorption and cryogenic. It pointed out that the performance of a membrane system is strongly affected by the flue gas conditions such as low CO2 concentration and pressure, which are the main hurdles for applying this technology. Furthermore, Bernardo et al. [66] revealed that although there are significant developments in gas separation membrane systems, they are still far away to realize the potentialities of this technology.

4.5. Hydrate-based separation

Hydrate-based CO2 separation is a new technology by which the exhaust gas containing CO2 is exposed to water under high pressure forming hydrates. The CO2 in the exhaust gas is selectively engaged in the cages of hydrate and is separated from other gases. The mechanism is based on the differences of phase equilibrium of CO2 with other gases, where CO2 can form hydrates easier than other gases such as N2 [67].

This technology has the advantage of small energy penalty (68%) [19] and the energy consumption of CO2 capture via hydrate could be as low as 0.57 kWh/kg-CO2 [67]. Improving the hydrate formation rate and reducing hydrate pressure can improve the CO2 capture efficiency [67]. Tetrahydrofuran (THF) is a water-miscible solvent, which can form solid clathrate hydrate structures with water at low temperatures. So the presence of THF facilitates the formation of hydrate and is frequently used as a thermodynamic promoter for hydrate formation. Englezos et al. [68] found that the presence of small amount of THF substantially reduces the hydrate formation pressure from a flue gas mixture (CO2/N2) and offers the possibility to capture CO2 at medium pressures. Recently, Zhang et al. [69] studied the effects and mechanism of the additive mixture on the hydrate phase equilibrium using the isochoric method and confirmed the effect of THF on hydrate formation. US DOE considers this technology to be the most promising long term CO2 separation technology identified today and is currently in the R&D phase [19,70,71].

4.6. Cryogenic distillation

Cryogenic distillation is a gas separation process using distillation at very low temperature and high pressure, which is similar to other conventional distillation processes except that it is used to separate components of gaseous mixture (due to their different boiling points) instead of liquid. For CO2 separation, flue gas containing CO2 is cooled to desublimation temperature ( -100 to-135 °C) and then solidified CO2 is separated from other light gases and compressed to a high pressure of 100-200 atmospheric pressure. The amount of CO2 recovered can reach 90-95% of the flue gas. Since the distillation is conducted at extremely low temperature and high pressure, it is an energy intensive process estimated to be 600-660 kWh per tonne of CO2 recovered in liquid form [72]. Several patented processes have been developed and research has mainly focused on cost optimization [73,74]. The evaluation of low temperature processes for producing high purity, high pressure CO2 from oxyfuel combustion flue gas through simulation and modeling in Aspen HYSYS has also been investigated [75].

5. CO2 transport

Once CO2 is separated from the rest of the flue gas components it needs to be transported to the storage site or to the facilities for its industrial utilization. Whatever the chosen final fate of CO2, a reliable, safe and economically feasible system of transport is a key feature of any CCS project. Depending on the volumes involved a variety of means of transport may be utilized, ranging from road tankers to ships and pipelines. A study related to CCS in the North Sea highlights that CO2 transport by ship tanker, using technologies derived from the LPG carriers, is feasible and cost competitive with pipelines with a total cost ranging from 20 to 30 USD/tonne when more than 2MtCO2/year are transported within the distances involved in North Sea storage [76].

Pipelines are considered to be the most viable method for onshore transport of high volume of CO2 through long distances as CCS would likely involve when widely deployed [77]. Pipelines are also the most efficient way for CO2 transport when the source of CO2 is a power plant which lifetime is longer than 23 years. For shorter period road and rail tankers are more competitive [78]. The cost of transport varies considerably with regional economic situation. A cost analysis in China shows that for a mass flow of 4000 t CO2/day the use of ship tankers will cost 7.48 USD/tonne CO2 compared with 12.64 USD/tonne CO2 for railway tankers and 7.05 USD/tonne CO2 for 300 km pipelines [79].

In order to optimize the mass/volume ratio CO2 is carried as dense phase either in liquid or supercritical conditions. Supercritical is the preferred state for CO2 transported by pipelines, which implies that the pipelines operative temperature and pressure should be maintained within the CO2 supercritical envelop, i.e. above 32.1 °C and 72.9 atm. [80]. The typical range of pressure and temperature for a CO2 pipeline is between 85 and 150 bar, and between 13 °C and 44 °C to ensure a stable singlephase flow through the pipeline [81]. The drop in pressure due to the reduction of the hydraulic head along the pipeline is compensated by adding recompression stations. Larger diameter pipelines allow lower flow rates with smaller pressure drop and therefore a reduced number of recompression stations; on the other hand larger pipelines are more expensive therefore a balancing of costs needs to be considered [81].

Impurities in the CO2 stream represent a serious issue because their presence can change the boundaries of the pressure and temperature envelope within which a single-phase flow is stable. Moreover, the presence of water concentration above 50 ppm may lead to the formation of carbonic acid inside the pipeline and cause corrosion problems. Hydrates may also form that may affect the operation of valves and compressors. The estimated values of corrosion on the carbon steel commonly used for pipeline's construction can be up to 10 mm/year [81,82].

Currently only a few pipelines are used to carry CO2 and are almost all for EOR projects. The oldest is the Canyon Reef Carriers pipeline, a 225 km pipeline built in 1972 for EOR in Texas (USA). The longest is the 800 km Cortez pipeline which is carrying 20 million tonne/year of CO2 from a natural source in Colorado to the oil fields in Denver City, Texas since 1983 [81].

CO2 pipelines are mostly made of carbon steel and composed of insulated 12 m sections with crack arresters every 350 m and block valves every 16-32 km. The onshore pipelines are buried in trenches of about 1 m deep. Offshore pipelines in shallow water also need to be deployed in trenches as protection from fishing and mooring activities. Deep water pipelines generally do not need to be buried unless their diameter is below 400 mm [81,83].

The rate of accidents involving CO2 pipelines is relatively low with a value of 0.30/year for every 1000 km calculated during the period 1990-2001 considered for an overall pipelines extension of 2800 km [84]. The enlargement of the pipelines network leads to

an increase in the number of accidents up to 0.76/year for every 1000 km in 2002-2008 calculated over an overall pipeline length of 5800 km [85]. These values are still well below the ones involving pipelines for gas/oil or other hazardous fluids. However, the current CO2 pipeline network is far smaller than that for gas/ oil transport, and therefore, the statistical significance of these values is somewhat uncertain.

For commercial scale CCS projects an extensive network of CO2 pipelines needs to be developed. An integrate network, where different sources will merge for their final transport to the storage areas, can reduce the total pipelines length by 25%, but it will require that all sources produce CO2 stream with the same quality (e.g. pressure, T, water content) before being combined together [82]. When the flow managed through a network of pipelines increases there is an exponential decrease in the cost of transport; models highlight that the cost for transporting CO2 along a 1000 km pipeline is around 8 USD/tonne for a mass flow of 25 MtCO2/year with a further reduction down to 5 USD/tonne if the flow increases to 200 MtCO2/year [86]. Further cost saving may be achieved from the reuse of existing gas pipelines but their suitability is to be verified. One of the biggest uncertainties is the effects on the pipelines' integrity of long term exposure to CO2 fluxes in terms of corrosion and potential brittle fractures propagation due to the sharp cooling of the pipelines in case of leak of supercritical CO2 [87].

The pipelines have to be periodically monitored to assess their integrity and an accurate fiscal metering system is to be in place to assure the quantification of the stored fluxes. The equipment used for gas/oil pipelines need to be modified to withstand the challenging environment experienced inside a CO2 pipeline. Poor lubrication capacity of CO2, high chemical reactivity and high pressure may all affect the performance of both monitoring and metering equipment [88].

Other issues could arise from the trans-national transport of CO2 and offshore storage due to legal aspects. The two key documents are the Convention for the Protection of the Marine Environment of the North East Atlantic (OSPAR Convention) and the London Protocol. These treaties do not allow waste dumping in marine environment and they also limit the cross border transport of pollutants. In 2007 the OSPAR Convention was amended allowing sub-seabed CO2 storage and entered into force following the needed ratification by seven countries on 23 June 2011. In 2006 an amendment was made to Annex 1 of the London Protocol allowing CO2 to be injected in sub-seabed geological formations. Being an amendment to an Annex it does not need to be ratified and entered in force on 10 February 2007, 100 days after being proposed as for rules of the London Protocol. A second amendment was proposed in 2009 in order to remove the restriction for cross border transport of CO2 for geological storage; this is an amendment to the Protocol itself and therefore needs to be ratified by two-thirds of the 42 contracting parties. So far only Norway and the UK have ratified the document [89]. CO2 transport for EOR is allowed under existing legislation both in USA [85] and Europe [89], but there is no guarantee that the same approach will be maintained for the far larger volumes needed to be transported for large scale CCS operations.

6. CO2 utilization

After capture, the high CO2 content stream can be transported for geological storage (see Section 7), or for CO2 utilization. Kikuchi [90] evaluated the economic and technical aspects of large scale CO2 recycling and proposed an integrated scheme for CO2 recovery and reuse in industry, agriculture and energy production. A demonstration plant in Luzhou, China was recently commissioned

that produces ammonia and urea using the CO2 captured (160 t/ day) from its production process [91]. CO2 can also be used in other areas such as food beverages, refrigerants and fire extinguishing gases. Current CO2 utilization accounts for only 2% of emissions, but forecasts predict chemical utilization could mitigate 700 megatons of CO2 per year, far greater than the combined potential of nuclear, wind and cellulosic biofuel technologies [92]. Enhanced oil recovery (EOR) using CO2 from capture processes can significantly increase CO2 utilization [93], and this application is described in Section 7.1. Other related new sectors include the use of CO2 as a cushion gas for energy storage [94].

CO2 can be utilized through mineralization, a process based on the accelerated reaction of CO2 with Mg/Ca rich silicate rocks or inorganic wastes to form stable carbonates which can be used [95]. The unfavorable kinetics of this process is overcome by (i) directly increasing the pressure and/or temperature or, (ii) indirectly, by using aggressive leaching agents. Among the indirect routes, the pH swing has received significant attention as it allows the recyclability of the chemicals used during the process separation and recovery of pure products [96-104].

Large scale, economic photocatalytic conversion of CO2 into methane (CH4) and/or methanol (CH3OH) represents a formidable scientific and technical challenge [105]. Recent progress in this area has focused mainly on the development of novel catalysts through advances in nanotechnology [106,107]. Few photocataly-tic reactors have been tested for ultraviolet driven CO2 reduction [108], and these generally operate as batch processes [109], with even more limited solar reactor studies published [110,111], predominantly operated in batch mode and within the context of wastewater treatment and air purification [112].

7. CO2 geological storage

CO2 can be stored into geological formations such as deep saline aquifers which have no other practical use, and oil or gas reservoirs. Geological storage is at present considered to be the most viable option for the storage of the large CO2 quantities needed to effectively reduce global warming and related climate change [113-116]. A typical geological storage site can hold several tens of million tonnes of CO2 trapped by different physical and chemical mechanisms [117].

Suitable geological sites for CO2 storage have to be carefully selected. General requirements for geological storage of CO2 include appropriate porosity, thickness, and permeability of the reservoir rock, a cap rock with good sealing capability, and a stable geological environment [118]. Requirements such as distance from the source of CO2, effective storage capacity, pathways for potential leakage and in general economic constrains may limit the feasibility of being a storage site. Bachu [119] described the criteria and approaches for selecting suitable geological sites for storing CO2, including the tectonic setting and geology of the basin, its geothermal regime, hydrology of formation waters, hydrocarbon potential and basin maturity. In addition, economic aspects related to infrastructure and socio-political conditions will also affect the site selection. Furthermore, although techniques for geological storage can be derived from existing processes, mostly enhanced oil recovery (EOR) projects, there is no real experience yet at commercial scale, and the potential long term environmental effects of large amounts of CO2 stored is also limited.

