Wednesday, January 15, 2020

The Most Important Research Directions for CO2 Capture and Storage Projects

The capture and storage of CO2 is gaining attention as an option for limiting CO2 emissions from the use of fossil fuels. CO2 capture is premised on the safe long-term storage of CO2 in geological formations. Naturally occurring CO2 is used for enhanced oil recovery in the USA, Trinidad, Turkey, Hungary, Brazil and Croatia. Industrially produced CO2 has been used for enhanced oil recovery at the Rangely field in Colorado, USA since 1986 and at the Weyburn field in Saskatchewan, Canada since 2000. Large-scale CO2 storage in geological formations to avoid CO2 emissions was first undertaken offshore in Norway in 1996 and onshore in Algeria in 2004. CO2 delivered for EOR in the USA averaged around USD 11/tonne CO2 during the 1990s. The cost of CO2 capture from low concentration industrial sources varies with a number of factors, but will certainly be very much higher  than the recovery of naturally-occurring CO2. Adequate knowledge exists in the oil and gas industry for the application of CO2 capture and storage. Widespread implementation of fully-integrated CO2 value chains will nonetheless depend on achieving public acceptance  and regulatory approval for CO2 storage, cost reduction for CO2 capture and sufficient economic incentives for the key actors involved. This article discusses the most important research directions for CO2 capture and storage projects that have been initiated around the world. The adequacy of economic incentives will strongly influence how quickly producers and users of fossil fuels are able to close the knowing-doing gap for CO2 capture and storage.


The world’s dependence on fossil fuels for the satisfaction of primary energy needs is at odds with growing atmospheric emissions of CO2 from the combustion of hydrocarbons. Given their high energy density and availability, fossil fuels are likely to continue to provide more than  80% of total world energy requirements for the coming decades, with especially coal and natural gas asserting  their positions in the fuel mix by providing  38%  and  30%, respectively of electricity demand in 2030 (IEA, 2004a). On a global basis, coal accounted for 24% of primary energy consumption in 2004,  oil for 34%, natural  gas for 21%, nuclear  for 5%, large  hydropower for 6%  and renewable accounting for approximately 10% (BP, 2005) Power generation comprises the largest source of  CO2 emissions (see Figure 1) (IEA GHG, 2002b).

*Correspondence to: Ms R. Steeneveldt, Statoil ASA, Research & Technology Development, Arkitekt Ebbellsvei 10, Rotvoll, N-7005, Norway. E-mail:

Flue or stack gases from this sector are usually at atmospheric pressure with the CO2 concentration varying between 3% (vol.) for natural gas fired plants and 14% for oil and coal fired boilers. In addition to fossil fuel based heat and power production, large stationary sources of CO2 emissions include natural gas sweetening, hydrogen production for ammonia and ethylene oxide, oil refineries, iron and steel production facilities, cement and limestone manufacturing plants. The transportation sector contributed 18% of global CO2 emissions in 2001 (Ibid). A viable CO2 value chain could provide the foundation for reducing emissions from the transportation sector through the production of hydrogen from fossil fuels. While the CO2 content of emissions from ammonia, ethylene oxide and refinery reformers is typically above 95% (dry volume basis), iron and steel, cement and limestone production results in atmospheric  emissions  with a CO2 content of 20% or higher (Sheinbaum and Ozawa, 1998). Figure 2 shows that large-scale commercial applications of CO2 separation technology have typically been from streams where the partial pressure of CO2 is relatively high. Some newer concepts for power production focus on producing a pressurized and/or concentrated stream of CO2 so as to reduce the energy required for separation. Where systems for CO2 transport and storage are tolerant of contaminants like SOx, NOx and Hg, potentially costly investments in flue gas clean-up may be circumvented by co-storage of these components with the CO2.

Figure 1. Global CO2 emissions in 2001 (IEA)

Improved energy efficiency, fuel switching (e.g., from coal to natural gas)  and the capture and storage  of CO2  are strategies for climate change mitigation that reconcile the continued use of fossil fuels with goals to reduce CO2 emission related to meeting global energy needs.1 This article focuses on CO2 capture and storage (CCS). The major components of a CCS value chain include capture (i.e., separation and compression to supercritical state) transport and storage (including measurement, monitoring and verification of safe operations). The large scale applications of CO2 that have been identified are the use of    CO2 for enhanced oil recovery (EOR2), and for enhanced coal bed methane (ECBM3).

The costs of CCS based on fossil fuels depends on a number of variables and considerations (see for example Bock et al., 2003; Rubin and Rao, 2003), including the  cost of fuel, the technology characteristics of the power    or industrial plant, the scale of the capture plant, the percentage CO2 captured, the characteristics of  the  storage site and the required transportation distance. CO2 capture from high pressure, high CO2 concentration streams can potentially be performed at lower cost than from exhaust gases from power production. In general, for CO2 capture and storage from power station flue gas, the cost of CO2 separation and compression dominates the CO2 costs, making up 50 – 80% of total specific CO2 costs across the value chain4: The application  of  capture  technology would add about 0.18 – 0.034 USD/kWh to the cost of electricity from a pulverized coal power plant, 0.09 – 0.22 USD/kWh to the cost for electricity from an integrated gasification combined cycle coal power plant, and 1.2 –2.4  USD/kWh  from  natural  gas  combined  cycle power plant (IPCC, 2005). Senior et al. (2004) provide an overview of the cost distribution, reproduced in Table 1. For example, Kvamsdal et al. (2005b) reported 67 USD/tonne5 total costs of CO2 capture from a  860  MW  power  plant,  whereof 54 USD/tonne was the cost of capture and 13 USD/tonne the transport cost for a 150 km pipeline.

1 Increased use of renewable energies and nuclear energy may also contribute to reducing CO2 emissions associated with meeting energy needs.
2 Enhanced oil recovery (EOR) is the term used for those techniques that are put into effect for altering the original properties of the oil to improve recovery from a producing field. Enhanced oil recovery restores reservoir pressure and improves fluid flow. The three major types of enhanced oil recovery approaches are chemical flooding, miscible displacement (CO2 injection or hydrocarbon injection) and thermal recovery (steamflood or  in situ combustion). Enhanced oil recovery is also called improved oil recovery or tertiary recovery.
3 Enhanced coal bed methane (ECBM) is the term used for techniques that increase the recovery of methane from unmineable (uneconomic) coal seams—CO2 is selectively adsorbed into the pore volume displacing the methane.
4 The cost of modifications required to implement CO2 injection for EOR may in some cases prove to be substantial.
5 Assume 1 ¼ 1 USD.
6 The Electricity Act that came into force on 1 July 2003, suggests that a tax exemption worth approximately 25 – 40 million in the first year and increasing every year by between 25 – 30 million will be established to support renewable energy, energy efficiency and climate neutral electricity, including CO2 capture and storage.
7 While the potential fuel efficiency achievable with fuel cells (SOFC; MCFC) are promising, the limited scale envisioned for fuel cells (10 –  50 MW) will limit the application of this technology for centralized  power production. For this reason, research on fuel cells has been excluded from this review.

There is remaining uncertainty about the application of the London (Dumping) Convention and the OSPAR Convention (Oslo Paris Convention), to CO2 storage offshore   in geologic formations. Clarification may require intergovernmental negotiations. Public acceptance and endorsement of CO2 storage is an important premise for CCS. Apart from sizeable research funding only the Netherlands6 and Norway have in place legislation that provide some incentive for CO2 capture and storage (see Lee et al., 2005). Consequently, research on CO2 capture aims at technology development  for reduced capital and operating costs, while research on CO2 storage aims at technology development for monitoring and verifying the safety of CO2 injection.

The main research directions for CO2 storage and capture are depicted in Figure 3. A comprehensive review of the extensive literature on CO2 capture and storage is not the intent of this paper. The objectives of this paper are    to: (1) give an overview of the most important CO2 capture technologies, (2) examine the status of the most important CCS projects that have been initiated worldwide, (3) briefly examine the remaining development challenges of the main capture technologies, and (4) discuss some of the challenges for realizing a global CO2 value chain.7

Some scholars have  argued  that,  like  with  systems  for SOx removal, the cost of building and operating CO2 capture systems should be reduced over time through cumulative learning and technological progress (e.g., Alic et al., 2003; McDonald and Schrattenholzer, 2001; Riahia et al., 2004; Rubin et al., 2004a,b; Rao et al., 2003). As will be discussed in the remainder of this paper, there are numerous technical routes to CO2 capture at different  stages of maturity. The cumulative learning  contention rests on the assumption that there is effective learning across technology platforms—an assumption that is debatable where there is a proliferation of approaches. The biggest factor likely to influence the implementation of CCS is government support (both in terms of size and perceived predictability).


In the petrochemical industry, CO2 is separated from other gaseous components using both physical and chemical absorbents. Large scale CO2 separation units in operation today focus on the removal of  unwanted  CO2  at high partial pressure. The recovery of CO2 from flue gas is performed on a limited scale at a small number of plants around the world (IEA GHG, 2004). Physical solvents commonly in commercial use include methanol, dimethyl  ethers of polyethylene glycol, propylene carbonate, and potassium carbonates (Astarita, 1983). Conceivable commercially available alternatives are selective polymeric membranes and cryogenic separation. The factors influencing the choice of separation technology are the partial pressure of the CO2 in the feedstream, sensitivity of the method to other impurities or trace components, CO2 recovery, capital and operating costs and environmental impacts (waste or by-product production). For separating CO2 from flue gas with very low CO2 partial pressure in     a large stream of mostly non-condensable gases, absorption processes using chemical solvents offer distinct advantages over the alternatives: lower energy use and costs, higher capture efficiency and better selectivity.

Figure 2. Partial pressure of CO2 from the most important CO2 producing stationary processes.

Table 1. Overview of indicative costs of elements in a CO2 capture and storage value chain.

