review paper- ccs

REVIEW PAPER

CO2 CAPTURE AND STORAGEClosing the Knowing–Doing Gap

R. STEENEVELDT�, B. BERGER and T. A. TORP

Statoil ASA, Research & Technology Development, Rotvoll, Norway

The capture and storage of CO2 is gaining attention as an option for limiting CO2 emis-sions from the use of fossil fuels. CO2 capture is premised on the safe long-term sto-rage of CO2 in geological formations. Naturally occurring CO2 is used for enhanced

oil recovery in the USA, Trinidad, Turkey, Hungary, Brazil and Croatia. Industrially producedCO2 has been used for enhanced oil recovery at the Rangely field in Colorado, USA since1986 and at the Weyburn field in Saskatchewan, Canada since 2000. Large-scale CO2 storagein geological formations to avoid CO2 emissions was first undertaken offshore in Norway in1996 and onshore in Algeria in 2004. CO2 delivered for EOR in the USA averaged aroundUSD 11/tonne CO2 during the 1990s. The cost of CO2 capture from low concentrationindustrial sources varies with a number of factors, but will certainly be very much higherthan the recovery of naturally-occurring CO2. Adequate knowledge exists in the oil andgas industry for the application of CO2 capture and storage. Widespread implementation offully-integrated CO2 value chains will nonetheless depend on achieving public acceptanceand regulatory approval for CO2 storage, cost reduction for CO2 capture and sufficienteconomic incentives for the key actors involved. This article discusses the most importantresearch directions for CO2 capture and storage projects that have been initiated around theworld. The adequacy of economic incentives will strongly influence how quickly producersand users of fossil fuels are able to close the knowing-doing gap for CO2 capture and storage.

Keywords: carbon dioxide capture; carbon dioxide storage; carbon dioxide transport; carbondioxide value chain; carbon dioxide capture costs.

INTRODUCTION

The world’s dependence on fossil fuels for the satisfactionof primary energy needs is at odds with growing atmos-pheric emissions of CO2 from the combustion of hydro-carbons. Given their high energy density and availability,fossil fuels are likely to continue to provide more than80% of total world energy requirements for the comingdecades, with especially coal and natural gas assertingtheir positions in the fuel mix by providing 38% and30%, respectively of electricity demand in 2030 (IEA,2004a). On a global basis, coal accounted for 24% of pri-mary energy consumption in 2004, oil for 34%, naturalgas for 21%, nuclear for 5%, large hydropower for 6%and renewable accounting for approximately 10% (BP,2005) Power generation comprises the largest source ofCO2 emissions (see Figure 1) (IEA GHG, 2002b).Flue or stack gases from this sector are usually at atmos-

pheric pressure with the CO2 concentration varying between3% (vol.) for natural gas fired plants and 14% for oil and coal

fired boilers. In addition to fossil fuel based heat and powerproduction, large stationary sources of CO2 emissionsinclude natural gas sweetening, hydrogen production forammonia and ethylene oxide, oil refineries, iron and steelproduction facilities, cement and limestone manufacturingplants. The transportation sector contributed 18% of globalCO2 emissions in 2001 (Ibid). A viable CO2 value chaincould provide the foundation for reducing emissions fromthe transportation sector through the production of hydrogenfrom fossil fuels. While the CO2 content of emissions fromammonia, ethylene oxide and refinery reformers is typicallyabove 95% (dry volume basis), iron and steel, cement andlimestone production results in atmospheric emissionswith a CO2 content of 20% or higher (Sheinbaum andOzawa, 1998). Figure 2 shows that large-scale commercialapplications of CO2 separation technology have typicallybeen from streams where the partial pressure of CO2 isrelatively high. Some newer concepts for power productionfocus on producing a pressurized and/or concentratedstream of CO2 so as to reduce the energy required for separ-ation. Where systems for CO2 transport and storage aretolerant of contaminants like SOx, NOx and Hg, potentiallycostly investments in flue gas clean-up may be circumventedby co-storage of these components with the CO2.