Three different geological formations are commonly considered for CO2 storage: depleted (or nearly depleted) oil and gas reservoirs, unmineable coal beds, and saline aquifers. Deep ocean storage is also a feasible option for CO2 storage although environmental concerns (such as ocean acidification and eutrophication) will likely limit its application. It has been shown that CO2 storage

potential can reach 400-10,000 GT for deep saline aquifers compared with only 920 GT for depleted oil and gas fields and > 15 GT in unmineable coal seams [120]. Different geological settings have different criteria of consideration for their reliability as CO2 storage areas and these are discussed below.

7.1. Enhanced oil recovery (EOR) in oil and gas reservoirs.

CO2 can be injected into depleted (or nearly depleted) oil/gas reservoirs to increase their pressure and provide the driving force to extract residual oil and gases, while the injected CO2 remains stored there permanently. Up to 40% of the residual oil left in an active reservoir can be extracted after primary production [121]. In fact, fluids injection methods have been widely used in the oil and gas extraction industry for decades to enhance the recovery of the residual oil and gases. Therefore, there is an economical incentive for injecting CO2 (recovered from an associated capture process) into depleted oil and gas reservoirs in order to offset the high CCS cost commonly involved in the process. Technologies for injection of CO2 for EOR are mature and there are studies on various aspects of EOR, such as migration simulation [122,123], geochemical modeling [124,125], and leakage/risk assessment [126].

Several EOR projects for CO2 storage are ongoing, as shown in Table 5. The largest one is the Weyburn project that started in 2000 in the Weyburn oil reservoir in Saskatchewan, Canada. Although the aim of the project is not to investigate the potential for CO2 storage, the reservoir is estimated to be able to store more than 30 million tonnes of CO2 captured from a gasification plant in North Dakota, USA and transported to the site through a 320 km pipeline. A number of larger EOR projects with much larger storage capacity are planned (such as Hatfield and California DF2) and will be commissioned in the next few years. This will build confidence in operators for the feasibility of larger CO2 storage demonstration projects.

7.2. Unmineable coal bed storage

CO2 can be injected into deep coal beds to recover methane which is trapped in the porous structure of coal seams. This process, called CO2 enhanced coal bed methane (CO2-ECBM),

Table 5

List of current and planned EOR projects.

Project Location Year of Max. CO2 injection Reference

name operation start rate Mt/year

Jilin oil Jilin, China 0.1 [214,215]

Weyburn- Saskatchewan, 2000 2.2 [216-218]

Midale Canada

Paradox Utah, USA 2005 0.14 [219,220]

Salt Creek Wyoming, USA 2006 2.2 [143]

Williston North Dakota, USA 2011 1.0 [221]

South North Dakota, USA 2012 0.6 [143]

Oologah Oklahoma, USA 2012 1.5 [222]

Masdar Abu Dhabi, United Arab Emirates 2012 1.7 [223,224]

Hatfield Hatfield, U.K. 2013 6.5 [143]

California California, USA 2014 5 [225]

Mongstad Mongstad, Norway 2014 1.5 [143]

Trailblazer Texas, USA 2014 4.3 [143,226]

Greengen China 2015 0.7 [143]

Genesee Alberta, Canada 2015 3.6 [143,227]


allows CO2 to be stored in the void fraction made available by removal of the trapped methane in the coal seams. Extraction of coal bed methane (CBM) has been adopted in coal seams for many years and there are several commercial CBM extraction sites in the world, mostly in the USA (Table 6). White et al. [127] conducted a very comprehensive review on the CO2 sequestration in deep unmineable coal beds with recovery of methane gas. Several key issues, such as estimation of potential storage capacity, storage integrity, physical and chemical processes, environmental health and safety, etc., were highlighted in their study.

CO2 storage in deep unmineable coal bed with simultaneous methane gas recovery has been successfully carried out in several coal bed sites such as that in New Mexico, USA [128] and Alberta, Canada [129]. A list of CO2-ECMB projects currently conducted or planned worldwide is shown in Table 6. The technology for CO2-ECBM has additional economic incentives, and there are large coalbed methane resources worldwide, including China, Australia and the USA [130]. However, many of the coal seams (such as those in China and Western Europe) have low permeability that would make this process not applicable [128]. A field pilot test conducted at Yubari in Japan during the period of 2002-2007 indicated that reduction of permeability is one of the main technical issues to be solved in order to make large scale CO2-ECBM economically viable [131].

7.3. Storage in saline aquifers

Deep aquifers at 700-1000 m below ground level often host high salinity formation brines [132]. These saline aquifers have no commercial value but can be used to store injected CO2 captured from CCS process. Deep saline aquifers can be found in widespread areas both onshore and offshore and are considered to have enormous potential for storage of CO2 [6]. Despite of the high potential for CO2 storage, there are comparatively less knowledge about the CO2 storage features of saline aquifers as compared to other geological sites such as coal seams and oil fields.

Different trapping mechanisms take place in saline aquifers when CO2 is injected. The main features of these mechanisms are shown in Table 7, and a detailed review was published [133]. Yang et al. [115] conducted a review on the characteristics of CO2 sequestration in saline aquifers, including CO2 phase behavior,

CO2-water-rock interaction, and CO2 trapping mechanisms that include hydrodynamic, residual, solubility and mineral trapping [61,129,134]. The parameters affecting mineral trapping of CO2 sequestration in brines have been extensively investigated [135138]. Recently, Szulczewski et al. [139] evaluated how pressure rises during injection and how CO2 is trapped in the pore space of deep saline aquifers, which help the estimation of the CO2 storage capacity.

Over the past two decades several pilot and commercial projects for CO2 storage on saline or deep saline aquifers have been launched. Statoil's Sleipner project in the North Sea, as part of a commercial natural gas operation, stores around 1 Mt CO2/ year in a deep saline aquifer hosted in the Utsira Sand formation, about 1000 m below the seafloor with an available volume for CO2 storage in the order of 6.6 x 108 m3 [140-142]. This project started in 1996 and is one of the earliest CCS projects. Other current and approved projects of different scales (i.e. commercial, pilot and demonstration) can be found in Rai et al. [143], Michael et al. [144] and Global CCS Institute [87], and are summarized in Table 8. It can be observed that previous and existing projects are of small CO2 injection capacity ( r 1.3 Mt/year) but future projects (such as the Gorgon and the Latrobe Valley projects in Australia) would have much larger CO2 injection capacity ( > 4.5 Mt/year).

White et al. [127] conducted a comprehensive review on the storage of the captured CO2 in deep saline aquifers and commented that, with the experience gained in several concurrent projects, storage of CO2 in deep saline aquifers is technically feasible, and can have little or no negative environmental impacts. Michael et al. [144] conducted a similar study based on the experience from existing storage operations and presented similar conclusions as White et al. [127]. These authors also discussed the importance of monitoring and verification, and pointed out that there are limited monitoring programs for existing projects, as well as limited data from post-injection monitoring of CO2 behavior in the storage reservoir. Nevertheless, the experience gained in these operations helps to establish best practice guidelines for future CO2 geological storage. More recently, Myer [116] reviewed the global status of geological CO2 storage and indicated the lack of data on post-injection behavior inside the storage reservoir and the need for more field assessments on the processes that lead to plume stabilization and long term trapping.

Table 6

List of current and planned CO2-ECBM projects.

Project Name


Year of operation start

Max. CO2 injection rate Mt/year


San Juan Basin Fenn Big Valley Recopol Qinshui Basin Yubari

Permian Basin

Farnham Dome/Uinta Basin


New Mexico, USA

Alberta, Canada


Texas, USA

Utah, USA

1996 1998 2003

2005 2005 2015

0.1 0.02

400 t/year 0.01 0.004 0.3 0.9 0.01





Table 7

Types and mechanisms of CO2 trapping in saline aquifers [61,129,134].

Trapping mechanism CO2 trapping phase Description of mechanism

Hydrodynamic Supercritical fluid Undissolved CO2 is trapped by overlying low-permeability caprock; CO2 will be gradually dispersed.

Residual Gas phase CO2 rises through water-saturated rock and displacing water from the pore space; the whole

rock volume retains a residual saturation of CO2.

Solubility Dissolved liquid phase CO2 is dissolved in the formation brine water; a major trapping mechanism.

Mineral Reacted solid phase Dissolved CO2 reacts with Ca, Fe, or Mg

based mineral to form carbonate precipitates; not subject to leakage.

Table 8

Current and planned projects of CO2 storage in saline aquifers.

Project name Location Scalea Year of injection start Max. CO2 injection rate Mt/year Reference

Alberta Basin Alberta & B.C. Canada C 1990 0.1 [233,234]

Sleipner North sea, Norway D 1996 1.0 [184,235,236]

Frio USA P 2004 0.1 [143]

In Salah Krechba, Algeria D 2004 1.3 [237]

Sn0hvit Barents Sea, Norway D 2008 0.7 [238,239]

MRCSP- Michigan Basin Gaylord, MI, USA P 2008 0.2 [240,241]

MRCSP-Cincinnati Arch Kentucky, USA P 2009 0.2 [242,243]

SECARB Early Cranfield, MS, USA D 2009 1.0 [244,245]

Mountaineer West Virginia, USA C 2009 0.1 [143,246]

MGSC Decatur Decatur, IL, USA D 2010 0.4 [247-249]

ZeroGen Queensland, Australia P 2012 0.7 [143,250]

Brindisi Italy P 2012 1.2 [143,251]

Gorgon Barrow Island, WA, Australia D 2014 4.5 [252,253]

Latrobe Valley Victoria, Australia C 2015 13 [143,254]

Nagaoka Japan P 2015 0.007 [144]

Edwardsport Indiana, USA P 2015 1.0 [255]

a C: commercial; P: pilot; D: demonstration.

7.4. Deep ocean storage

Oceans cover more than 70% of Earth's surface and are the biggest natural CO2 sink. It is estimated that oceans contain about 38,000 Gt of carbon and take up carbon from the atmosphere at a rate of about 1.7 Gt annually. At the same time, oceans produce 50-100 Gt carbon (in the form of phytoplankton) annually, which is greater than the intake by terrestrial vegetation [145]. The carbon inventory in the ocean is enormous at about 50 times greater than that of our atmosphere [61]. At depths greater than 3 km, CO2 will be liquefied and sunk to the bottom due to its higher density than the surrounding seawater [119,146]. Mathematical models suggest that CO2 injected in this way could be kept for several hundred years [147]. House et al. [146] further showed that injecting CO2 into deep sea sediments at a depth greater than 3 km can provide permanent geological storage of CO2 even with large geomechanical perturbations. Therefore, deep ocean storage can present a potential sink for large amounts of anthropogenic CO2. However, this approach is more controversial than other geological storage methods. Injecting large amounts of CO2 directly into our oceans may affect the seawater chemistry (such as reducing its pH) causing ocean acidification, which may lead to disastrous consequences to the marine ecosystem [148]. Comparatively fewer studies have been conducted in this area, particularly on its effect on the marine ecosystem. Hall-Spencer et al. [149] studied the effect of ocean acidification on an ecosystem near volcanic CO2 vents and concluded that ocean acidification will probably reduce the biodiversity and alter profoundly the ecosystems. Rodolfo-Metalpa et al. [150] also agreed that the ocean ecosystems' resistance to acidification could be worsened by higher temperatures due to global warming. Espa et al. [151] and Caramanna et al. [152] carried out field studies in a volcanic island Panarea in Italy and laboratory investigations to examine the bubbles plumes effect due to sub-seabed CO2 leakage. They found the development of a pseudo-convective cell around the rising plume forming vortices that act as a physical barrier inhibiting the interaction between the plume and the surrounding water. Moreover, the depth of the thermocline plays an important role in the diffusion of the CO2 seepage through the overlying water column. This finding can be a useful guide for future studies on the acidification of surrounding water due to shallow water CO2 leakage.