The application of selective membranes8 and cryogenic separation is economic for streams having both high feed concentration of CO2 and high pressure and low concentrations of other acidic components, like H2S. Despite the observation that examples of the small-scale commercial application of CO2 absorption from flue gas can be found around the world,9 the treatment of power plant flue gas   for CO2 storage represents a scale-up challenge: The capacity of CO2 capture from flue gas for the supply of  CO2 to the food and beverage industries ranges from 6 to 800 tonnes/day CO2 (Herzog, 1999; IEA, 2004b). Since a 500 MWe pulverized coal power plant emits approximately 10 – 12 k tonnes/day, and a natural gas combined cycle plant approximately 4 k tonne/day, this implies scale-up of 20 – 50 times (Riemer and Ormerod, 1995; IEA GHG 2000b). With absorber diameters of up to 15 meters considered feasible, single train  CO2  recovery  plant capacities of up to 8000 tonnes/day are believed achievable, depending on the inlet flue gas CO2 concentration. Larger plants could be designed with multiple absorbers that share a common stripper (Reddy et al.,  2003; Roberts, 2002).

8 The  trade-off  between  purity  and  recovery  typically  experienced with solution-diffusion membranes, makes it costly to achieve both high CO2 purity and high CO2 recovery.
9 Fluor’s Bellingham 330 tonne per day CO2 capture plant is largest commercial plant based on turbine flue gas.

Figure 3. Main research directions for  CCS.


There is significant spending on CCS research and development around the world and in particularly in the EU, in   the USA (DOE’s Carbon Mitigation Program), Canada, Australia Japan and Norway. More than USD 80 million excluding the matching contributions from industry participants and other research institutions has been  directed  at  CCS research under the EUs framework 5 and 6 pro-  grammes (McKee, 2002). The DOE’s Carbon Mitigation Program had an annual  budget  of  USD  46  million  in  2005, with  projections  of  a  baseline  funding  requirement of USD 30 million per year until 2020. The IEA’s Greenhouse Gas Program was established in 1991, providing an early marketplace for ideas and research on CCS. The  recently  released  IPCC10  Special  Report  on  Carbon Dioxide Capture and Storage ( activity/srccs/index.htm) knits together the  diverse  threads of research on CCS, presenting the results of 15 years of international  research effort.  Table 2  below lists a selection  of the completed and ongoing international research projects on  CCS.  In  addition  there  are  pilot  facilities  at  Ka˚rstø, Norway, Osaka, Japan (Buller et al., 2004) and at the Boundary Dam power station, Saskatchewan, Canada with a  capacity  of  4– 8  tonnes  CO2  per  day  (Wilson  et  al., 2004). The CO2 capture pilot plant with the largest design capacity to date, of 24 tonnes CO2 per day, was opened at Esbjerg, Denmark in March 2006. An explicit goal for all ongoing research on CCS is the demonstration of new technology at pilot and semi-commercial scales.


The three main pathways to CO2 capture and storage are shown in Figure 4. CO2 is separated from the other components to optimize CO2 compression to the dense phase, for cost-effective transport and injection at  the  storage  site and to meet the purity requirements at the injection point. All of the capture and storage pathways  require  energy, which implies that processes with CO2 capture pro- duce more CO2/kWh or CO2/product (than equivalent reference plants without capture). For most analyses, the system boundaries are drawn such that energy involved in exploration/mining, energy for the production  and  transport of fossil fuels, the energy required to produce and transport important capture components  like,  e.g.,  amines  for post-combustion and  energy  required  for  the  disposal  of waste is excluded from the analysis. A discussion of  system boundaries can be found in Haefeli et al. (2004). Lombardi (2005) found the emissions associated with construction and dismantling of capture plants to be negligible relative to that of the central  combustion  processes.  The  CO2 emissions directly associated with capture, compression, transport  and  injection  for  storage  or  enhanced oil recovery are most often included. From a CO2 accounting perspective, both the direct and indirect CO2 emissions   are important,11 as well as the estimated leakage from storage (see e.g., Ha-Duong and Keith, 2003). Implicit to the observation that there are additional CO2 emissions associated with all concepts, the ‘CO2 avoided’ i.e., both the direct and indirect CO2 emissions from a reference plant (without capture) less CO2 emissions from  a  given  plant  with capture is often  used  in  the  literature.  A  discussion  of methodological issues for calculating CO2 costs can be found in Melien (2005).


In addition to the CO2 storage projects (discussed below) that are projected to come on-stream in  the  near  future,  there are three announced plans  for  realizing  large-scale  CO2 capture (and storage) from  power  production.  These  are BP’s ambitious Decarbonised Fuel project in the UK, Vattenfall’s 30 MWth oxyfuel pilot plant in Germany (Vattenfall, 2005) and CES’s potential 50 MWe pilot in the  Netherlands:  BP  and  partners,  Royal  Dutch/Shell, ConocoPhillips and Scottish & Southern Energy PLC have announced plans for a large-scale CO2 capture and storage project, envisioned to come on-stream in 2009 (http:// The chosen route is the production of hydrogen from natural gas. The hydrogen will fuel 350 MW  from  Scotland’s  Peterhead  power  station  while  1.3 million tonnes of captured CO2 will be transported by an existing pipeline and injected for enhanced oil recovery and deep geological storage in the Miller Field.13 Vattenfall of Sweden ( has announced plans to build a 30 MWth lignite-based plant using oxyfuel technology. The pilot plant is expected to come on-stream in 2008 and will provide the design basis for scale-up of the technology to 600 MWe. Although a solution for the CO2 has not been made known, oxyfuel boiler technology allows the recovery of high concentration CO2 Clean Energy Systems (CES) ( and SEQ Nederland, B. V. have entered into an agreement for engineering services for a 50 MW power plant to be built in the Netherlands, where the carbon dioxide captured from the plant will be used for enhanced gas recovery. By avoiding harmful atmospheric emissions, the proposed project could qualify for governmental support as a ‘climate neutral combustion technology’, under current Dutch law (see footnote 6).

Table 2. Selection of international projects on CSS.

Figure 4. Main CO2 capture routes (from  CCP12).

10 Intergovernmental   Panel   on   Climate   Change:  
activity/srccs/index.htm. 11Associated with import of electricity or (other products) for example.
11 Associated with import of electricity or (other products) for example.


The main routes for CO2 capture are depicted in Figure 4. The generic combustion reaction for hydrocarbon fuel can be written as equation (1) below where f is the molar ratio of air required in excess of stoichiometric oxygen required.

The large amounts of excess air required for combustion control in current boiler and gas turbine technology result in a dilute CO2 stream that also has significant oxygen content. Chemical absorption processes employ the reversible nature of the reaction of an aqueous alkali solvent with an acid gas. MEA (monoethanolamine), MDEA (methyldiethanolamine) and DEA (diethanolamine) are currently the main chemical solvents of interest for acid gas treatment. The process technology for acid gas removal from natural gas was developed during the 1920s (Herzog, 1999). For MEA, the fundamental reaction for the process is:
The reaction proceeds to the right at low temperature 25– 1008C  allowing  absorption  from  the  gas  stream.  The solvent can be regenerated, and the CO2 recovered as a concentrated stream, by heating the solvent solution into the temperature range of 100– 1508C to reverse the absorption chemistry (Aboudheir et al., 2003). The economic amount of CO2 removal for post-combustion is between 80% and 95% CO2. Kvamsdal et al. (2005b) found that there was an efficiency gain in lowering the CO2 capture from 90%  to 75%, but  found  a  sharp  increase in  capital costs for 95% capture. There are three main technology suppliers (see Table 3). From the process flow diagram shown in Figure 5, incoming gas is cooled, and enters the CO2 is taken up by the solvent at temperatures typically between 40 and 808C. The top section of the column is used as a water wash to prevent solvent carry-over and to correct the water balance. The rich solvent is pumped to the top of the stripper where the solvent is regenerated at about 100–1408C, at around 60 kPa (g) (Barchas and Davis, 1992; Roberts et al., 2004).

12 CCP: CO2 Capture Project: Carbon Capture Project, see http://
13 Injecting the carbon dioxide into the Miller Field reservoir more than three kilometres under the seabed could extend the life of the field by about 20 years and enable additional production of about 40 million barrels of oil that are not currently recoverable.

Table 3. Comparison of established suppliers of MEA scrubbing technology.

Figure 5. Typical flowsheet for CO2 capture using MEA

While many of the constituent elements of the amine scrubbing process consists of widely-known technology, the development of inhibitors and their application to cost-effectively prevent degradation and corrosion  is  a  key area of technology know-how. Apart from the concerns for the purity of the CO2 at the point of use, the impurities in the  flue  gas  are  also  important  for  the  overall design and cost of the CO2 removal plant (Herzog et al., 1991). The relatively high oxygen content of flue gas represents a particular challenge for amine absorption due to degradation of amine by the  oxygen.  Solutions  of  MEA that are partly degraded are aggressive at high concentrations, causing high rates of corrosion, degradation of column internals and other elements (including filters)  and  reaction  with  other  components  in  the  gas.  