Although the IPCC has recognized the potential of ocean CO2 storage, it also noted its local risks that may arise as mentioned above [6]. With the above ecological and environmental concerns, more studies in this area need to be conducted to establish its

feasibility and long term effect on marine ecosystem before it can be fully implemented.

7.5. In-situ carbonation

Injected CO2 reacts with the surrounding host rock and, in the presence of specific minerals, may generate carbonates [153]. This process may occur within mafic and ultramafic rocks such as basalts and Ophiolite suites [154]. Basalts are the most widely diffused rocks on the planet covering large areas of the continents and the oceans seafloor. Their potential for CO2 storage is therefore very high even if technical issues and a limited knowledge of their stratigraphic setting at the level of details required for identifying the injection areas and their effective reactivity with CO2 still limit their use [155,156].

8. Life cycle GHG assessment

The principal aim of CCS technologies is to reduce the CO2 emissions from anthropogenic sources to the atmosphere. Most of the processes associated with CCS described in the previous sections would require the construction of infrastructure and installation of facilities (such as scrubbers, compressors and pipelines), additional use of chemicals (such as amine, hydroxide or zirconate), solid waste and wastewater disposal, etc. Energy would also be required for manufacturing, transporting, installing and operating of these facilities, and for producing chemicals, and thus, resulting in CO2 emissions. Therefore, it is necessary to carry out a life cycle analysis (LCA) on GHG to determine whether or not a particular CCS technology can result in a net reduction in CO2. This analysis is important, particularly for formulation of relevant CCS policy of a country. The Directive 2009/31/EC and the associated Guidance Document 1 is an example of how Europe is assessing the CO2 Storage Life Cycle Risk Management [157].

Several LCA studies have been conducted regarding CCS, but mainly on coal-fired power plants and only including the capture unit [158-161]. Pehnt and Henkel [160] found that while there is an increase in cumulative energy demand for CCS, a substantial decrease in GHG emission is found for all the existing CO2 capture approaches (i.e. post-combustion, pre-combustion, oxyfuel), as well as transport and storage in a depleted gas field. Odeh and Cockerill [159] conducted a LCA on the GHG emission of three types of fossil fuel power plants with and without CCS. They found that with a 90% CO2 capture efficiency, life cycle GHG emissions are reduced by 75-84%. They also concluded that the global

warming potential is reduced when monoethanol amine (MEA) based CO2 capture system is employed. Khoo and Tan [158] carried out a detailed LCA on four CO2 recovery technologies, namely chemical absorption, membrane separation, cryogenics and pressure swing adsorption, combined with nine CO2 sequestration systems including six options of ocean sequestration (i.e. vertical injection, inclined pipe, pipe towed by ship, dry ice and gas lift advanced dissolution), and three types of geological sequestration (i.e. EOR, ECBM and saline aquifer). They found that the three geological storage methods induced the least environmental burdens and the deep saline aquifer option (Sleipner project with CO2 storage in the Utsira formation as an example) was the best case scenario, while the ECBM combined with chemical absorption produced the most promising environmental benefit due to its capability to prevent resource depletion. Recently, Singh et al. [162] conducted a LCA of a natural gas combined cycle power plant and found similar GHG reductions as those reported by Odeh and Cockerill [159]. However, a trade-off with other environmental impacts such as acidification, eutrophication and toxicity were found.

9. CO2 leakage and monitoring

One of the important aspects for geological storage is the potential leakage of the stored CO2 that would impair the effectiveness of the CO2 confinement and eventually lead to serious consequences on the surrounding environments, such as acidification and pollution induced by the mobilization of heavy metals [163]. Therefore, studies on leakage/risk assessment have also attracted much attention in CCS studies.

9.1. Potential leakages

There are two possible sources of CO2 leakage: CO2 transport facilities or the storage area. Several studies have been conducted to identify the effect of the atmospheric dispersion of CO2 due to leakage during transportation [164-166]. Dispersion models are normally used to study the plume dispersion due to a particular atmospheric condition and for assessing its effect to the environment. Comparatively, leakage from geological storage areas involves more complex situations and a number of studies have been conducted to assess this issue. There are two common sources of leakage from geological formations: leakage through caprock and leakage through permeable pathways. Normally the leakage through caprock will be slow and may take tens of thousands of years [167], while the leakage through permeable pathways can be faster causing more concerns to the operator [168]. Several studies have been conducted to model the effect of geological CO2 leakage [169-172]. Celia et al. [173] discussed some available analytical and numerical models, and data needed for estimation of CO2 leakage from geological sites. Nordbotten et al. [174] developed a semi-analytical solution for estimating CO2 leakage from injection well, leaky well, and multiple aquifers separated by impermeable aquitards. This served as a foundation for the later development of a novel framework for predicting the leakage from a large number of abandoned wells, and forming leakage paths connecting multiple subsurface permeable formations [175].

Investigations of gas leakage through the cap rock have been conducted by many researchers [176-178]. Li et al. [178] found that the cap rock sealing pressure should be determined before the start of the process, and should not be exceeded during the CO2 injection process to avoid CO2 migration to upper formations which could be more permeable allowing the CO2 to seep into

the surrounding environment and, eventually, back to the atmosphere.

Wells (injection and abandoned) have been identified as the most probable leakage pathway. Therefore, maintaining the wellbore integrity is imperative to guarantee the isolation of geological formations, particularly in basins with a history of oil and gas exploration and production [179].

There are studies regarding the effects of CO2 leakage on human beings [180], plants [181] and marine ecosystems [148,172,182-184]. Due to the important consequences and effects of leakage on our environment, adequate monitoring is necessary in order to establish its potential long term effects on human and our environment, as described in the next section.

9.2. CO2 monitoring

The key feature for geological storage is that CO2 will be retained for extremely long periods, of the order of magnitude of 103 year, without any appreciable seepage back to the surface. Models show that a leakage rate above 0.1% per year will invalidate the effectiveness of CCS in global warming control [185]. Moreover, migration of the injected CO2 inside the storage volume should be monitored to assess that it will not interfere with the surrounding environment and in particular with the groundwater.

The monitoring strategy includes pre-injection, during injection and post-injection phases utilizing a suite of techniques aimed to assure the integrity of the reservoir, the absence of leakages, the quantification of the volumes of the stored CO2 and the identification of the geometry of the injected plume of CO2. Monitoring is also a key to verify the project's aims, including its predicted performance and long term containment.

The variety of monitoring techniques can be grouped into several families, each one having its range of application in function of the data to be acquired and of the environmental condition of the storage area, as shown in Table 9.

Seismic monitoring: Both active and passive systems can be employed. For active seismic, an energy source is used to generate acoustic waves, which will be detected and interpreted to gain information about the underground geology of the storage area; while in passive seismic, the tremors and micro-earthquakes generated by the movement of fluids or by the formation of fractures are recorded by geophones. When used during the pre-injection phase these methods are aimed to identify the characteristics of the storage area and its structural integrity. During the injection and post-injection, seismic is applied to the monitoring of the evolution of the CO2 plume. 3D seismic generates a tridimensional image of the underground structures including the dimension of the injected plume of CO2; time lapse or 4D monitoring is used to track the evolution through the time of the CO2 plume [186,187]. High quality 3D is able to identify CO2 bodies of mass above 106 kg at depths of 1-2 km with optimal results in off-shore monitoring where the presence of water as medium enhances the penetration of the seismic waves [187].

Geoelectrical methods: These are based on the variation of resistivity caused by the presence of CO2. When CO2 displaces fluids with higher conductivity, i.e. brines, the induced variation in resistivity can be measured giving information about the grade of CO2 saturation of the reservoir and the spatial distribution of the injected plume. The bigger the difference in conductivity between CO2 and displaced fluids, the stronger is the signal. Once CO2 is dissolved in water the difference in resistivity will drop below appreciable values, and therefore, this method is only valid for monitoring free CO2 before dissolution [188].

Temperature logs: A range of thermal processes are involved in CO2 injection (i.e. Joule-Thomson cooling, advective heat transfer,

Table 9

Main monitoring tools applied in some of CCS demonstration projects.

Methods Sleipner Frio Nagaoka Ketzin In-Salah Otway Basin Weyburn

3D seismic X X X X X

4D seismic X

Micro-seismic X X X

Vertical seismic X


Gravimetry X X X

Cross-hole X X X



Pressure and X X X


Geochemical X X X X


Soil-gas X X X

Tracers X X X

Atmospheric X


Microbiology X

Core sampling X

InSar X

heat transport) causing changes in temperature around the CO2 plume. Monitoring the variation in temperature can help in identifying the flow paths inside the reservoir. For more reliable results mathematical models can be developed based on the geology of the storage area, the volumes of injected CO2 and its interaction with the surrounding fluids [189].

Gravimetry methods: Changes in underground density due to the injection of CO2 can be detected by small perturbation in the local gravitational field; a loss in density is observed when CO2 displaces denser brine inside the reservoir. Monitoring these changes gives information on the diffusion rate of CO2. Limits are due to the distance between the gravimetric meters and the plume. The shape of the plume also affects the results, with vertically elongated plumes generating a stronger signal than flat spread ones [187].

Remote sensing: The injection of large volumes of fluids in the reservoir, mostly when the hydraulic conductivity is not very high, can generate a certain degree of overpressure leading to deformation of the surface that can be detected by Interferometric Synthetic Aperture Radar (InSAR) airborne or satellite monitoring. This method is based on the use of synthetic aperture radar to map the surface of the storage area through the time identifying the displacements. The injection of 3 Mt CO2 in the In Salah Gas Field (Algeria) caused a lifting of 5 mm/y which was detected by InSAR [190].

Geochemical sampling: It is possible to collect samples of fluids from boreholes inside the storage area and observe the chemical variation induced by the injection of CO2. The most evident effect is a drop in pH and changes in the concentration of minerals, such as carbonates and some silicates, due to the acidification. Measuring the pH drop in groundwater allows the identification of CO2 leakages of the order of 103 t/year [191]. Dissolved gas analysis is also a reliable tool for the quantification of the presence of CO2 in the formation fluids and to track the migration of the CO2 plume [192].

Atmospheric monitoring: CO2 could seep from the reservoir and reach the surface, leaking into the atmosphere. Monitoring the atmospheric concentration of CO2 in the storage area can be used to identify anomalies above the natural baseline. Large natural variation in CO2 values due to soil respiration, organic matter decomposition or peculiar climatic condition may affect the reliability of these techniques [144].

Tracers: Co-injection of specific compounds together with CO2 can generate a specific "fingerprint" of the stored CO2. These tracers can be detected even in very small concentration (ppm) allowing an identification of any seepage from the reservoir. SF6 and CH4 have been used as tracers in the storage of CO2 inside a depleted natural gas field and their presence was identified in samples collected from a monitoring well 700 m from the injection point about 150 days after the beginning of the injection, thus giving an estimate of the diffusivity of the CO2 inside the reservoir [191].

Soil gas: Monitoring the composition of the soil gas, and in particular the concentration of CO2, before the injection defines the baseline. Time lapse monitoring can be used during the injection and post-injection phases to assure the absence of CO2 seepage [192].

Microbiology: Samples of fluids and sediments can be collected before the injection for a baseline on biocenosis to be compared with the modification induced by the presence of CO2. Biological analysis is useful to identify biogeochemical processes which can affect the diffusion of CO2 within the reservoir [193].

10. Barriers and opportunities for commercial deployment

CCS is considered to be a crucial part of worldwide efforts to combat global warming by reducing greenhouse gas emission. It was estimated that about 100 CCS projects need to be implemented by 2020 and over 3000 by 2050 in order to reach the goal of restoring the global temperature by 2 °C [194]. Although some of the technologies regarding CCS have been proven, comprehensive CCS projects involving large scale capture and storage are not operational. According to the Global CCS Institute's 2012 project survey 73 large scale integrated CCS projects have been identified around the world, only 15 of them are currently operating or in construction, capturing 35.4 Mt CO2 per year, and the rest of the projects are in the planning stage of development [21]. It has been noted that five power generation CCS projects were removed from the Institute's 2011 listing.

IEA [165] pointed out a number of barriers of implementation of CCS, and recommended rules and standards for the transport and storage of CO2 as follows [31]:

• Lack of a market mechanism/incentive that is sufficiently large and long term enough to reward an entity with carbon reduction using CCS technologies;

• No mechanism to penalize those major CO2 emitting sources;

• Inadequate legal framework allowing transport and geological storage of CO2 for both inland and offshore storage;

• Most of the current storage practices/demonstration projects are related to EOR or ECBM, which are more financially viable but have limited CO2 storage capacity as compared to ocean and deep saline aquifers; demonstration in the latter two technologies need to be enhanced.

More recently DECC [195] identified a series of key points through the CCS chain to make its development an economically feasible solution:

• Identification of reliable storage sites with capability of switching between the sites in case a backup is needed;

• Use clusters of storage sites as "hubs" where different CO2 sources can be delivered thus reducing the cost by sharing the infrastructures;

• Develop a large scale network of pipelines with reduction of the transport costs following the increasing of the transported volumes;

• Scaling up the CCS projects;

• Reduction in the energy penalty associated with capturing CO2 from power plants;

• Assuring financial stability to the CCS projects by a regulatory and policy framework;

• Further explore the effectiveness of EOR in offsetting part of the costs associated with CCS;

• Identify other CO2 sources than power generation which can be used for CCS.

There are no major technological barriers to the capture and geological storage of CO2 for existing operation but noted that CCS is an energy intensive process that lowers the overall efficiency of the concerned energy/power generating systems. It is inevitable that the costs, both capital and operation, involved in plants equipped with CCS are much higher than those without capture due to the reduction in efficiency and additional capital cost for installing the capture, transport and injection facilities. The high cost of CO2 capture, particularly for dilute streams like those from gas-fired power plants and industrial combustion processes is the major challenge of CCS [171]. Page et al. [196] compared the energy for CCS and efficiency penalty for different types of power plants and found that there are wide variations even for the same type of power plants. Part of the costs associated with CCS could be offset by using the CO2 for economically productive application. EOR/ECBM in USA may allow the storage of up to 10,500 MtCO2 generating revenue which should exceed the CCS costs; 78% of this low cost EOR is estimated to be used within a 20 years' time. In China 5500 MtCO2 can be used for 99% EOR within the first 20 years. Further 2000-2,500 MtCO2 may be transported and stored at an average cost of 4.89 USD/tonne CO2 for USA and 4.51 USD/ tonne CO2 for China. Adding the capture phase the overall cost will be increased from 40 USD/tonne CO2 up to 70 USD/tonne CO2 in China [197,198]. Considering CCS applied to power plants the cost of capture in USA will range from 4.5 USD/tonne CO2 for coal based integrated gasification combined cycle power plant with EOR to 72.4 USD/tonne CO2 for natural gas combined cycle with storage in saline formations [199].

Estimates of the total cost associated with CCS for electricity production are in the range of 60-100 USD/tonne CO2; the recent reduction in price of natural gas is leading to lower cost for gas-fired power plants if compared with coal-fired ones [200]. In general, the cost of CO2 capture is ~ 70-80% of the total costs of a carbon capture, transport and storage system [6,32]. Therefore, significant research efforts are underway to reduce the costs of capture. On the other hand study indicated that the cost of CO2 avoided is from 23 to 92 USD for coal plants and from 67 to 106 USD for natural gas plants, which are much higher than other renewable energy technologies such as hydropower and onshore wind farms [89]. However, study indicated that with increased R&D and accumulation of experience in CCS technologies, the cost of CCS can be reduced by 50% between 2008 and 2020 [201].

A general bias of cost estimates in CCS is their large range of uncertainty, mostly due to the fact that so far no large scale power plant with integrated CCS is operating. The cost of the avoided CO2 will also vary between the retrofitting of an existing power plant and a new one with built-in CCS; the retrofitting costs being higher mostly when considering coal-fired electricity generation. Moreover, a real reduction in atmospheric injection of CO2 will be fully achieved only if a new CCS-equipped power plant is going to replace an older one. The development of a CO2 tax aimed to penalize the CO2 emitters will also play an important role in the overall cost estimates. Any cost comparison should be therefore carefully and critically addressed [202,203]. Kenney and Basu [204] identified a number of challenges that could hinder the

achievement of a strategy for CO2 reduction and highlight the importance of incentives to entice the engagement of countries.

Although much of the current discussion on CCS is focused on coal, a recent report by Green-Alliance [205] indicated that CCS could potentially be fitted on 50-100 GW of gas-fired capacity in Europe by 2030 with suitable policy action. Similarly, significant less attention has been paid to CCS for non-power applications, such as cement, steel and refinery, and hence there is relatively less knowledge about the required instrumentation and infrastructures for the deployment of CCS in the industrial sector [206,207].

Apart from conventional carbon capture and storage methods, there is increasing interest in some innovative ways of carbon reduction such as using biochar and biological CO2 mitigation. Biochar (produced from pyrolysis of biomass) production and storage in soils can provide simultaneous benefits for carbon sequestration, provision of energy and soil conditioning that can restore degraded agricultural land and increase crop yields [208,209]. Its role for carbon sequestration was included in the Agenda for the 2009 UNFCCC Copenhagen climate change negotiations. In recent years microalgae has emerged as a promising option for biological CO2 fixation and intensive research has been carried out to develop feasible systems for removing CO2 from industrial exhaust gases. Lenton [210] conducted a review on land-based biological CO2 removal and storage methods including biochar production and bioenergy with CO2 capture and storage. The review suggests that there is already the potential to counterbalance land use change CO2 emissions and by the end of the century, CO2 removal could exceed CO2 emissions, thus lowering atmospheric CO2 concentration and global temperature. Although the above innovative mitigation technologies and measures may be able to break some of the barriers for commercial deployment of CCS systems, further R&D is needed on the optimal implementation plan and system.

11. Conclusions

In order to meet GHG emissions reduction target, a complimentary range of technological approaches, including improving energy efficiency and conservation, adopting clean fuels and clean coal technologies, developing renewable energy, and implementing CCS, has been considered by various countries according to their own circumstances. It is noted that CCS comprises a portfolio of technologies that can massively reduce CO2 emissions, but CCS is yet to be widely deployed. This paper has reviewed various technologies and issues related to CO2 capture, separation, transport, storage and monitoring. The selection of specific CO2 capture technology heavily depends on the type of the plant and fuel used, where for gas-fired power plants, post-combustion capture technology was found generally to be the technology due to its lower cost. Absorption is the most mature CO2 separation process, due to its high efficiency and lower cost; although issues related to environmental impact have to be fully understood.

The best option for CO2 transport will depend on a variety of parameters including:

• Volumes of CO2 to be transported;

• Planned lifetime of the CO2 source (e.g. power plants, steel and cement factories);

• Distance between CO2 source and storage area;

• Onshore vs. offshore transport and storage;

• Typology of transporting infrastructure available (i.e. road and rail networks, pipelines trunks, shipping docks facilities).

Pipeline is considered to be the most viable solution if large volumes of CO2 are available for long time and if a trunk of

pipelines can be developed; further advantage is represented by the potential reuse of pipelines for gas or oil transport. In case of offshore storage shipping the CO2 by tankers can be economically competitive due to the high capital costs involved in the deployment of submarine pipelines. The costs of intermediate storage facilities and suitable docking for the tankers should be addressed when ships are used as CO2 carriers.

Four main types of geological formations are considered for CO2 storage:

• Depleted oil and gas reservoirs;

• Unmineable coal beds;

• Saline aquifers;

• Basalts.

In case of storage in oil and gas reservoir the technology already used for enhanced oil recovery (EOR) is mature and has been practiced for many years using natural CO2 sources and mostly on-shore. However, the economical feasibility of using captured CO2 from anthropogenic sources for EOR has not been fully demonstrated yet mostly for offshore storage. The use of unmineable coal beds, eventually recovering methane by Enhanced Coal Bed Methane (ECBM) recovery, can be an option but it will make the coal used for CO2 storage unavailable even if future mining technology and economical consideration should make it of commercial value. On the other hand, there are growing interests in CO2 storage in saline aquifers, due to their enormous potential storage capacity and several projects are in development both onshore and offshore. Basalts represent an extremely large volume for CO2 storage which will be fixed as carbonate minerals following chemical reaction with the minerals of the hosting rocks. A number of uncertainties ranging from the need of an extremely detailed knowledge of the stratigraphic structure of the basalts to fully understanding of the chemical reaction still limit their use.

Potential CO2 leakage is a major concern for geological storage and a comprehensive monitoring program needs to be developed. A number of monitoring technologies have been described in this paper to be applied according to the special environmental conditions of the storage site.

Although technologies regarding the capture and storage of CO2 exist, the overall cost of using current CCS procedures is still high and must be substantially reduced before it can be widely deployed. There are multiple hurdles to CCS deployment that need to be addressed in the coming years, including the absence of a clear business case for investment in CCS, and the absence of robust economic incentives to support the additional high capital and operating costs associated with CCS.


The first author would like to acknowledge the support of ACU for providing the Titular Fellowship for this study. Support from the Center for Innovation in Carbon Capture and Storage (Engineering and Physical Sciences Research Council grant EP/F012098/ 1 and EP/F012098/2) is gratefully acknowledged.


[1] Emission database for global atmospheric research EDGAR, European Commission. <> = C02ts1990-2011.

[2] IPCC fourth assessment report: climate change 2007 (AR4) from IPCC website [< ports.shtml/>; 2007.

[3] NOAA, National oceanic and atmospheric administration, <http://www.esrl.>; 2013.

IPCC. Special report on emissions scenarios: a special report of working group III of the Intergovernmental Panel on Climate Change. New York: Cambridge University Press; 92-9169-1135.

IPCC fourth assessment report: climate change 2013 (AR5) from IPCC website < >; 2013.

IPCC. Special report on carbon dioxide capture and storage. New York:

Cambridge University Press; 2005 (ISBN:92-9169-1190-4).

Kheshgi H, de Conninck H, Kessels J. Carbon dioxide capture and storage:

seven years after the IPCC special report. Mitig Adapt Strat Glob Change


Knoope MMJ, Ramirez A, Faaij APC. A state of the art review of techno-economic models predicting the costs of CO2 pipeline transport. Int J Greenh Gas Control 2013;16:241-70.

Lv YX, Xu CQ, Yan GH, Guo DY, Xiao Q. A review on CO2 capture using membrane gas absorption technology. Adv Mater Res 2012;616-618:1541-5. Maroto-Valer MM, editor. Developments and innovation in carbon dioxide (CO2) capture and storage technology, 2 volumes. New York. ISBN: 978-14398-3099-4 (V1) and 978-1-84569-797-6 (V2).