Flue gas from combustion will usually contain acidic components  NO2  and  SOx,  hydrogen  sulfide  (H2S), HCl, arsenic,  and mercury. MEA removes  nearly all of  the SO2 and some of the NO2 but very little NO and N2O.14 NO2 is usually less than 10% of overall  NOx  content in flue gas (Chapel et al., 1999, 2001). The acidic components react with the amine to form stable salts that reduce the absorption capacity, accumulate in the solution and cannot be regenerated by heating in the stripper. This represents a loss of solvent from the system and increases the solution viscosity undesirably. The elimination of heat stable salts results in operating costs for reclaiming the solvent and for handling the waste stream of sulphate and nitrate salts. MEA is typically recovered from the heat stable salts through reaction with soda ash (Reddy et al., 2003; Kvamsdal et al., 2005b). In addition to the solvent degradation, other gaseous components also affect the driving force for CO2 absorption, an effect that becomes more pronounced at elevated pressures (De Koeijer and Solbraa, 2004). The limits on SO2 and NO2 concentration in the flue gas being treated for CO2 removal by MEA absorption are recommended to be in the range from 10 to 50 ppmv. Amine tolerance levels are  reported  to  be  90 ppm  O2,  10 ppm SO2 and 20 ppm NOx (at 6% excess oxygen)  (IEA, 2004b). At these values solvent degradation is not eliminated, but simply reduced to an acceptable rate (Heggum et al., 2005). Fly ash and soot removal is also  important to prevent both foaming in the absorber and further reactions with the solvent.

14 The authors are not aware of research that has examined the effects of the other impurities on MEA absorption. Like with NOx and SOx, HCl also reacts with MEA to form heat stable salts. Remaining work in the EU project CASTOR will aim to better understand the formation of heat stable salts and the effect of flue gas impurities on absorption efficiency and cost.

Table 4. Energy requirements for post-combustion CO2 capture (leading technologies).

Post combustion treatment is costly and energy-intensive because of the large volume of gas to be treated, the low partial pressure of CO2 in the flue gas, the presence of contaminants that may be detrimental to the solvent and the energy demand associated with  solvent  regeneration. MEA has a high heat of absorption (which needs to be supplied in the regeneration step), the absorption of CO2 is modest and concentrations much greater than 20 – 30% result in corrosion problems. The energy requirements for post-combustion CO2 capture are summarized in Table 4. Extraction of LP steam from the steam turbine, instead of increasing the fuel demand gives 2 – 3% gain in fuel efficiency (Bolland and Undrum, 2003; Kvamsdal et al., 2005b). Compression of CO2 to export pressure and the regeneration heat for the amine solution are the largest consumers of energy. In addition to increased fuel costs, operating costs for post combustion plants are incurred by replacing consumed solvent (0.2 – 1.6 kg/CO2 tonne) and the use of chemicals for the removal of decomposition pro- ducts (e.g., 0.03 – 0.13 kg NaOH, 0.03 – 0.06 kg activated carbon/tonne CO2) (IPCC, 2005).  Improvements  that  have already been identified could potentially reduce the energy requirements for post-combustion capture from the research  efforts aimed at overcoming the weaknesses of  the predominant approaches for post-combustion CO2 removal are outlined in Figure 6.


An overview of existing solvents is given in Table 4. Sterically hindered amines have more favourable reaction stoichiometry, such that the theoretical capacity is higher than MEA, and lower heat of absorption/regeneration. Examples of sterically hindered amines are 2-amin-2- methyl-1-propanol (AMP), and the proprietary solvents marketed by Mitsubishi Heavy Industries,  KS-1,  KS-2  and KS-3 (White et al., 2003). A large research effort is being directed at improved solvents to improve the CO2 loading, reduce the energy requirement for solvent circulation and regeneration and to overcome solvent degradation (Chakma, 1995; Chakma and Tontiwachwuthikul, 1999; Mimura et al., 1999; Zheng et al., 2003; Cullinane and Rochelle, 2003; Leites, 1998; Erga et  al., 1995; Aresta  and Dibenedetto, 2003; Bai and Yeh, 1997; Chakravarti    et al., 2001; Mimura et al., 1995; Mimura et al., 2003). Improving the activated potassium carbonate process has been investigated using piperazine (e.g., Cullinane and Rochelle, 2003; Bishnoi and Rochelle, 2002). There is evidence that the capture process efficiency can be substantially improved by careful design of a mixture of solvents (Melien, 2005; White et al., 2003). While current suppliers of technology, ABB Lummus, Fluor and Mitsubishi/ Kansai Electric Power Company (KEPCO) are pursuing research on improved solvents, there is ongoing research around the world including at the Tokyo Electric Power Company, TNO,15 in the Netherlands and  at  Praxair,  Table 5 gives an overview of some of the amine-based solvents under development.

15 TNO is a contract research and specialist consultancy with its corporate centre in Delft, The Netherlands, see

Figure 6. Post-combustion research directions.

Table 5. CO2 solvents under development.

Even though improved amines, e.g., can save regeneration operating costs, they may have slower reaction kinetics and thus require longer gas– liquid contact time in the absorber. The design of improved contacting equipment that additionally overcomes the known operational problems with packed columns (flooding, channelling, entrainment and foaming) is thus another area where improvements are needed. Improved packing, (e.g., Aroonwilas et al., 2003; Kvamsdal et al., 2005b) and the use of contacting membranes (e.g., Søybe Grønvold et al., 2005; Feron and Jansen, 2002; Feron, 1992, 1994; Falk-Pedersen et al., 1999) has been investigated. DeMontigny et al. (2005) found significantly higher mass transfer coefficients for polymeric contactors as compared to structured packing. While membrane systems potentially have a smaller footprint and lower weight than conventional systems (Herzog and Falk-Pedersen, 2001), their modular nature implies that economy-of-scale benefits for very large scale CO2 capture plants are likely to be very modest or non-existent. The combination of chemical absorption and selective membranes has also been suggested, so as to perform absorption and desorption in a single unit, see Mano et al. (2003) and Okabe et al.  (2003). The combination of polymeric microporous membranes and DEA has been investigated by Bao and Trachtenberg (2005). The use of the carbonic anhydrase to catalyse and accelerate CO2 absorption and desorption forms the basis of the start-up company Carbozyme Inc.16

Other avenues that have been investigated are increased concentration of solvent (Aboudheir et al., 2003), so as to reduce circulation rates and thus energy requirements for regeneration, removal of oxygen, so as to enable the use   of solvents that are intolerant of oxygen (Nsakala et al., 2003). Ammonia has been proposed as an alternative to amines and can be employed to capture all three major   acid gases (SO2, NOx, CO2) in addition to any Hg, HCl  and HF, which may exist in the flue gas of coal combustors (Huang et al., 2002; Yeh and Bai, 1999; Yeh et al., 2002). Since SO2, NOx and Hg emissions must comply with given limits, a single process to capture all acidic and toxic gases is expected to reduce the total cost and complexity of emission control systems. Unlike the MEA process, ammonia is not expected to have absorbent degradation problems that are caused by sulphur dioxide and oxygen in flue gas, is not expected to cause equipment corrosion and could potentially reduce the energy requirements for CO2 capture. Recently, Powerspan Corp.,17 reported the application of ammonia for simultaneous reduction of SO2, NOx and mercury and announced the start-up of a pilot plant for testing the novel emission control concept that includes CO2 removal in 2006. In addition to the absorption processes using ammonia as a regenerative solvent, CO2 capture for the production of fertilizer has also been investigated.

Split flow, where a portion of the side draw from the absorber is fed to the stripper, bringing the operating line of the absorber parallel to the equilibrium line and so improving the thermodynamic efficiency (and thus lower reboiler duty) of the  absorber has  been suggested (Reddy et al., 2003). Kvamsdal et al. (2005b) found that at low CO2 loading and the correspondingly low regeneration temperature, a split flow regime gives no appreciable decrease in reboiler duty solid sorbents for CO2 have also been investigated (Abanades et al., 2004; Green et al., 2002).

The purity of CO2 from post-combustion capture is typically 99.9% (vol.) (Sander and Mariz, 1992). However, CO2 derived from combustion gases may contain sulphur oxides, nitrogen oxides, several different low molecular weight hydrocarbons, carbon monoxide,  and  mercury.  The concentrations of these impurities  may vary greatly   in individual processes; also, the variety of possible CO2 sources is responsible for a large number of potential impurities in the produced CO2.



Energy requirements can be reduced  by  pursuing energy integration between the CO2 capture plant and the power plant. The recirculation of flue gas is the most studied integration option (Bolland and Sæther, 1992). Combinations of the aforementioned measures have also been evaluated: For example Mimura et al. (1997) have investigated the combination of new solvent technology and integration of the steam requirements for the CO2 stripper with the power plant, and found that the energy penalty for CO2 capture and compression can potentially be lowered to 10 – 11% for natural gas and 15% for conventional coal. Chinn et al. (2004) proposed engineering options for reducing the costs of amine-based CO2-capture from the flue gas of a 400 MW natural gas combined cycle power, potentially bringing the costs of CO2 capture to around     35 USD/tonne. These potential improvements included depressurization of the lean solvent and vapour compression; elimination of contact coolers before the absorber,  the use of structured packing, direct integration of the stripper and Heat Recovery Steam Generator and recycle  of a portion of the flue gas to increase the CO2 feed concentration to the absorber.

It has been argued that post combustion CO2 capture affords power producers greater operational flexibility to respond to short term market signals than those alternatives that require integration between the power block and the capture plant (e.g., Gibbins et al., 2005). This may be valuable in terms of fluctuations in both the prices of CO2 quota and electricity and in overcoming the barrier that potential mismatches in timing between the life of power plants and CO2 required for enhanced oil recovery may present. Typically, operational flexibility comes at a cost (e.g., increased capital cost) that must be weighed against the uncertain value of the future benefits.


Applying new turbine cycles to produce flue gas with higher CO2 content may avoid some of the challenges for post-combustion CO2 capture. For example, the Combicap concept (Lynghjem et al., 2004) comprises two gas turbines that are interconnected by a CO2 separation system and an integrated combustor-heat exchange system (see Figure 7). Combicap aims at producing a flue gas stream with a higher CO2 partial pressure. By recirculating the flue gas stream from the main gas turbine, a novel semi-closed top cycle   is proposed employing a working fluid of mostly N2 (approximately 85%) and CO2 (approximately 10%). The CO2 concentration is limited by the  oxygen  required  in the combustor for complete combustion. Gas exiting the CO2 removal unit needs to be heated up to the hot gas temperature of the helper gas turbine unit. This required heat may be provided by heat exchange, without adding CO2 to the gas, or by supplementary firing that will  lead   to some additional CO2 in the exhaust gases if natural gas  is  burned.  Increasing  the  CO2  partial  pressure  (.1.5 bar), potentially lowers the cost of CO2 capture by, e.g., polymer membrane systems. The use of novel, fixed site carrier membranes where an amine group and other cross-linking agents (e.g., Fl) are incorporated into the structure of a polymer membrane for CO2 capture from flue  gases  has  been  investigated.  (e.g.,  Ha¨gg  and  Lindbra˚then, 2005). The Combicap  concept  exhibits  relatively high  overall  fuel  efficiency  (approximately  50%)  due  to the high temperature at the turbine inlet and has low formation of NOx since the combustor receives both fresh air and recycled flue gas. The advantages of the increased CO2 partial pressure and modest temperature for CO2 separation are partially offset by the increased complexity and higher degree of integration of the process.

Figure 7. The Combicap# cycle (Lyngheim et al., 2004).

Humid air turbine (HAT) cycles have been proposed as a means of reducing the costs of power generation and CO2 removal (e.g., Rao and Day, 1996). A typical HAT cycle uses a high pressure ratio gas  turbine,  composed  of  a high pressure inter-cooled shaft and a low pressure power shaft. The high pressure air from the compressor is cooled and then humidified in an air saturator. The humidified air is heated in a heat recovery section that uses the turbine exhaust before entering the turbine combustor. Arguments for HAT cycles are that the added cost of a more expensive gas turbine, the air saturator and the increased number of heat exchangers is offset by elimination of the heat recovery steam generator (HRSG) steam cycle.

An alternate approach to removing CO2 from the flue gas is to use oxygen for combustion instead of air. To maintain thermal conditions in the combustion zone and prevent overheating of the furnace liner materials,  some  of  the flue gas would be recycled to the furnace. Using oxygen instead of air opens up new possibilities for increased combustion efficiencies. Trace impurities exit with the CO2 stream and where these can be stored with the CO2 could result in overall lower emissions abatement costs. The oxyfuel pathway to CO2 capture and storage is discussed in the following section.


Since nitrogen is the highest concentration component in the flue gas from power stations, removal of nitrogen in oxyfuel processes (also called pre-combustion denitrogena- tion) simplifies downstream CO2 separation. One of the earliest investigations of oxyfuel CO2 capture was by Holt and Lindeberg (1988), who suggest oxygen firing instead of air and recirculation of CO2 and H2O as the working fluid in    a partially closed turbine cycle. Air separation precedes combustion so that the combustion products are chiefly CO2, and water with small amounts of other acid gases (e.g., SOx, NOx), possible impurities such as HCl and Hg derived from the fuel used, and inert gas components, such as nitrogen, argon and oxygen either derived from the oxygen feed, the fuel stream or air leakage into  the  system. Oxyfuel concepts for both natural gas and coal feedstock have been proposed Croiset and Thambimuthu (2000) and Tan et al. (2002), and holds potential for more efficient NOx, SO2, particulate, trace element and moisture removal since the gas volume that has to be treated for flue gas purification is much reduced. Another challenge for the oxyfuel route is the relatively low purity CO2 produced. The research directions for oxyfuel technology are given in Figure 8.

Figure 8. Oxyfuel research directions.

Combustion temperatures in oxyfuel processes are controlled by recycling a portion of the flue gas, steam or  water back to the combustion chamber. Because of the higher heat capacity of carbon dioxide a reduced inert gas/O2 ratio is typically required (approaching 2.5 : 1 instead of 4 : 1 for  air)  (Chatel-Pelage  et  al., 2003; Tan et al., 2002). The net flue gas, after cooling to condense  the water vapour, contains 80 – 98% CO2 depending on the fuel used and the particular type of oxyfuel process. The recycled flue gas may either be CO2 or H2O.

Oxyfuel alternatives potentially allow for 100% CO2 capture, although a small amount of CO2 (around approximately 4 g/kWh) will not be recovered from oxyfuel cycles using water condensers. The advantages of oxyfuel can be offset by the cost of O2/N2 separation, the high oxygen demand and the efficiency penalty incurred by flue gas recirculation. For oxyfuel boilers air leakage into the system undermines the extra capital and power associated with high purity oxygen and lowering the oxygen purity from 99.5% to 95% will significantly reduce the power consumption. While the amount of excess air (largely determined by variations in air/fuel distribution between  burners in multi-burner installations) of 15 – 20% excess air is normally required in pulverized coal combustion boilers to ensure adequate burnout, 10 – 20% excess oxygen is required for oxyfuel boilers. With significant air in-leakage, inert gas removal to achieve the desired CO2 purity is required. In general, fuel efficiency decreases with increasing oxygen and CO2 purity.

A promising potential application of oxyfuel technology that has been reported (Wilkinson et al., 2003b) is the retrofit of power plant boilers and a range of refinery heaters in the Grangemouth refinery complex in Scotland. The conversion of gas and oil fired heaters to an oxy-fuel boiler required minor burner modifications (a new O2 injection system and a new flue gas recycle line with a separate blower) that could potentially yield increased boiler thermal efficiency due to the recycle of hot gas. In general, modifications to a coal fired boiler are more complex (Allam et al., 2004; Croiset et al., 2000). The CO2 concentration in the flue gas in the Grangemouth case increased to 60%. Impurities (SOx, NOx) and gases (excess O2, N2, Argon) representing about 10% of the stream are separated from CO2 at low temperature (2558C). After cooling, compression and drying of the separated or non-recycled flue gas, the product for sequestration comprises 96%  CO2.18 Production of ultra-pure CO2 for storage would be possible by adding distillation steps to the separation process. Theoretical studies have concentrated on the retrofit option, however, there are advantages in applying oxyfuel technology to modern ultra-supercritical boilers since their increased efficiency reduces the oxygen demand per unit  of generated electricity and therefore the cost end efficiency penalty of O2/CO2 recycle combustion.


The AZEP concept (Sundnes, 1998; Sundkvist, 2005; Griffin et al., 2003), involves the integration of a ceramic membrane in the combustor. The ceramic membrane  allows transport of oxygen and heat, such that the combustion products, chiefly CO2 and H2O are expanded in one turbine, while the heated oxygen-depleted air drives the main combined cycle gas turbine. The optimum operating window for the membrane is such that the turbine inlet temperature is lower than most of the advanced gas turbines, resulting in lower efficiencies.19

Several novel turbine cycles using water, CO2 or a mixture of H2O/CO2 as the working fluid have been proposed in the literature (e.g., Mathieu, 2003). Table 6 contains a broad comparison of the main oxyfuel cycles. The Clean Energy Systems (CES) process is a variant of the water- cycle (H2O recycle) and the Graz cycles (77% H2O and 23% CO2 recycle). A combustor  is fired with  a  mixture  of recycled high pressure water/steam, fresh oxygen and natural gas or synthesis gas. The combustion is performed at essentially stoichiometric conditions to produce steam and CO2 at high temperature and pressure that powers a turbine. The turbine exhaust is used for water/steam heating and is reheated to above 13708C by combustion of additional gas. The remaining turbine sections may have intermediate feed water heaters before the exhaust stream (approximately 90% H2O, 10% CO2) enters a partial condenser and then a condenser/CO2 recovery section. CES commissioned a 20 MWth gas generator at the Kimberlina power plant, California in May 2005. Considerable effort will be required to further develop the gas generator and  the ultra high pressure/temperature turbines required for    a full-scale commercial process.

The Graz-cycle consists of a high pressure (40 bara) combustor, which is fed with natural gas, oxygen, CO2 and steam. The combustor exit stream, at 13288C, is expanded in a high pressure turbine. The turbine exit stream is  cooled in a heat recovery steam generator (HRSG), where high-pressure steam is produced (174 bar, 5608C) and then expanded to 40 bar in a steam turbine. The hot gas from  the HRSG is further expanded in a low pressure turbine before being finally cooled in a condenser. The condensed water and CO2 are separated in the condenser. The CO2 stream is compressed (with intercooling) before it is mixed into the combustor, as an inert gas for the control of the combustor exit temperature. The water collected from the condenser is preheated in the CO2 compression intercoolers, before it is pressurised for steam generation. Excess water, as well as some of the CO2, formed in the combustion is removed from the cycle (Jericha et al., 2003).

18 In addition to 2% N2, 1% Argon and approximately 1% O2 and SO2.
19 Supplementary firing allows higher turbine inlet temperatures and higher efficiency at the cost of lower CO2 capture.

In addition to the lowering the overall fuel efficiency, recirculation of a H2O/CO2 cooling/mixing medium requires the development of turbo-machinery capable of using CO2/H2O mixtures as the working fluid at high temperatures and pressures. The practical design of condensers for good heat recovery from the working fluid (with relatively high concentration of non-condensable gases) is another important challenge. The development of gas turbines capable of operating with very high  temperatures will potentially improve the efficiency of oxyfuel cycles. Relatively low fuel efficiency is reported for all of the oxy- fuel alternatives (Bolland et al., 2005; IEA GHG, 2004).


Chemical Looping combustion, proposed by Richter and Knoche in 1983, divides combustion into intermediate oxidation and reduction reactions that are performed separately with a solid oxygen carrier circulating between the separated sections. Oxides of iron, copper, chrome, manganese and nickel  have  been  investigated  (Lyngfelt et al., 2001; Brandvoll and Bolland, 2004; Zafer et al., 2005; Ishida and Jin, 1994; Cho et al., 2002; Jin et al., 1999; Ishida et  al., 1999, 2002). The major  components  of a chemical looping process are: solid oxygen carriers;    a chemical looping system; fuel and air supplies; heat utilization/recovery and CO2 capture. Although there are various ways to perform CLC, a fluidized-bed combustion system has some advantages over other alternatives, e.g., good heat transfer and effective transport of the solid oxygen carriers between the two reactors. At the present stage of development, the mechanical stability and chemical reactivity over many cycles are the main development issues for this process.