Prelicz RM, Mackie EAV, Otto CJ. Methodologies for CO2 storage capacity estimation: review and evaluation of CO2 storage. First Break 2012;30/ 2:70-8.

Thomas L, Schneider M, Winkler A. Threats to the quality of water resources by geological CO2 storage: hydrogeochemical and other methods of investigation: a review. (The Handbook of Environmental Chemistry 2013). In: Scozzari A, Dotsika E, editors. Threats to the quality of groundwater resources: prevention and control; 2013.

Yang HQ, Xu Z, Gupta R, Slimane RB, Bland AE, Wright I. Progress in carbon dioxide separation and capture: a review. J Environ Sci 2008;20:14-27. Blomen E, Hendriks C, Neele F. Capture technologies: improvements and promising developments. Energy Procedia 2009;1:1505-12. Wall TF. Combustion processes for carbon capture. In: Proceedings of the combustion institute, vol. 31; 2007. p. 31-47.

de Visser E, Hendricks C, Barrio M, Molnvik MJ, de Koeijer G, Liljemark S, et al. Dynamics CO2 quality recommendations. Int J Greenh Gas Control 2008;2:478-84.

ICF. Developing a pipeline infrastructure for CO2 capture and storage; issues and challenges. Technical report prepared for INGAA Foundation. 2009 (106 pp.).

Olajire AA. CO2 capture and separation technologies for end-of-pipe application - a review. Energy 2010;35:2610-28.

Elwell LC, Grant WS. Technology options for capturing CO2 - special reports. Power 2006;150:60-5.

Kanniche M, Gros-Bonnivard R, Jaud P, Valle-Marcos J, Amann JM, Bouallou C. Pre-combustion, post-combustion and oxy-combustion in thermal power plant for CO2 catpure. Appl Therm Eng 2010;30:53-62. Global CCS Institute. Global status of large scale integrated projects: June 2012 update. < globalstatusoflargescaleintegratedprojectsjune2012update.pdf>; 2012a. Global CCS Institute. CO2 capture technologies: precombustion with CO2 capture: January 2012b. < publications/ 29756/co2-capture-technologies-pre-combustion-capture. pdf>; 2012b.

Nord LO, Anantharaman R, Bolland O. Design and off-design analyses of a pre-combustion CO2 capture process in a natural gas combined cycle power plant. Int J Greenh Gas Control 2009;3:385-92.

Hoffmann S, Bartlett M, Finkenrath M, Evulet A, Ursin TP. Performance and

cost analysis of advanced combined cycles with precombustion CO2 capture.

J Eng Gas Turbines Power 2009;131 (021701-1 to 7).

Buhre BJP, Elliott LK, Sheng CD, Gupta RP, Wall TF. Oxy-fuel combustion

technology for coal-fired power generation. Prog Energy Combust Sci


Zero, Zero Emissions Resource Organization, <>; 2013. Pfaff I, Kather A. Comparative thermodynamic analysis and integration issues of CCS steam power plants based on oxy-combustion with cryogenic or membrane based air separation. Energy Procedia 2009;1:495-502. Burdyny T, Struchtrup H. Hydrid membrane/cryogenic separation of oxygen from air for use in the oxy-fuel process. Energy 2010;35:1884-97. Global CCS Institute. CO2 capture technologies: oxycombustion with CO2 capture: January 2012. < publications/29761/co2-capture-technologies-oxy-combustion.pdf>; 2012c. Bhown AS, Freeman BC. Analysis and status of post-combustion carbon dioxide capture technologies. Environ Sci Technol 2011;45:8624-32. Gibbins J, Chalmers H. Carbon capture and storage. Energy Policy 2008;36:4317-22.

International Energy Agency Report. Capturing CO2. IEA Greenhouse Gas R&D Programme 2007 isbn:978-1-898373-41-4; 2007. Hendriks C. Energy conversion: CO2 removal from coal-fired power plant. Netherlands: Kluwer Academic Publishers; 1995.

Veawab A, Aroonwilas A, Tontiwachwuthiku P. CO2 absorption performance of aqueous alkanolamines in packed columns. Fuel Chem Div P Repr 2002;47:49-50.

Aaron D, Tsouris C. Separation of CO2 from flue gas: a review. Sep Sci Technol 2005;40:321-48.

[37 [38 [39 [40 [41

[42 [43 [44 [45

[46 [47 [48

[53 [54 [55

[61 [62

Knudsen JN, Jensen JN, Vilhelmsen PJ, Biede O. Experience with CO2 capture from coal flue gas in pilot-scale: testing of different amine solvents. Energy Procedia 2009;1:783-90.

Gurkan BE, de la Fuente FC, Mindrup EM, Ficke LE, Goodrich BF, Price EA, etal. J Am ChemSoc 2010;132:2116-7.

Bougie FF, Iliuta MC. CO2 absorption in aqueous piperazine solutions: experimental study and modeling. J Chem Eng Data 2011;56:1547-54. Rochelle GT. Thermal degradation of amines for CO2 capture. Curr Opin Chem Eng 2012;1-2:183-90.

Fredriksen SB, Jens KJ. Oxidative degradation of aqueous amine solutions of MEA, AMP, MDEA, Pz; a review. Energy Procedia 2013;37:1770-7. da Silva CF, Dias APB, Santana APR, Pizzo JS, de Souza FM, Lazarin AM, et al. Intercalation of amines into layered calcium phosphate and their new behavior for copper retention from ethanolic solution. Open J Synth Theory Appl 2013;2:1-7.

Kozak F, Petig A, Morris E, Rhudy R, Thimsen D. Chilled ammonia process for CO2 capture. Energy Procedia 2009;1:1419-26.

Takamura Y, Narita S, Aoki J, Uchida S. Application of high-PSA process for improvement of CO2 recovery system. Can J Chem Eng 2001;79:812-6. McKee B. Solutions for the 21st Century: zero emissions technology for fossil fuels. France: IEA, Com. Energy Research and Technology. OECD/iEa; 2002. Clausse M, Merel J, Meunier F. Numerical parametric study on CO2 capture by indirect thermal swing adsorption. Int J Greenh Gas Control 2011;5:1206-13.

Kulkarni AR, Sholl DS. Analysis of equilibrium-based TSA processes for direct capture of CO2 from air. Ind Eng Chem Res 2012;51:8631-45. Maroto-Valer MM, Lu Z, Zhang Y, Tang Z. Sorbents for CO2 capture from highcarbon fly ashes. Waste Manag 2008;28:2320-8.

Olivares-Marín M, Maroto-Valer MM. Preparation of a highly microporous carbon from a carpet material and its application as CO2 sorbent. Fuel Process Technol 2010;92:322-9.

Olivares-Marín M, Drage TC, Maroto-Valer MM. Novel lithium-based sor-bents from fly ashes for CO2 capture at high temperatures. Int J Greenh Gas Control 2010;4(4):623-9.

Olivares-Marin M, Maroto-Valer MM. Development of adsorbents for CO2 capture from waste materials: a review. Greenh Gases Sci Technol 2012;2:20-35.

Ishida M, Yamamoto M, Ohba T. Experimental results of chemical looping combustion with NiO/NiAl2O4 particle circulation at 1200 °C. Energy Convers Manag 2002;43:1469-78.

Cho P, Mattisson T, Lyngfelt A. Reactivity of iron oxide with methane in a laboratory fluidized bed - application of chemical-looping combustion. In: Proceedings of the 7th international conference on circulating fluidised beds. Niagara Falls, Ontario; May 5-7, 2002. p. 599-606.

Brandvoll 0, Bolland O. Inherent CO2 capture using chemical looping combustion in a natural gas fired power cycle. ASME J Eng Gas Turbines Power 2004;126:316-21.

Adánez J, de Diego LF, García-Labiano F, Gayán P, Abad A, Palacios JM. Selection of oxygen carriers for chemical-looping combustion. Energy Fuels 2004;18:371-7.

Zafar Q, Mattisson T, Gevert B. Integrated hydrogen and power production with CO2 capture using chemical-looping reforming-redox reactivity of particles of CuO, Mn2O3, NiO, and Fe2O3 using SiO2 as a support. Ind Eng Chem Res 2005;44:3485-96.

Li F, Luo S, Sun Z, Bao X, Fan LS. Role of metal oxide support in redox reactions of iron oxide for chemical looping applications: experiments and density functional theory calculations. Energy Environ Sci 2011;4:3661-7. Lyngfelt A, Leckner B, Mattisson T. A fluidized-bed combustion process with inherent CO2 separation; application of chemical-looping combustion. Chem Eng Sci 2001;56:3101-13.

Lyngfelt A, Mattisson T. Materials for chemical-looping combustion. In: Stolten D, Scherer V, editors. Efficient carbon capture for coal power plants. Weinheim: Wiley-VCH Verlag GmbH & Co. KGaA; 2011. p. 475-504. Adánez J, Abad A, Garcia-Labiano F, Gayan P, de Diego L. Progress in chemical-looping combustion and reforming technologies. Prog Energy Combust Sci 2012;38:215-82.

Erlach B, Schmidt M, Tsatsaronis B. Comparison of carbon capture IGCC with pre-combustion decarbonisation and with chemical-looping combustion. Energy 2011;36:3804-15.

Rackley SA. Carbon capture and storage. Burlington, USA: ButterworthHeinemann, Elsevier; 2010.

Audus H. Leading options for the capture of CO2 at power stations. In: Proceedings of the 5th international conference on greenhouse gas control technology. Cairns, Australia; August 13-16, 2000.

Gielen D. Energy policy consequences of future CO2 capture and sequestration technologies. In: Proceedings of the 2nd annual conference on carbon sequestration. Alexandria, VA; May 5-8, 2003.

Yave W, Car A, Funari SS, Nunes SP, Peinemann KV. CO2-philic polymer membrane with extremely high separation performance. Macromolecules 2009;43:326-33.

Brunetti A, Scura F, Barbieri G, Drioli E. Membrane technologies for CO2 separation. J Membr Sci 2010;359:115-25.

Bernardo P, Drioli E, Golemme G. Membrane gas separation: a review/state of the art. Ind Eng Chem Res 2009;48:4638-63.

[71 [72 [73

[74 [75

[78 [79 [80 [81

[83 [84 [85

[88 [89 [90

[92 [93 [94

[98 [99

Fan S, Wang Y, Lang X. CO2 capture in form of clathrate hydrate-problem and practice. In: Proceedings of the 7th international conference on gas hydrates (iCGH 2011), UK; July 17-21, 2011.

Englezos P, Ripmeester JA, Kumar R, Linga P. Hydrate processes for CO2 capture and scale up using a new apparatus. In: Proceedings of the international conference on gas hydrates, ICGH; 2008. Zhang Y, Yang M, Song Y, Jiang L Li Y, Cheng C. Hydrate phase equilibrium measurements for (THF+SDS+CO2+N2) aqueous solution systems in porous media. Fluid Phase Equilib 2014;370:12-8.

Babu P, Kumar R, Linga P. Progress on the hydrate based gas separation (HBGS) process for carbon dioxide capture. AICHE annual meeting. San Francisco, USA; 3-8 November 2013.

Sun D, Englezos P. Storage of CO2 in a partially water saturated porous medium at gas hydrate formation conditions. Int J Greenh Gas Control 2014;25:1-8. Gottlicher G, Pruschek R. Comparison of CO2 removal systems for fossil fuelled power plants. Energy Convers Manag 1997;38:S173-8. Burt SS, Baxter A, Bence C, Baxter LL. Cryogenic CO2 capture for improved efficiency at reduced cost. In: Proceedings of the AICHE 2010 annual meeting; November 7-12, 2010.