Conventional methods of oxygen production, i.e., cryogenic separation (99.99% O2) and vacuum pressure swing adsportion (90 – 94% O2) consume about 200 kWh/tonne O2. The largest single train air separation unit can produce approximately 3500 tons per day (TPD) of oxygen, a quantity sufficient to support an oxy-fuel power plant having roughly 200 MWe output. Larger single train units (.5000  TPD)  seem  possible  and  to  offer  some  modest improvement in economy-of-scale. (Wilkinson et al., 2003a). A less energy intensive (and thus potentially more cost effective) alternative that has been pursued is the use of oxygen transport membranes to produce pure oxygen from air (e.g. A˚ sen, 2001). Three different alliances—lead by Air Products (e.g., Carolan et al., 2001), Praxair and  the AZEP alliance (Griffin et al., 2003) have been working

Table 6. Comparison of the main oxyfuel alternatives.

on the development of oxygen transport membranes. The advanced zero emission power concept (AZEP) entails the integration of an oxygen conducting membrane with conventional power turbines (Sundkvist et al., 2005; Mo¨ller  et  al.,  2005).  Robinson  et  al.  (2004)  report  that theoretical studies show that the incorporation of an  oxygen transport membrane into steam methane reforming improves hydrogen yield and lowers CO2 and NOx emissions. These dense membranes consist of complex crystalline structures, allowing oxygen ions to diffuse in  the direction of decreasing oxygen partial pressure given  an adequate electronic conductivity that allows the counter migration of electrons.20 At low temperatures, the ionic conductivity of the ceramic material is often too low so that the transport process requires high temperatures, i.e., .7008C, making it attractive to combine these membranes with exothermic processes/reactions (Skinner and Kilner, 2003; Bouwmeester and Van Der Haar, 2002; Dyer et al., 2000; Bredesen et al., 2004). In addition to achieving adequate oxygen flux, mechanical and compositional stability over repeated thermal and oxygen concentration cycles, preventing fouling/coking, achieving a high surface area/ volume design and module fabrication for large-scale applications are very serious development and commercialization challenges for these types of membranes.

20 Oxygen separation occurs as O2 molecules diffuse to the membrane surface, followed by dissociation into oxide ions, ions are transported through the membrane by sequentially occupying the oxygen ion vacancies and recombine on the other side of the membrane, liberating electrons. The  ion transport is counterbalanced by a flow of electrons in the opposite direction. The driving force is the difference in the oxygen partial pressure between the permeate and retentate sides of the membrane. Since the transport mechanism is based on ion transport and not molecular sieving, the selectivity of the membranes is infinite as long as there are no cracks or other surface imperfections.


The pre-combustion route is premised on the production of synthesis gas, CO2 removal and combustion of hydrogen. Hydrogen is produced from a variety of feedstock including natural gas, naphtha, heavy oils or coal in processes that convert the hydrocarbon source into synthesis gas. The production of synthesis gas comprises the reforming, partial oxidation and water gas shift reactions:

Different synthesis gas technologies have different approaches to the supply/removal of the heat of reaction and for the supply of oxygen and steam, implying different ways of combining or coupling the reforming and partial oxidation reactions. The shift reactions convert the CO to CO2 and increase the hydrogen yield. For coal and heavy oils various forms of gasification form the main synthesis gas production technology. Pre-combustion CO2 capture based on coal is termed integrated gasification combined cycle (IGCC). The two predominant synthesis gas technologies from natural gas are steam methane reforming (SMR) and autothermal reforming (ATR). SMR introduced in the 1930s is by far the most common process. The current upper limit for the capacity of single trains SMR plants is around 480 tonnes/day hydrogen, and hydrogen is recovered at high pressure using pressure swing absorption. A SMR unit consists of Ni-alloy tubes filled with catalyst, which are heated externally by burners. The ATR  is  a large refractory-lined vessel with a burner and catalyst bed. The partial combustion of natural gas with oxygen and steam occurs in the burner, and the reactants equilibrate in the catalyst bed to form synthesis gas. The addition of steam is required to prevent coking and  and  soot formation (Wilkinson and Clarke, 2002).

The production of hydrogen from fossil fuels is energy intensive, and about 20 – 25% of the energy is irreversibly dissipated during the conversion (see Corradetti and Desideri,  2004;  Ertesva˚g  et  al.,  2005).  Typically  the  product stream from the shift reactors has a CO2 concentration of CO2 in the range 15 – 60% (dry basis) and the total pressure is typically 2 – 7 MPa, which enables more efficient CO2 separation (by e.g., amine absorption or physical absorbents like Selexol). Using amine absorption to recover the CO2 followed by a PSA (Sircar and Golden, 2001) unit for hydrogen recovery, the efficiency penalty for the CO2 capture unit in a natural gas fired large SMR plant  is around 3% at 88% capture (IEA GHG, 1996). CO2 capture is already commonly used in the production of ammonia and urea. The main research directions for pre-combustion CO2 capture are shown in Figure 9.

A key aspect for all synthesis gas technologies is whether the oxidization agent is pure oxygen or air. In addition to the cost of the air separation unit, the compression of air and oxygen requires substantial power, comprising the largest parasitic load on a reformer or integrated gasification facility. The integration between the reforming and turbine units can improve thermal efficiencies: For example, air extracted from the gas turbine air compressor can be mixed with the products from the pre-reformer and preheated against exhaust gas before entering the reformer and steam generated from the waste heat from reforming is used in the steam turbine. For IGCC units, the high partial pressure of the CO2 allows the use of physical solvents (e.g., Selexol). Cryogenic separation (e.g., Fluor’s CO2LDSepw) is another alternative. The parasitic load from air separation can be reduced by extracting a portion of the air from the compressor of the gas turbine to feed the air separation unit. However, because of reliability problems associated with 100% integration found at several demonstration IGCC facilities, current industry thinking in the US is that about 50% integration is the recommended maximum (Rosenberg et al., 2005).

For air-blown systems, the introduction of nitrogen markedly increases equipment sizes (this must be traded off against the high cost of an air separation unit). For CO2 capture, oxygen-fired, high pressure systems—resulting in higher CO2 partial pressures—may be preferred, but given that nitro- gen is required for combustion in the hydrogen turbine, air- fired systems may be economic for natural gas fired systems.


Worldwide there are more than 400 gasifiers in operation that do not generate electricity, but produce synthesis gas and various other by-products of high rank coal and residual oil gasification. In these facilities, CO2 is separated after the gasification stage. CO2 capture costs for IGCC plants are among the lowest reported, see Table 7. The synthesis gas or hydrogen are used as a fuel or for chemical raw material, e.g., for liquid fuel manufacturing or ammonia synthesis. Bracht et al. (1997) report the economic potential of novel shift reactor and IGCC concept. There are a number of gasification technology suppliers, among them General Electric (acquired from ChevronTexaco), Shell, Foster Wheeler, E-GAS (ConocoPhillips and Fluor alliance) and Mitsubishi Heavy Industries (McDaniel and  Hornick, 2002). A comparison of gasification technologies can be found in Zheng and Furinsky (2005) and Rosenberg et al. (2005). Despite the worldwide commercial use and acceptance of gasification processes and combined cycle power systems, the integration of a coal gasification with a combined cycle power block to produce electricity as a primary output is relatively new, and has been demonstrated at only a handful of facilities around the world (see Table 8 for an overview). The commercial gasification processes believed most suited for near-term IGCC  applications using coal or petroleum coke feedstock are the General Electric, ConocoPhillips, and Shell entrained-flow gasifiers. Each of these technologies is currently deployed at an operating commercial IGCC facility (see Table 8).


The hydrogen turbine is the unit that is common for all pre-combustion technologies for all fuels. Pure hydrogen presents several complex challenges for flame stability due to its very high flame speed when premixed, and its high temperatures when non-premixed. The high flame temperatures resulting from hydrogen combustion are attenuated by the addition of nitrogen and/or steam. General Electric’s (GE) IGCC group has utilized fuels with H2 contents between 8% and 62% and fuels having up to 95% H2 have been used in GE turbines in process plants. General Electric reports having completed feasibility testing for 100% H2 fuel to define the entire combustion map that shows that ratios of 50/50 H2/N2 can produce very low NOx as well as provide enhanced output in a modern IGCC gas turbine. The rate of NOx generation varies exponentially with flame temperature and linearly with the amount of time that the gases are exposed to the flame zone. NOx emissions can be reduced either with a conventional, diffusion-based combustor with nitrogen and/or steam dilution, or with a dry low emissions (DLE) premixed combustion system.

Figure 9. Pre-combustion research directions.

Table 7. Cost comparisons of the main technology options.

At present, only dilution based on diffusion is commercially available for hydrogen-rich combustion and increases in hydrogen content increase the required amount of dilution gases. Although steam is the more effective of the two diluents, steam dilution results in higher metal temperatures of the hot-gas components that can reduce equipment lifetimes if firing temperatures—and thereby also engine efficiency— are not reduced. Moreover, steam extraction has a direct negative impact on the energy efficiency of a combined cycle. So, nitrogen is generally preferred over steam for dilution, but for high hydrogen content, the large volumetric flow to the combustor presents a design challenge.

Modifications to the combustors and fuel mixing system are the principal requirements when converting a natural gas turbine to burn hydrogen-rich fuels. Although hydrogen has almost three times more energy by mass than natural gas, by volume the energy density is much lower. As a result, hydrogen fuelled gas turbines will require larger delivery piping, manifold, valves and nozzle sizes than natural gas-burning engines currently need. Compressing hydrogen to a greater operating pressure than natural gas,  to increase its volumetric energy density, would mitigate the increased size requirements for delivery  equipment. The flammability range of hydrogen is quite large compared to other fuels, so that the fuel/air ratio can be throttled for much leaner combustion.

Table 8. Overview of existing IGCC facilities (after Rosenberg et al., 2005).

Although hydrogen combustion turbines are not presently commercially produced, there appears to be no major technical barriers for gas turbines burning gases with hydrogen contents up to roughly 70%. While immediate efficiency gains could be obtained using hydrogen in place of natural gas, these would likely be offset by NOx control considerations, such as a lean fuel/air mixture to limit the combustion temperature. Since efficiency and power roughly can be considered equal between these fuels, the most significant gain from converting to hydrogen fuelled gas turbines is its nearly completely clean emissions profile. Todd and Battista (2001) have reported combustion trials assuming the modification of an existing GE frame 9F turbine. Steam injection was selected as the method of limiting NOx production. An alternative to  steam  injection is to use inlet fogging techniques  (e.g.,  Van de  Burgt, 2004). Such techniques are increasingly used in commercial operation to increase turbine output (up to 20%), to reduce heat rate, to improve turbine efficiency and to reduce NOx emissions. These systems inject only of the order of 1% H2O by weight in a fine spray upstream of the compressor. Wotzak et al. (2005), report on the suitability for hydrogen utilization of the  GE Frame 5002C and 6001B gas turbines at the BP Prudhoe Bay Facility. All the three big suppliers (GE, Siemens and Alstom) communicate a general interest in developing low emission and high-efficiency hydrogen combustion. This is also manifested through their participation in big research projects such as ENCAP (EU) and FutureGEN (USA).


Many novel pre-combustion concepts or improvements have been published (see for example Middleton et al., 2002; Holt et al., 2003; Jordal et al., 2003). A  few of  them are mentioned here. The sorption enhanced reaction process (SER) combines catalytic shift conversion (of carbon monoxide and steam to hydrogen and carbon dioxide) with a high temperature CO2 adsorption system using a mixture of solid catalyst and adsorbent  (e.g.  Hufton et al., 1999; Hufton et al., 2005; Liang et al., 2004). The conversion and CO2 removal steps are carried out in a multi-bed pressure swing adsorption unit which is regenerated using low pressure steam which is subsequently condensed to leave a relatively pure CO2 stream.

The removal of hydrogen in dehydrogenation and synthesis gas reactions with membranes has been widely studied. Two different approaches have been investigated: Integration of a membrane into the reformer and integration of a membrane into the high temperature shift reactor. Product removal may occur by H2 permeation through a Pd-alloy or composite Pd-ceramic membrane or a ceramic porous membrane. The permeation of the sweep gas onto the feed (i.e., retentate) side also contributes to increasing the conversion.


The CO2 purity requirements for the whole CCS chain are being formulated. For CO2 capture for enhanced oil recovery (EOR), experience from existing  large-scale  EOR can be drawn upon (Stevens et al., 2001) The CO2 concentration of gas produced from CO2-rich geological accumulations varies over a wide range: the CO2 content   of gas produced from the Jackson Dome in the  USA can be as low as 65%, while the McElmo Dome (USA) produces 98 – 99% CO2. The CO2 purity requirements for ECBM and storage only (i.e., no hydrocarbon production) are believed to be less stringent than those for EOR. For EOR, components like N2 and O2 below 300 and 50 ppm levels respectively may be required, although for the SACROC EOR project in the USA (for example), a maximum content of 4 mol% N2 is specified. Since immiscible components may increase the minimum miscible pressure in the reservoir and thus decrease the efficiency of CO2 injection, the total concentration of components immiscible with oil (CH4, Ar, N2 and H2) is important and the effect of the immiscible components is likely to be assessed for each EOR project. Oxygen present in the gas stream may cause precipitation reactions and reduce the permeability of the reservoir, or react exothermally with oil and cause over- heating at the injection point. Particulates pose the danger of pore blockage near the injection well thereby reducing reservoir permeability. Acidic compounds, such as H2S, COS, CO, SO2 and NOx are corrosive and will be reproduced with the recovered hydrocarbons, affecting the choice of materials and potentially increasing the down-  stream processing required. Sulphur components may also downgrade produced hydrocarbons by increasing their sulphur content. Where water-alternating-gas (WAG) technol- ogy is the EOR strategy adopted, the CO2 stream will come into contact with water at the top of the well. To prevent hydrate formation, heating of the CO2  above  158C  may be required. The composition of the gas to EOR will, in other words, have important implications for the modifications that are required at the injection point and for investments in the downstream oil and gas processing equipment.


Haines et al. (2004) present a methodology for screening and comparing different processes for CO2 capture. Reported costs of CO2 capture are packed with technological and economic assumptions. Numerous comparisons of options for CO2 capture are to be found in the literature: Parsons (2002a,b), Bolland (2002), Singh et al. (2003), Haines et al. (2004), Kvamsdal et al. (2005b), Steinberg   et al. (1984). The recent IPCC report on CCS  (IPCC, 2005) contains a thorough review of a number of technology comparisons that have been performed. Table 7 presents a selection of the reported costs in the literature. For comparisons between different approaches to CO2 capture to be meaningful, the competing methods must be based on shared assumptions about plant size, feedstock quality, product quality, CO2 delivered (purity, temperature and pressure), and the quality of available utilities (e.g., cooling water temperature). For natural gas fired systems, techno-economic studies show that the fuel price has the largest impact on the production cost of electricity, making the  fuel efficiency of new concepts the most important selection criterion (e.g., Mo¨ller et al., 2005). Theoretical fuel efficiency achievable on paper can in turn be based on optimistic assumptions about, e.g., turbine inlet temperatures, turbine efficiencies, steam levels achievable in Heat Recovery Steam Generators, lowest pressure achievable in condensers and heat exchangers that cannot be built using  current material technology (e.g., assuming that high  temperature heat exchange with synthesis gas is possible even in the operational areas where metal dusting21 is known to occur). Technology choice implies a trade-off between fuel efficiency, other operating expenses like maintenance or plant availability and capital costs. Internal consistent  comparisons do not necessarily result in credible costs for CO2 capture and storage: conventions or published methods (e.g., Turton et al.,  2003)  for  preparing  cost estimates  may differ from in-house standards for doing economic analysis that include assumptions about fuel and capital costs (including the economic life of the plant, on-stream factors, weighted average cost of capital, inflation effects, interest charges  during  construction,   taxation,   commissioning costs and contingency elements). In addition to other site- specific details like labour costs and weatherization costs associated  with  temperature  or  other extremes,  methods for assessing costs often  reflect  a  firm’s  orientation toward risk. For this reason, published costs are often not transferable  across  organizational boundaries.


Given the glaring disadvantages of the conventional methods, there is room for novel methods that can bring about a step-change in efficiency of CO2 capture. In addition to the commercially available separation techniques, the number of different concepts for separating CO2 is limited only by the creativity of the scientists and engineers who are set to work on the problem. Among the novel concepts, not described in detail here, but that have been forwarded is: biological CO2 fixation with algae (algae convert CO2 to organic material) and formation of CO2 hydrates. An  air-lift bioreactor with variable—but up to 95%—CO2 removal is reported by Vunjak-Novakovic et al. (2005). This technology is the basis for the venture start-up Green- Fuel Technologies Corporation, which has also announced that a larger field trial of the bioreactor for the combined removal of CO2 and NOx.22

The use of dry regenerable sorbents has also been investigated. The CO2 is chemically absorbed by the sorbent and is then subsequently released in a second step to produce a concentrated stream of CO2 at which point the sorbent is regenerated and recycled. Sorbents such as sodium carbonate, calcium oxide and lithium silicates/zeolites have been investigated (Kato et al., 2001; Abanades, 2002; Abanades et al., 2004a,b; Klara and Srivastava, 2002; Hoffman et al., 2002; Kimura et al., 2005). Solid supports impregnated with amines have also been suggested (Contarini et al., 2002). While the carbonation of CaO to CaCO3 involves the separation of CO2 above 6008C, and regeneration at 9008C, temperatures of about 30– 1008C are used to regenerate amine impregnated solids. Reactor systems that have been suggested for this type of process include fixed bed reactors, moving bed reactors and fluidized bed reactors. The main challenges for solid absorbents (e.g. Abanades et al., 2004a; Abanades et al., 2004b; Green et al., 2002) on a large scale are the costs of solids handling and dust elimination equipment, the cyclic absorption capacity and mechanical strength of the absorbent. Electric swing adsorption, involving the adsorption of CO2 on a charged carbon substrate and high-temperature polymer (solution-diffusion) membranes have also been proposed (e.g., Van der Sluijs  et al., 1992).

21 Boudard reaction: 2CO C CO2. One of the mechanisms that lead to the disintegration of metals. The critical temperature range is 400– 8008C and the relative concentrations of CO2/CO  determining the  reaction rate.

A further possibility for solid fuel firing is described by Alstom (Griffin et al., 2003)—a high temperature carbonate loop is proposed in which calcined limestone is used to remove CO2 from oxygen rich flue gases. Limestone circulates between a high temperature calciner—that produces free lime and CO2 for subsequent processing and disposal—and a high temperature region of the furnace where CO2 is absorbed.