Tuinier MJ, Annaland MVS, Kramer GJ, Kuipers JAM. Cryogenic CO2 capture using dynamically operated packed beds. Chem Eng Sci 2010;65:114-9. Besong M, Maroto-Valer MM, Finn A. Study of design parameters affecting the performance of CO2 purification units in oxy-fuel combustion. Int J Greenh Gases 2013;12:441-9.

Aspelund A, Molnvik MJ, De Koeijer G. Ship transport of CO2, technical solutions and analysis of costs, energy utilization, energy efficiency and CO2 emissions. Chem Eng Res Des 2006;84(A9):847-55.

Svensson R, Odenberger M, Johnsson F, Stromberg L. Transportation systems for CO2 - application to carbon capture and storage. Energy Convers Manag 2004;45:2343-53.

Norisor M, Badea A, Dinca C. Economical and technical analysis of CO2 transport ways. U.P.B. Sci Bull Series C 2012;74(1):127-38. Gao L, Fang M, Li H, Hetland J. Cost analysis of CO2 transportation: case study in China. Energy Procedia 2011;4:5974-81.

Johnsen K, Helle K, Roneid S, Holt H. DNV recommended practice: design and operation of CO2 pipelines. Energy Procedia 2011;4:3032-9. Forbes SM, Verma P, Curry TE, Friedmann SJ, Wade SM. Guidelines for carbon dioxide capture, transport, and storage. World Resour Inst 2008 20113082154 (144 pp.).

International Energy Agency Report. CO2 pipeline infrastructure: an analysis of global challenges and opportunities. Element Energy Limited. Final Report. 2010 (134 pp.).

FEED. CO2 transport pipeline. Except for public use. Vattennfal Europe. Job n. P10111; 2011. 143 pp.

Gale J, Davison J. Transmission of CO2-safety and economic considerations. Energy 2004;29:1319-28.

Parfomak PW, Folger P, Vann A. Carbon dioxide (CO2) pipelines for carbon sequestration: emerging policy issues. Congressional research service report. 2009 (21 pp.).

Chandel MK, Pratson LF, Williams E. Potential economies of scale in CO2 transport through use of a trunk pipeline. Energy Convers Manag 2010;51: 2825-2834.

Rabimdran P, Cote H, Winning IG. Integrity management approach to reuse of oil and gas pipelines for CO2 transportation. In: Proceedings of the 6th Pipeline Technology Conference. Hannover Messe, Hannover, Germany; 0405 April 2011.

DNV. Design and operation of CO2 pipelines. Det Norke Veritas. Recommended Practice DNV-RP-J202; 2010. 42 pp.

Global CCS Institute (2012). The Global Status of CCS. Canberra, Australia; 2012. 228 pp.

Kikuchi R. CO2 recovery and reuse in the energy sector, energy resource development and others: economic and technical evaluation of large-scale CO2 recycling. Energy Environ 2003;14:383-95.

Dooley JJ, Davidson CL, Dahowski RT. An assessment of the commercial availability of carbon dioxide capture and storage technologies as of June 2009. Report for the US Department of Energy under a contract no. DE-AC05-T6RL01830, PNNL-18520; 2009.

Aresta M, Dibenedetto A. Utilisation of CO2 as a chemical feedstock: opportunities and challenges. Dalton Trans 2007;28:2975-92. Oldenburg CM. Why we need the and in CO2 utilization and storage, greenhouse gases: science and technology, 2/1; 2013. p. 1-2. Oldenburg CM. Carbon dioxide as cushion gas for natural gas storage. Energy Fuels 2003;17:240-6.

Seifritz W. CO2 disposal by means of silicates. Nature 1990;345:486. Park AHA, Fan LS. CO2 mineral sequestration: physically activated dissolution of serpentine and pH swing process. Chem Eng Sci 2004;59:5241-7. Kodama S, Nishimoto T, Yamamoto N, Yogo K, Yamada K. Development of a new pH-swing CO2 mineralization process with a recyclable reaction solution. Energy 2008;33:776-84.

Eloneva S, Said A, Fogelholm KJ, Zevenhoven R. Preliminary assessment of a method utilizing carbon dioxide and steelmaking slags to produce precipitated calcium carbonate. Appl Energy 2012;90:329-34. Sanna A, Dri M, Hall MR, Maroto-Valer MM. Micro-silica for high-end application from carbon capture and storage by mineralisation. Key Eng Mater 2012;517:737-44.

[102 [103 [104

[110 [111 [112

[113 [114 [115 [116 [117

[121 [122

[126 [127

[129 [130

Sanna A, Dri M, Hall MR, Maroto-Valer MM. Waste materials as a potential resource for carbon capture and storage by mineralisation (CCSM) in the UK context. Appl Energy 2012;99:545-54.

Dri M, Sanna A, Maroto-Valer MM. Dissolution of steel slag and recycled concrete aggregate in ammonium bisulphate for CO2 mineral carbonation. Fuel Process Technol 2013;113:114-22.

Wang X, Maroto-Valer MM. Dissolution of serpentine using recyclable ammonium salts for CO2 mineral carbonation. Fuel 2011;90:1229-37. Wang X, Maroto-Valer MM. Integration of CO2 capture and mineral carbona-tion by using recyclable ammonium salts. ChemSusChem 2011;4:1291-300. Wang X, Maroto-Valer MM. Optimization of carbon dioxide capture and storage with mineralisation using recyclable ammonium salts. Energy 2013;2013(51):431-8.

Roy SC, Varghese OK, Paulose M, Grimes CA. Toward solar fuels: photo-catalytic conversion of carbon dioxide to hydrocarbons. ACS Nano 2010;4/ 3:1259-78.

Liu Q, Maroto-Valer MM. Studies of pH buffer systems to promote carbonates formation for CO2 sequestration in brines. Fuel Process Technol 2012;98: 6-13.

Tan JZY, Fernandez Y, Liu D, Maroto-Valer MM, Bian JC, Zhang XW. Photo-reduction of CO2 using copper-decorated TiO2 nanorod films with localized surface Plasmon behavior. Chem Phys Lett 2012;531:149-54. Liou P-Y, Chen S-C, Wu JCS, Liu D, Mackintosh S, Maroto-Valer M, et al. Photocatalytic CO2 reduction using an internally illuminated monolith photoreactor. Energy Environ Sci 2011;4:1487-94.

Tseng IH, Chang W-C, Wu JCS. Photoreduction of CO2 using sol-gel derived titania and titania-supported copper catalysts. Appl Catal B Environ 2002;37:37-48.

Huang C, Yao W, Raissi AT, Muradov N. Development of efficient photo-reactors for solar hydrogen production. Sol Energy 2011;85:19-27. de la Calle A, Roca L, Yebra LJ, Dormido SN. Modeling of a two-step solar hydrogen production plant. Int J Hydrog Energy 2012;37:10549-56. Usubharatana P, McMartin D, Veawab A, Tontiwachwuthikul P. Photocatalytic process for CO2 emission reduction from industrial flue gas streams. Ind Eng Chem Res 2006;45/8:2558-68.

Celia MA, Nordbottena JM. Practical modeling approaches for geological

storage of carbon dioxide. Ground Water 2009;47:627-38.

Van der Zwaan B, Smekens K. CO2 capture and storage with leakage in an

energy-climate model. Environ Model Assess 2009;14:135-48.

Yang F, Bai BJ, Tang DZ, Dunn-Norman S, Wronkiewicz D. Characteristics of

CO2 sequestration in saline aquifers. Pet Sci 2010;7:83-92.

Myer L. Global status of geologic CO2 storage technology development.

United States carbon sequestration council report July 2011. 2011.

Doughty C, Freifeld BM, Trautz RC. Site characterization for CO2 geological

storage and vice versa: the Frio brine pilot, Texas, USA as a case study.

Environ Geol 2008;54:1635-56.

Solomon S, Carpenter M, Flach TA. Intermediate storage of carbon dioxide in geological formations: a technical perspective. Int J Greenh Gas Control 2008;2:502-10.

Bachu S. Sequestration of CO2 in geological media: criteria and approach for site selection in response to climate change. Energy Convers Manag 2000;41:953-70.

International Energy Agency Report. Improvements in power generation with post-combustion capture of CO2. IEA Greenhouse Gas R&D Programmes, PH4/33; 2004.

Blunt M, Fayers FJ, Orr FM. Carbon dioxide in enhanced oil recovery. Energy Convers Manag 1993;34:1197-204.

Vidiuk K, Cunha LB. A simulation study of effects of operational procedures in CO2 flooding projects for EOR and sequestration. In: Proceedings of the Canadian international petroleum conference. Calgary, Alberta; June 12-14, 2007.

Chiaramonte L, Zoback M, Friedmann J, Stamp V, Zahm C. Fracture characterization and fluid flow simulation with geomechanical constraints for a CO2-EOR and sequestration project Teapot Dome Oil Field, Wyoming, USA. Energy Procedia 2011;4:3973-80.

Preston C, Moneab M, Jazrawib W, Brown K, Whittakerd S, Whitee D, et al. IEA GHG Weyburn CO2 monitoring and storage project. Fuel Process 2005;86:1547-68.

Cantucci B, Montegrossi G, Vaselli O, Tassi F, Quattrocchi F, Perkins EH. Geochemical modeling of CO2 storage in deep reservoirs: the Weyburn Project (Canada) case study. Chem Geol 2009;265:181-97. Klusman RW. Evaluation of leakage potential from a carbon dioxide EOR/ sequestration project. Energy Convers Manag 2003;44:1921-40. White CM, Strazisar BR, Granite EJ, Hoffman JS, Pennline HW. Separation and capture of CO2 from large stationary sources and sequestration in geological formations—coalbeds and deep saline aquifers. J AWMA 2003;53:645-715. Stenvens SH, Kuuskraa VA, Spector D, Riemer P. CO2 sequestration in deep coal seams: pilot results and worldwide potential. In: Proceedings of the 4th international conference on greenhouse gas control technologies (GHGT). Interlaken, Switzerland, August 30-September 2,1998, Elsevier; 1999. p. 175-80. Gunter WD. CO2 sequestration in deep unmineable coal seams. In: Conference Proceedings; CAPP/CERI industry best practices conference; 2000. p. 1 - 19.

Kelafant JR, Stevens SH, Boyer II CM. Coalbed gas-2: vast resource potential exists in many countries. Oil Gas J 1992;90:80-5.

160 161

Fujioka M, Yamaguchi S, Nako M. CO2-ECBM field tests in the Ishikari Coal Basin of Japan. Int J Coal Geol 2010;82:287-98.

Singh N. Deep saline aquifiers for sequestration of carbon dioxide. In:

International geological congress, Oslo; August 2008.

Garcia S, Kaminska A, Maroto-Valer MM. Underground carbon dioxide

storage in saline formations. Waste Resour Manag 2010;163:77-88.

DoE US. Carbon sequestration research and development; DOE/SC/FE-1.

Washington DC: U.S. Department of Energy; 1999.

Druckenmiller M, Maroto-Valer MM, Hill MA. Investigation of carbon sequestration via induced calcite formation in natural gas well brine. Energy Fuels 2006;20:172-9.

Liu Q, Maroto-Valer MM. Investigation of the pH effect of a typical host rock and buffer solution on CO2 sequestration in synthetic brines. Fuel Process Technol 2010;91(10):1321-9.

Liu Q, Maroto-Valer MM. Parameters affecting mineral trapping of CO2 sequestration in brines. Greenh Gases Sci Technol 2011;1(3):211-22. Liu D, Fernandez Y, Ola O, Mackintosh S, Maroto-Valer MM, Parlett CMA, et al. On the impact of Cu dispersion on CO2 photoreduction over Cu/TiO2. Catal Commun 2012;25:78-82.