The transport of CO2 by land-based pipelines is a well- established practice worldwide: For example, 50 million tonnes/year of CO2 are transported in pipelines  that  extend over more than 2500 km in western USA, mostly carrying CO2 from natural sources to enhanced oil recovery projects (IEA GHG, 2002a; West, 1974). The Cortez pipeline is the largest example, with a diameter of 30 in and a capacity of 12.2 Mt CO2/year. The CO2 for this pipeline is produced from the McElmo field, operated by Kinder Morgan, which contains 97 mole%  of pure CO2. Before  the CO2 is pumped down the pipeline, it is cleaned, dehydrated and  compressed  to  supercritical  pressure  (145 bar). The use of pumps to  transport  supercritical  CO2, rather than compressors for gas phase transport, reduces operating costs significantly. In 2007, the first  long distance (150 km) offshore CO2 pipeline will be commissioned as part of the Snøhvit LNG project.

The most widely used operating pressure is between 7.4 and about 21 MPa, although the design pressure  is obviously dependent on the desired delivery  conditions, the transportation length and  the  composition of  the gas to be transported. Above 7.4 MPa, CO2 exists as a single dense phase over a wide range of temperatures. The solubility of water in CO2 (to determine the percentage free water) and corrosion rates  are  important  considerations for establishing the material specification for a CO2 pipeline. Water solubility in CO2 is given in Heggum et al. (2005). Existing practice for inhibiting hydrate formation and preventing excessive corrosion rates for carbon steel is to reduce the water content to ppm-levels using either molecular sieves, glycol (MEG/TEG) or alumina desiccants. The requirement for CO2 pipelines, used for EOR in the USA, is maximum 600 ppm water (Heggum et al., 2005). While accurate estimations of the water solubility is key to determining the corresponding corrosion rates and thus the dehydration/corrosion inhibition requirement, the solu- bility of water in CO2 is influenced by the concentration of other components (e.g., hydrocarbons, N2) (Skovholt, 1993). The presence of hydrocarbons tends to lower the water solubility, as do decreasing temperatures. For deep water pipelines, the static head contributes to increased pressure and increased water  solubility, and  therefore tends to prevent the formation of free water. At the LNG plant at Hammerfest in Norway, CO2 will be removed from the natural gas prior to the LNG liquefaction unit. The drying requirement for CO2 pipeline transporting the captured  CO2  to  the  Tuba˚en  formation,  is  50 ppm  water, which is the engineering practice for transportation of natural gas (Heggum et al., 2005; Maldal and Tappel, 2004).

An important area of future research is to improve understanding of the influence of the impurity concentration on thermo-physical properties such as critical pressure and temperature, mixing properties and how  changing  CO2  gas properties affect the design and operating parameters  of the compression equipment.

Transport scenarios for CO2 have been reported by Skovholt (1993) and Svensson et al. (2004): For long distance, offshore transport of CO2 an alternate approach   to pipelines is a logistics chain consisting of CO2 liquefaction and intermediate storage facilities, ships, loading and unloading systems. It has  been proposed that liquid  CO2  is transported  at a  temperature of 2508C  and a pressure  of 7 to 8 bars. Large-scale liquefaction of CO2 is best achieved in an open cycle, using the CO2 feed as the refrigerant where the refrigeration is partly or fully provided by the feed gas itself. The liquefaction process includes compression, cooling and expansion to the liquid product specification. In addition volatile gases and water are removed (in gas scrubbers and an adsorption  gas  drier). The  process  delivers CO2 at  6.5 bara and  2528C  to the storage tanks, with power consumption  of  about 110 kWh/tonne liquid CO2 (Barrio et al., 2004).

Ships have the advantage of introducing flexibility in the CO2 value chain, allowing collection of concentrated CO2 from various sources at volumes below the critical size for pipeline transportation. Even though Yara International and the Anthony Veder Group routinely transport CO2 by ship for the North-European market, the ships currently in service are too small for large-scale ship-based transport of CO2: Yara charters three ships carrying 900– 1200 tonnes of CO2 (1000 and 1500 m3, at a transport pressure of about 14 to 20 bara) While ships of up to 10 000 to 30 000 m3 with the flexibility to also transport LPG have been studied, the carrying capacity will be influenced by harbour conditions, volumes and distances (Berger et al., 2004).

Ship-based transport would require liquefaction plants and  intermediate  storage  at  each  loading  site  (Lekva  et al., 2005). If an onshore CO2 hub were to be introduced, intermediate storage facilities matching the incoming amounts of liquefied CO2 would also be  needed.  Care must be taken to avoid dry-ice formation in the process plant, storage and when loading and unloading. In the dense phase, CO2 is pumped to a pressure sufficient to avoid phase transition during transfer and further to the injection pressure required. The total costs of ship-based transport are calculated to 23 – 31 USD/tonne for volumes larger than 2 million tonnes/year and distances limited to the North Sea (Berger et al., 2004).


Geological storage of CO2 in the earth’s upper crust is a naturally occurring phenomenon. Carbon dioxide from biological activity, volcanic activity, and chemical reactions is found underground either as dissolved/precipitated carbonate   minerals,   or  in  supercritical  form. Candidate   geological formations for CO2 storage are  depleted  oil  and gas reservoirs, deeply buried saline aquifers and uneconomic coal seams (Buller et al., 2004; Heinrich et al., 2003). A review of geological storage of CO2 can  be  found in Benson (2005). Depleted oil and gas reservoirs have the advantages of being proven traps; having well-known reservoir geology and of having  infrastructures  that can readily be adapted for CO2 transport and injection. Nevertheless, relatively few hydrocarbon reservoirs are currently depleted or near depletion, so that the timing of CO2 storage will depend on reservoir availability (Beecy and Kuuskraa, 2005). Deep saline aquifers that could be used for long term CO2 storage are innumerable: In both cases—depleted reservoirs and saline aquifers—much of the injected gas will eventually dissolve in the formation water, while some may react with the minerals to form carbonate precipitates. Rough IEA (2004b) estimates of how much CO2 could be stored in the various geological options are .15 Giga tonnes in unminable coal seams, 920 Giga tonnes in depleted oil and gas fields and  400 – 10 000 Giga tonnes in deep saline aquifers. Table 9 below lists   the large-scale CO2 injection projects worldwide.

Table 9. List of present and near future CO2 storage.


Motivated by the offshore CO2 tax imposed by the Norwegian government, currently at around 54 USD per tonne, since 1996 about 1 million tonnes per year of CO2 have been separated from the natural gas and stored in a saline aquifer (the Utsira formation) at the Sleipner field. A special feature of the field is the high carbon dioxide content. Initial gas produced from the main field contains about 9 mole% CO2 which must be reduced to an average of 3 mole% to meet customer specifications (Baklid et al., 1996; Hansen et al., 2005). The CO2 is stripped from the well-stream using an activated MDEA absorption process. The amine plant, which weighs  about 9000 tonnes and is 35 m high, cost NOK 2 billion (about USD 300 million) in 1996, see Figure 10. Once the CO2 has been captured, its pressure is boosted by four compressors to  80  bara prior to being transferred to the Sleipner A platform for injecting into the base of the saline aquifer (Hansen et al., 2005). The cost of CO2 storage by this method has been estimated to be close to 15 USD per tonne CO2 (Torp, 2004). To predict the migration path of the injected CO2 and the storage capacity of a reservoir, the appraisal of the reservoir geometry and the presence of faults must be conducted over a range of scales. In addition, the construction of simplified geological models based on all the available data may be need to supplement reservoir simulation. As CO2 is buoyant (in both gaseous and fluid phases) it will tend to rise to the top of the repository reservoir. Assessment of the depth to the top of the reservoir is therefore a basic prerequisite of CO2 storage, allowing a first order estimate of short-term storage capacity, and the assessment of likely migration pathways (Buller et al., 2004). The detection of possible reservoir compartmentalization and/or the potential for fault-related leakage is also important. The presence of reservoir compartmentalization could lead to a rapid increase in formation pressures with time as fluid flow between compartments is inhibited. The identification of small-scale faulting requires seismic data of adequate resolution (Ibid). The migration of CO2 in the Utsira Formation has been monitored using 4D23 seismic. A baseline  survey  was shot prior to injection in 1994, and repeat surveys have so far been acquired in 1999, 2001, 2002 and 2004. The 2004 seismic survey revealed that (after the injection of approximately 7 million tonnes) the area of the supercritical CO2 plume was about 2 km2 with a maximum lateral migration from the injection point of 1.5 km to the northeast (Hansen et al., 2005; Arts et al., 2004).

Figure 10. CO2 injection at the Sleipner Field.

Very long term geo-modelling of the Utsira aquifer suggests that most of the CO2 will eventually dissolve in the formation water: flow simulation models, calibrated with the 4D seismic data, have been used to predict the  CO2 behaviour in the Utsira Formation, over periods of hundreds to thousands of years. The results of  these  models predict that, following accumulation beneath the rock cap seal for a few years after the injection  has  ceased, the CO2 will spread laterally on top of the brine column with migration routes controlled by the topography of the Utsira Formation/cap rock interface. It has been suggested that the area size of the free CO2 plume may reach its maximum size after a few hundred years, and most of the CO2 will have dissolved into the aquifer after between 5000 and 50 000 years (Hansen et  al.,  2005). The non-porous mineral volume  composition  of  the Utsira formation is mainly quartz  (76%),  K-feldspar  (7%), plagioclase (3%), mica (5%) and calcite (7%). Long-term (10 000 year perspective) numerical modelling of the reactivity of the CO2 in the aquifer indicates that  only minor dissolution of the calcite occurs: the total volume of minerals undergoes little change and the overall porosity is unaffected over time (Audigane et al., 2005; Hansen et al., 2005).

At depths below 800 m, the properties of supercritical CO2 (including its high density)  potentially  provide  for the efficient usage of the pores in the sedimentary rocks (Benson, 2005). Carbon dioxide can remain trapped underground through a number of mechanisms: trapping below the cap rock; retention as an immobile phase  trapped  in the free pore volume of the storage formation (also called residual gas saturation); dissolution in the fluids present; and/or adsorption onto organic matter in coal and shale  (Benson, 2005; White et  al., 2003). Additionally, it may  be trapped by reacting with the minerals in the storage formation and cap rock to produce carbonate minerals. By avoiding deteriorated wells, or open fractures or faults, injected CO2 will be retained for very long periods of time.24 The Sleipner case has yielded considerable insight which has been worked into a Best Practice Manual for  CO2 storage by the SACS and CO2STORE25 projects.