Szulczewski ML, MacMinn CW, Juanes R. Theoretical analysis of how pressure buildup and CO2 migration can both constrain storage capacity in deep saline aquifers. Int J Greenh Gas Control 2014;23:113-8. Arts R, Zweigel P, Lothe A. Reservoir geology of the Utsira Sand in the Southern Viking Graben area - a site for potential CO2 storage. In: 62nd EAGE meeting, paper B-20. Glasgow; 2000.

Korboel R, Kaddour A. Sleipner Vest CO2 disposal—injection of removed CO2 into the Utsira formation. Energy Convers Manag 1995;36:509-12. Kongsjorden H, Karstad O, Torp TA. Saline aquifer storage of carbon dioxide in the Sleipner Project. Waste Manag 1997;17:303-8. Rai V, Chung NC, Thurber MC, Victor DG. PESD carbon storage project database. Working paper#76, The program on energy and sustainable development, Stanford University, Available at SSRN: <> or ssrn.1400118; 2008.

Michael K, Golab A, Shulakova V, Ennis-King J, Allinson G, Sharma S, et al. Geological storage of CO2 in saline aquifers - a review of the experience from existing storage operations. Int J Greenh Gas Control 2010;4:659-67. Yamasaki A. An overview of CO2 mitigation options for global warming -emphasizing CO2 sequestration options. J Chem Eng Jpn 2003;36:361-75. House KZ, Schrag DP, Harvey CF, Lackner KS. Permanent carbon dioxide storage in deep-sea sediments. Proc Natl Acad Sci USA 2006;103:12291-5. Adam EE, Caldeira K. Ocean storage of CO2. Elements 2008;4:319-24. Seibel BA, Walsh PJ. Potential impacts of CO2 injection on deep-sea biota. Science 2001;294:319-20.

Hall-Spencer JM, Rodolfo-Metalpa R, Martin S, Ransome E, Fine M, Turner SM, et al. Volcanic carbon dioxide vents show ecosystem effects of ocean acidification. Nature 2008;45:96-9.

Rodolfo-Metalpa1 R, Houlbreque F, Tambutte E, Boisson F, Baggini C, Patti FP, et al. Coral and mollusc resistance to ocean acidification adversely affected by warming. (online 21 August 2011). Nat Clim Change 2011. NCLIMATE1200.

Espa S, Caramanna G, Bouche V. Field study and laboratory experiments of bubble plumes in shallow seas as analogues of sub-seabed CO2 leakages. Appl Geochem 2010;25:696-704.

Caramanna G, Wei Y, Maroto-Valer MM, Nathanail P, Steven M. Laboratory experiments and field study for the detection and monitoring of potential seepage from CO2 storage sites. Appl Geochem 2013;30:105-13. Oelkers EH, Gislason SR, Matter J. Mineral carbonation of CO2. Elements 2008;4-5:333-7.

Matter JM, Kelemen PB. Permanent storage of carbon dioxide in geologic reservoirs by mineral carbonation. Nat Geosci 2009;2:837-41. Goldberg DS, Kent DV, Olsen PE. Potential on-shore and off-shore reservoirs for CO2 sequestration in Central Atlantic magmatic province basalts. PNAS 2010;107:1327-32.

Schaef HT, McGrail BP, Owen AT. Carbonate mineralization of volcanic province basalts. Int J Greenh Gas Control 2010;4:249-61. Directive 2009/31/EC. Guidance Document 1 CO2 storage life cycle risk management framework; 2009.

Khoo H, Tan RBH. Life cycle investigation of CO2 recovery and sequestration. Env Sci Technol 2006;40:4016-24.

Odeh NA, Cockerill TT. Life cycle GHG assessment of fossil fuel-power plants with carbon capture and storage. Energy Policy 2008;36:367-80. Pehnt M, Henkel J. Life cycle assessment of carbon dioxide capture and storage from lignite power plants. Int J Greenh Gas Control 2009;3:49-66. Schreiber A, Zapp P, Kuckshinrichs W. Environmental assessment of German electricity generation from coal-fired power plants with amine-based carbon capture. Int J Life Cycle Assess 2009;14:547-59.

Singh B, Stromman AH, Hertwich E. Lifecycle assessment of natural gas combined cycle power plant with post-combustion carbon capture, transport and storage. Int J Greenh Gas Control 2011;5:457-66. Elzahabi M, Yong RN. pH influence on sorption characteristics of heavy metal in the vadose zone. Eng Geol 2001;60:61-8.

Kruse H, Tekiela M. Calculating the consequences of a CO2-pipeline rupture. Energy Convers 1996;37:1013-8.

[171 [172 [173

[174 [175

[176 [177

[179 [180

[182 [183

[184 [185

[189 [190

[191 [192 [193

International Energy Agency Report. Barriers to overcome in implementation of CCS: rules and standards for the transmission and storage of CO2. IEA Greenhouse Gas R&D Programmes, PH4/23; 2003.

Turner R, Hardy N, Hooper B. Quantifying the risks associated with a CO2 sequestration pipeline: a methodology and case study. Camberra, CRC for Greenhouse Gas Technologies (CO2CRC); 2003.

Lindeberg E, Bergmo P.The long-term fate of CO2 injected into an aquifer. In: Proceedings of the 6th international conference on greenhouse gas control technologies. Gale JJJ, Kaya Y., editors. V1. Amsterdam: Pergamon; 2003. p. 489-94. Celia MA, Nordbottena JM, Bachuc S, Dobossya M, Courta B. Risk of leakage versus depth of injection in geological storage. Energy Procedia 2009;1:2573-80.

Pruess K. Numerical simulation of CO2 leakage from a geologic disposal reservoir, including transitions from super- to subcritical conditions, and boiling of liquid CO2. Soc Pet Eng SPE J. 2004;9:237-48. Lewicki JL, Oldenburg C, Dobeck L, Spangler L. Surface CO2 leakage during the first shallow subsurface CO2 release experiment. Lawrence Berkeley National Laboratory. 2008.

Watson TL, Bachu S. Evaluation of the potential for gas and CO2 leakage along

wellbores. Soc Pet Eng SPE Drill Complet 2009;24:115-26.

Bachu S. CO2 storage in geological media: role, means, status and barriers to

deployment. Prog Energy Combust Sci 2008;34:254-73.

Celia MA, Bachu S, Nordbotten JM, Gasda SE, Dahle HK. Quantitative

estimation of CO2 leakage from geological storage: analytical models,

numerical models and data needs. In: Proceedings of the 7th Greenhouse

Gas Technology, Paper ID#228; 2004,10 pp.

Nordbotten JM, Celia MA, Bachu S, Dahle HK. Semianalytical solution for CO2 leakage through an abandoned well. Environ Sci Technol 2005;39:602-11. Nordbotten JM, Kavetski D, Celia MA, Bachu S. Model for CO2 leakage including multiple geological layers and multiple leaky wells. Environ Sci Technol 2009;43:743-9.

Hildenbrand A, Scholmer S, Krooss BM. Gas breakthrough experiments on fine-grained sedimentary rocks. Geofluids 2002;2:3-23. Krooss BM, Leythaeuser D, Schaefer RG. The quantification of diffusive hydrocarbon losses through cap rocks of natural gas reservoirs - a reevaluation. AAPG Bull 1992;76:403-6.

Li Z, Dong M, Li S, Huang S. CO2 sequestration: depleted oil and gas reservoirs-caprock characterization and storage capacity. Energy Convers Manag 2006;47:1372-82.

International Energy Agency GHG. Wellbore integrity network summary report, 2012/01; 2012.

Lewicki JL, Birkholzer J, Tsang CF. Natural and industrial analogues for leakage of CO2 from storage reservoirs: identification of features, events, and processes and lessons learned. Environ Geol 2007;52:457-67. Ziska LH, Sicher RC, Bunce JA. The impact of elevated carbon dioxide on the growth and gas exchange of three C4 species differing in CO2 leak rates. Physiol Plant 1999;105:74-80.

Skinner L. CO2 blowouts: an emerging problem. World Oil 2003;224:223-38.

Saripalli KP, Mahasenan NM, Cook EM. Risk and hazard assessment for

projects involvingthe geological sequestration of CO2. In: Proceedings of the

6th international conference on greenhouse gas control technologies. Gale JJ,

Kaya Y, editors, vol. V1. Amsterdam: Pergamon; 2003. p. 511-6.

Allen DJ, Brent GF. Sequestering CO2 by mineral carbonation: stability against

acid rain exposure. Environ Sci Technol 2010;44:2735-9.

Enting IG, Etheridge DM, Fielding MJ. A perturbation analysis of the climate

benefit from geosequestration of carbon dioxide. Int J Greenh Gas Control


Arts R, Eiken O, Chadwick A, Zweigel P, Van der Meer L, Zinszner B. Monitoring of CO2 injected at Sleipner using time-lapse seismic data. Energy 2004;29:1383-92.

Bannister S, Nicol A, Funnel R, Etheridge D, Christenson B, Underschultz J, et al. Opportunities for underground geological storage of CO2 in New Zealand, report CCS-08/11, monitoring and verification methodologies. GNS Science Report 2009/64; 2009. 101 pp.

Kiessling D, Schmidt-Hattenbergera C, Schuett H, Schilling F, Kruegera K, Schoebel B, et al. Geoelectrical methods for monitoring geological CO2 storage: first results from cross-hole and surface-downhole measurements from the CO2SINK test site at Ketzin (Germany). Int J Greenh Gas Control 2010;4:816-26.

Bielinski A, Kopp A, Schutt H, Class H. Monitoring of CO2 plumes during

storage in geological formations using temperature signals: numerical

investigation. Int J Greenh Gas Control 2008;2:319-28.

Vasco DW, Rucci A, Ferretti A, Novali F, Bissell RC, Ringrose PS, et al. Satellite-

based measurements of surface deformation reveal fluid flow associated

with the geological storage of carbon dioxide. Geophys Res Lett 2010;37:


Jenkins CR, Cook PJ, Ennis-King J, Undershultz J, Boreham C, Dance T, et al. Safe storage and effective monitoring of CO2 in depleted gas fields. PNSA 2012;109/2:35-41.

Riding JB, Rochelle CA. The IEA Weyburn CO2 monitoring and storage project. Final report of the European research team. British Geological Survey Research Report RR/05/03. 2005 (54 pp.).

Schilling F, Borm G, Wurdemann H, Moller F, Kuhn M. Status report on the first European on-shore CO2 storage site at Ketzin (Germany). Energy Procedia 2009;1:2029-35.

194] International Energy Agency Report (2009), Technology Roadmap: Carbon capture and storage, OECD/IEA, Paris, Available at: ccs_roadmap.asp.

195] DECC. 2011 UK Greenhouse Gas Emissions, Final Figures. London, UK: Department of Energy & Climate Change; 2013.

196] Page SC, Williamson AG, Mason IG. Carbon capture and storage: fundamental thermodynamics and current technology. Energy Policy 2009;37:3314-4424.

197] Dahowski RT, Davidson CL, Dooley JJ. Comparing large scale CCS deployment potential in the USA and China: a detailed analysis based on country-specific CO2 transport & storage cost curves. Energy Procedia 2011;4:2732-9.

198] Dahowski RT, Davidson CL, Li XC, Wei N. A $70/tC02 greenhouse gas mitigation backstop for China's industrial and electric power sectors: insights from a comprehensive CCS cost curve. Int J Greenh Gas Control 2012;11:73-85.

199] Rubin ES, Chen C, Rao AB. Cost and performance of fossil fuel power plants with CO2 capture and storage. Energy Policy 2007;35:4444-54.

200] Kheshgi HS, Thomann H, Bhore NA, Hirsch RB, Parker ME, Teletzke GF. Perspectives on CCS cost and economics. SPE Econ Manag 2012;4/1:24-31.

201] EU, Communication from the Commission to the European Parliament, the Council of the European Economic and Social Committee and the Committee of the Regions. Supporting early demonstration of sustainable power generation from fossil fuels. Brussels, Commission of the European Communities; 2008.

202] Rubin ES. Understanding the pitfalls of CCS cost estimates. Int J Greenh Gas Control 2012;10:181-90.

203] Simbeck D, Beecy D. The CCS paradox: the much higher CO2 avoidance costs of existing versus new fossil fuel power plants. Energy Procedia 2011;4:1917-24.

204] Kennedy M, Basu B. An analysis of the climate change architecture. Renew Sustain Energy Rev 2014;34:185-93.

205] Green-Alliance.The CCS challenge: the practical potential for gas carbon capture and storage in Europe in 2030; 2012.

206] Fennell PS, Florin N, Napp T, Hills T. CCS from industrial sources. COP18-Collection: vol. 2012, COP18, 17. doi: 10.5339/stsp.2012.ccs.17@ cop18.2012. 2012.issue-1; 2012.

207] Minchener AJ.Gasification based CCS challenges and opportunities for China. Fuel. Available on line; 2013.

208] Woolf D, Amonette JE, Street-Perrott FA, Lehmann J, Joseph S. Sustainable biochar to mitigate global climate change. Nat Commun 2010:56. http://dx.,,s1053 (1, Article no).

209] Darko Matovic. Biochar as a viable carbon sequestration option: global and Canadian perspective. Energy 2011;36:2011-6.

210] Lenton TM. The potential for land-based biological CO2 removal to lower future atmospheric CO2 concentration. Carbon Manag 2010;1:145-60.

211] International Energy Agency Report. CO2 capture as a factor in power station investment decisions. Report No. 2006/8, May; 2006.

212] Ritter JA. Radically new adsorption cycles for carbon dioxide sequestration. University coal research contractors review meeting, U.S. DOE National Energy Technology Laboratory. Pittsburgh, Pennsylvania; June 10, 2004.

213] Andus H. Leading options for the capture of CO2 at power stations. In: Proceedings of the 5th international conference on greenhouse gas control technology. Cairns, Australia; August 13-16, 2000.

214] Yun G, Liu D, Wu T, Wu J, Ji X, Zhuang L. CO2 capture and utilization for enhanced oil recovery (EOR) and underground storage: a case study in Jilin Field, China. Stud Surf Sci Catal 1998;114:201-6.

215] Qu X, Liu L, Gao Y, Liu N, Li F, Liu H. Geology record of mantle-derived magmatogenetic CO2 gas in the northeastern China. Acta Pet Sin 2010;31:61-7.

216] ZERO website: <>.

217] Emberley S, Hutcheon I, Shevalier M, Durocher K, Mayer B, Gunter WD, et al. Monitoring of fluid-rock interaction and CO2 storage through produced fluid sampling at the Weyburn CO2-injection enhanced oil recovery site, Saskatchewan, Canada. Appl Geochem 2005;20:1131-57.

218] White D. Monitoring CO2 storage during EOR at the Weyburn-Midale Field. Lead Edge 2009;28:838-42.

219] Kane, B. (2010) CO2 sequestration capability:where are we? An overview of the advances being made in CO2 geologic storage by DOE/NETL's regional carbon sequestration partnership. US Carbon Sequestration Council. <http:// Capability_-_Where_Are_We_ 31July10.pdf>.

220] Esser R, Levey R, Mcpherson B, O'Dowd W, Litynski J, Plasynski S. (Geology conference series 2010). Preparing for a carbon constrained world; overview of the United States regional carbon sequestration partnerships programme and its Southwest Regional Partnership, vol. 7. London, Petroleum: Geological Society; 2010; 1189-95.

221] Bachu S, Shaw J. CO2 storage in oil and gas reservoirs in Western Canada: effect of aquifers, potential for CO2-flood enhanced oil recovery. In: Proceedings of the 7th international conference on greenhouse gas control technologies; 2004.

222] Westermark RE, Schmeling J, Dauben DL, Robinowitz S, Weyland HV. Application of horizontal waterflooding to improve oil recovery from old fields. In: SPE/DOE symposium on improved oil recovery. Oklahoma, USA; 22-26 April 2006. isbn:978-1-55563-157-4.

223] Nader S. Paths to a low-carbon economy - the Masdar example. Energy Procedia 2009;1:3951-8.

224] Kumar S, Zarzour O, Gupta A. Challenges in design of post combustion CO2 capture facilities. In: Proceedings of the Abu Dhabi international petroleum

[227 [228 [229

[230 [231

[232 [233 [234 [235

[238 [239 [240

exhibition and conference. Abu Dhabi, UAE; 1-4 November 2010. isbn:978-1-55563-315-8.

Friedmann SJ. Carbon capture and sequestration technologies: status and future deployment. UCRL-BOOK-235276, < 353346.pdf>; 2007.

Lee ZH, Lee KT, Bhatia S, Mohamed AR. Post-combustion carbon dioxide capture: Evolution towards utilization of nanomaterials. Renew Sustain Energy Rev 2012;16:2599-609.

From Hitachi Power Systems America, Ltd. website <http://www.hitachipo wersystems/us/supportingdocs/forbus/hpsa/technicalpapers/EP2005.pdf>. Reeves S, Oudinot A. The Tiffany Unit N2 - ECBM Pilot: a reservoir modeling study. U.S. Department of Energy Topical Report DE-FC26-0NT40924; 2004. Cochrane T, Oudinot AY, Koperna JG, Philip ZG, Liu N, Heath JE, et al. CO2 injection performance in the Fruitland Coal Fairway, San Juan Basin: results of a field pilot. In: Proceedings of the SPE international conference on CO2 capture, storage, and utilization. San Diego, California, USA; 2-4 November 2009.

Wong S, Gunter WD. Testing CO2-enhanced coalbed methane recovery. Greenh Issues, IEA Greenhouse Gas R&D Program, 45, Novermber 1-3. Smith DH, Bromhal G, Sams WN, Jikich S, Ertekin T. Simulating carbon dioxide sequestration/ECBM production in coal seams: effects of permeability anisotropies and the diffusion-time constant. SPE Reserv Eval Eng 2005;8: 156-163.

Van Alphen K, Noothout PM, Hekkert MP, Turkenburg WC. Evaluating the development of carbon capture and storage technologies in the United States. Renew Sustain Energy Rev 2010;14:971-86.

Gunter WD, Bachu S, Law DHS. Technical and economic feasibility of CO2 disposal in aquifers within the Alberta sedimentary basin, Canada. Energy Convers Manag 1996;37:1135-42.

Bachu S, Gunter WD. (Special Publications). Acid-gas injection in the Alberta basin, Canada: a CO2-storage experience, vol. 233. London: Geological Society; 2004; 225-34.

Baklid A, Korbol R, Owren G. Sleipner West CO2 disposal, CO2 injection into a shallow underground aquifer. In: Proceedings of the 1996 SPE annual technical conference and exhibition. Denver, Colorado; 6-9 October 1996. Society of Petroleum Engineers Paper SPE 36600.

Hansen H, Eiken O, Aasum TO. Tracing the path of carbon dioxide from a gas-condensate reservoir, through the amine plant and back into a subsurface acquifer. Case study: the Sleipner area. Norwegian North Sea. SPE 96742 2005.

Riddiford F, Wright I, Bishop C, Espie T. Monitoring geological storage the in Salah gas CO2 storage project. In: Proceedings of the 7th international conference on greenhouse gas control technologies. Vancouver, Canada; 5 September 2004.

Maldal T, Tappel IM. CO2 underground storage for Snohvit gas field development. Energy 2004;29:1403-11.

Kaarstad, O. Presentation in IEA Asia Pacific Conference on Zero Emission Technologies. Queensland, Australia; 18 February 2004. Barnes DA, Bacon DH, Kelley SR. Geological sequestration of carbon dioxide in the Cambrian Mount Simon Sandstone: regional storage capacity, site characterization, and large-scale injection feasibility, Michigan Basin. Environ Geosci 2009;16:163-83.

[241] Barnes DA, Harrison WB III, Wahr, A. Assessment of regional geological carbon sequestration potential in upper Silurian to Middle Devonian Strata of the Michigan Basin. In: M. Grobe, J.C. Pashin and R.L. Dodge, (Eds.), Carbon dioxide sequestration in geological media-State of Science, AAPG Studies in Geology 59, 99-123.

[242] Litynski J, Plasynski S, Spangler L, Finley R, Steadman E, Ball D, et al. U.S. department of energy's regional carbon sequestration. Partnership program: overview. Energy Procedia 2009;1:3959-67.

[243] Rodosta T, Litynski J, Plasynski S, Spangler L, Finley R, Steadman E, et al. US Department of Energy's regional carbon sequestration partnership initiative: update on validation and development phases. Energy Procedia 2011;4:3457-64.

[244] Hovorka SD, Meckel TA, Trevino RH, Lu J, Nicot JP, Choi JW, et al. Monitoring a large volume CO2 injection: year two results from SECARB project at Denbury's Cranfield, Mississippi, USA. Energy Procedia 2011;4:3478-85.

[245] Koperna G, Riestenberg D, Kuuskraa V, Rhudy R, Trautz R, Hill GR, et al. The SECARB anthropogenic test: a US integrated CO2 capture, transportation and storage test. Int J Clean Coal Energy 2012;1:13-26.

[246] Gupta, N. The Ohio river valley CO2 storage project numerical simulation and risk assessment report. U.S. Department of Energy Report Project #: DE-AC26-98FT40418; 2008.

[247] Finley R. An integrated carbon sequestration deployment test at Decatur, Illinois. 2009 Portland GSA annual meeting Paper No. 22-14; 18-21 October 2009.

[248] Hnottavange-Telleen K, Krapac I, Vivalda C. Illinois Basin-Decatur Project: initial risk-assessment results and framework for evaluating site performance. Energy Procedia 2009;1:2431 -8.

[249] Leetaru HE, Coueslan M, McBride J. Seismic reflection data interpretation of the proposed Illinois Basin-Decatur carbon sequestration site topical report 1: an assessment of geological carbon sequestration options in the Illinois Basin: Phase III. Report submitted by Illinois State Geological Survey to US DOE; 2009.

[250] Cook PJ. Demonstration and deployment of carbon dioxide capture and storage in Australia. Energy Procedia 2009;1:3859-66.

[251] Boiardi, B. CO2 capture and geological sequestration: the first Italian experience. 34th course of the international school of geophysics on densely populated settings: the challenge of siting geological facilities for deep geothermics, CO2 and natural gas storage, and radioactive waste disposal. Erice; September 25-30, 2010.

[252] Flett M, Beacher G, Brantjes J, Burt A, Dauth C, Koelmeyer F, et al. Gorgon project: subsurface evaluation of carbon dioxide disposal under Barrow Island. In: Proceedings of the SPE Asia Pacific oil and gas conference and exhibition. Perth, Australia; 20-22 October 2008. isbn:978-1-55563-202-1.

[253] Flett M, Brantjes J, Gurton R, McKenna J, Tankersley T, Trupp M. Subsurface development of CO2 disposal for the Gorgon Project. Energy Procedia 2009;1:3031-8.

[254] Hooper BN. The Latrobe Valley post-combustion capture project. Energy Procedia 2009;1:1367-72.

[255] Friedmann SJ. Emerging technical challenges of 5-million-ton/yr injections. In: Proceedings of the SPE international conference on CO2 capture, storage, and utilization. San Diego, California, USA; 2-4 November 2009.