BP, the Algerian National oil and gas company, Sonatrach, and Statoil are participants in the In Salah gas project, comprising eight gas fields in the central Saharan region of the country (Riddiford et al., 2004). Like at Sleipner, naturally occurring CO2 must be removed from the produced gas to meet market specifications. Adequate seal integrity, storage potential, good reservoir properties and a suitable reservoir pressure were the main criteria for identifying a good CO2 storage solution for the project. In addition, placement of the CO2 must be such that it is retained within the aquifer zone and is not reproduced with hydrocarbons during the life of the field. There is no CO2 tax in Algeria and storage of CO2 is being done for environmental considerations only. Starting in 2004, approximately 1.2 million tonnes per year CO2 has been removed, compressed and in this case injected at a depth of 1800 m into an aquifer section at a remote corner of the Krechba gas field.

Maldal and Tappel (2004) describe the planned CO2 injection at the Snøhvit field. A schematic of the CO2 compression and injection system is shown in Figure 11. Starting in autumn 2006, CO2 injection will occur at the north-western  part  of  the  Snøhvit  field,  into  the  Tuba˚en formation, CO2 injection at Snøhvit will extend knowledge of CO2 storage in offshore aquifers since there are important differences between the Utsira and Tuba˚en formations (see Table 10). Similarly to the CO2 injection into the Utsira formation, 4D seismic will be employed at Snøhvit to monitor the CO2 injection. To provide a broader base of data, one of the gas producers could be deepened and used as a monitoring well for the injection if deemed necessary. In addition to the existing and planned CO2 storage projects, experience with CO2 flooding for EOR is relevant for storage: Hypotheses about the interaction of CO2 with other components (hydrocarbons, nitrogen and H2S) may be tested against existing data from EOR projects. In addition, monitoring techniques and safe practice encompassing proper operator training, maintenance procedures, pressure monitoring, reliable gas detection systems, emergency shutdown procedures and other safety systems relevant for EOR can be adapted for CO2 storage. In this regard, experience from the acid gas projects in Canada can also be exploited (Bachu and Gunter, 2005). Evidence from the Sleipner, Weyburn, and In Salah projects, indicates that it is feasible to store CO2 in geological formations. Chevron is proposing to remove CO2 from produced gas at  the  Gorgon  field, containing approximately 14% CO2 off Western Australia. The CO2 will be injected into the Dupuy Formation at Barrow Island (Oen, 2003, cited in IPCC, 2005). In the Netherlands, CO2 is being injected at pilot scale into the almost depleted K12-B offshore gas field  (van der Meer et al., 2005, cited in IPCC, 2005).

Figure 11. Schematic of CO2 injection at Snøhvit after Maldal and Tappel, 2004.

Table 10. Comparison of salient features of utsira and tuba˚en formations.

23 Data along the three geometric dimensions plus time-interval data.
24 As discussed previously, detailed seismic mapping can be used to identify fractures and faults.
25 The aim of the CO2STORE is to prepare the ground for widespread underground storage of CO2 in aquifers. CO2STORE is a research project


Trials with the use of CO2 for producing incremental oil began as early as the 1950s (Holm and O’Brien, 1971) and the large-scale injection of CO2 into subsurface geological formations was first undertaken in Texas, USA, in the early 1970s, for EOR as a response to the first oil price shock. Miscible CO2 flooding has become an increasingly important enhanced oil recovery technique in the USA for recovering residual or bypassed oil. At present there are 71 active CO2 EOR projects in the USA (Oil and Gas Journal, 2004) and approximately 12 operations outside of the USA.

The majority of these projects are clustered in the Permian Basin, located in west Texas and the adjoining area of south-eastern New Mexico and account for approximately 4% (206 000 barrels/day) of the total USA oil production in 2004 (Oil and Gas Journal, EOR Survey, April 12 2004). Approximately 30 million tonnes per year CO2 are injected for EOR worldwide (Oil and Gas Journal EOR survey, April 12 2004). The largest EOR injection rates exceed 10 ktonne/day, the typical emission rate of a 500 MW coal-based power station (Herzog, 1999). With CO2 EOR, the CO2 content of the produced gas changes from 1 to 5% vol at the start and goes beyond 80% towards the end of the project life. The extensive history of CO2 injection in the USA and experience from other countries (including Turkey and Trinidad) indicates that this technology can increase oil recovery by 7 – 15% for land-based fields as compared with water flooding alone: Holt et al. (2005) surveyed a selection of real field projects worldwide and concluded that CO2 injection yielded, on average26 incremental oil recoveries above 12% and 17% of the original oil in place for sandstone and carbonate reservoirs, respectively. In a report issued by the Norwegian Petroleum Directorate27 ( in 2004, reservoir characteristics (including the spacing of wells) in Norway dictate lower incremental oil recovery (3 – 7%) for offshore fields. Accurate predictions of the EOR potential for a given field can however only be assessed through extensive reservoir modelling using a numerical reservoir simulator and a detailed reservoir model. Prices of delivered CO2     to the Permian Basin typically vary between 9 – 18 USD/ tonne,  following  movement  in  oil  prices  and  averaged around USD 11/tonne for pure, high pressure CO2 during the 1990s (Stevens et al., 2001). The production of CO2 with the hydrocarbons is an important issue, since typically more than 50% and up to 67% of the injected CO2 returns with the produced oil (Bondor, 1992) and is usually separated and re-injected into the reservoir. The remainder is trapped in the oil reservoir either by dissolution in reservoir oil that it is not produced and in reservoir pore space unconnected to the flow path for the producing wells.28

26 The CO2 floods included in SINTEF Petroleum Research’s database with 115 CO2 injection projects.

The Great Plains Synfuel Plant, near Beulah, North Dakota, gasifies 16 326 metric tons per day of lignite coal into 3.5 million standard cubic metres per day of combustible syngas, and close to 7 million standard cubic metres of CO2. A part of the CO2 is captured at high pressure by a physical solvent based on methanol. The captured CO2 is compressed and 2.7 million standard cubic meters per day are piped over a 325 km distance to the Weyburn, Saskatchewan, oil field, where the CO2 is used for EOR (Perry and Eliason, 2004).

Statoil and partners have carried out studies to see if the Tampen offshore area in the North Sea (North of Sleipner) can benefit from the use of CO2. A thorough evaluation consisting of reservoir simulation, an assessing the needed platform   modifications,   transportation   of   CO2   and– not least– in accessing the best CO2-sources for a total need of 5 million tonnes per year (Agustsson and Grinestaff, 2004). Holt et al. (2005) examined the potential for CO2 based EOR in the North Sea, where 67.2 million tonnes of CO2 are injected annually over 40 years and reported that an average potential increase of 7.9% in hydrocarbon pore volume (HCPV). The value (purchase price) of CO2 delivered to export terminals that feeds CO2 into the transportation infrastructure was estimated to be between 7.9 and 12.8 USD/ tonne. When this is compared to the cost of CO2 capture from industrial flue gasses (e.g., a low estimate of 25 USD/ tonne) and transportation from point sources to the export terminals (e.g., 4 USD/tonne), it is evident that the use of CO2 for EOR can cover only a fraction of the total costs associated with CO2 capture, transport and storage.


The fundamentals of combustion and separation processes suggest that the capture of high purity, high concentration CO2 from fossil fuels requires energy. Improved energy efficiency and fuel switching are thus clearly superior strategies for curtailing CO2 emissions, although these strategies do not actively capture CO2 from being   the concern of a few specialists with strong convictions about man-made impacts on the earth, the substantial commitment of public resources to CCS R&D has contributed to establishing research on carbon dioxide capture and storage as part of the mainstream. CO2 capture is premised on the safe long-term storage of CO2 in geological formations. There is sufficient industry-wide know-how for realizing CO2 capture from dilute stationary sources of CO2,  but poor economics prevents this knowledge from being put into practice. None of the major pathways for capturing CO2 from power generation identified at  present  stands out as having greater inherent potential for substantially lowering the costs of CO2 capture  in  the  next  decade. The challenges for chemical engineering are many: to portray technology choice in the context of entire life-cycles, to improve focus on the fundamentals of molecules, materials and naturally-occurring mechanisms (e.g., photo- synthesis) for enhanced process design and increased exploration of hybrid processes (e.g., integrated separation and reaction) that combine the attractive aspects of conventionally discrete unit operations for improved energy and exergy efficiency. The increasing number of storage projects worldwide provides a basis for improved strategies  for the mitigation and management of  risk  associated  with deep geological storage. The use of CO2 for EOR    can cover only a fraction of the  total  costs  associated  with CO2 capture from power production, transport and storage. Apart from technical advance, legislation and regulatory changes will be the stronger drivers for closing the knowing-doing gap for CO2 capture and storage.

28 In the absence of an approach for CO2 capture from the transportation sector, CO2 (captured from the power sector) for enhanced oil recovery may lead to a net increase in global CO2 emissions, and arguments for   the use of CO2 for EOR for limiting CO2 emissions should be moderated with the consequences of increased oil production.

Source: R. STEENEVELDTx, B. BERGER and T. A. TORP - Statoil ASA, Research & Technology Development, Rotvoll, Norway


The 10 largest coal producers and exporters in Indonesia:

  1. Bumi Resouces
  2. Adaro Energy
  3. Indo Tambangraya Megah
  4. Bukit Asam
  5. Baramulti Sukses Sarana
  6. Harum Energy
  7. Mitrabara Adiperdana 
  8. Samindo Resources
  9. United Tractors
  10. Berau Coal