�Correspondence to: Ms R. Steeneveldt, Statoil ASA, Research & Tech-nology Development, Arkitekt Ebbellsvei 10, Rotvoll, N-7005, Norway.E-mail: [email protected]

739

0263–8762/06/$30.00+0.00# 2006 Institution of Chemical Engineers

www.icheme.org/cherd Trans IChemE, Part A, September 2006doi: 10.1205/cherd05049 Chemical Engineering Research and Design, 84(A9): 739–763

Improved energy efficiency, fuel switching (e.g., fromcoal to natural gas) and the capture and storage of CO2

are strategies for climate change mitigation that reconcilethe continued use of fossil fuels with goals to reduce CO2

emission related to meeting global energy needs.1 Thisarticle focuses on CO2 capture and storage (CCS). Themajor components of a CCS value chain include capture(i.e., separation and compression to supercritical state)transport and storage (including measurement, monitoringand verification of safe operations). The large scale appli-cations of CO2 that have been identified are the use ofCO2 for enhanced oil recovery (EOR2), and for enhancedcoal bed methane (ECBM3).The costs of CCS based on fossil fuels depends on a

number of variables and considerations (see for exampleBock et al., 2003; Rubin and Rao, 2003), including thecost of fuel, the technology characteristics of the poweror industrial plant, the scale of the capture plant, the per-centage CO2 captured, the characteristics of the storagesite and the required transportation distance. CO2 capturefrom high pressure, high CO2 concentration streams canpotentially be performed at lower cost than from exhaustgases from power production. In general, for CO2 captureand 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 thevalue chain4: The application of capture technologywould add about 0.18–0.034 USD/kWh to the cost of elec-tricity from a pulverized coal power plant, 0.09–0.22USD/kWh to the cost for electricity from an integratedgasification 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 overviewof the cost distribution, reproduced in Table 1. For example,Kvamsdal et al. (2005b) reported 67 USD/tonne5 total costsof CO2 capture from a 860 MW power plant, whereof54 USD/tonne was the cost of capture and 13 USD/tonnethe transport cost for a 150 km pipeline.

There is remaining uncertainty about the application ofthe London (Dumping) Convention and the OSPAR Con-vention (Oslo Paris Convention), to CO2 storage offshorein geologic formations. Clarification may require intergo-vernmental negotiations. Public acceptance and endorsementof CO2 storage is an important premise for CCS. Apart fromsizeable research funding only the Netherlands6 and Norwayhave 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 developmentfor reduced capital and operating costs, while research onCO2 storage aims at technology development for monitoringand verifying the safety of CO2 injection.

The main research directions for CO2 storage and cap-ture are depicted in Figure 3. A comprehensive review ofthe extensive literature on CO2 capture and storage is notthe intent of this paper. The objectives of this paper areto: (1) give an overview of the most important CO2 capturetechnologies, (2) examine the status of the most importantCCS projects that have been initiated worldwide, (3) brieflyexamine the remaining development challenges of the maincapture technologies, and (4) discuss some of the chal-lenges for realizing a global CO2 value chain.7

Some scholars have argued that, like with systemsfor SOx removal, the cost of building and operating CO2

capture systems should be reduced over time throughcumulative learning and technological progress (e.g., Alicet al., 2003; McDonald and Schrattenholzer, 2001; Riahiaet al., 2004; Rubin et al., 2004a,b; Rao et al., 2003). Aswill be discussed in the remainder of this paper, there arenumerous technical routes to CO2 capture at differentstages of maturity. The cumulative learning contentionrests on the assumption that there is effective learningacross technology platforms—an assumption that is debat-able where there is a proliferation of approaches. Thebiggest factor likely to influence the implementation ofCCS is government support (both in terms of size andperceived predictability).

SEPARATING CO2: EXISTING TECHNOLOGY

In the petrochemical industry, CO2 is separated fromother gaseous components using both physical and chemi-cal absorbents. Large scale CO2 separation units in oper-ation today focus on the removal of unwanted CO2 athigh partial pressure. The recovery of CO2 from flue gas

Figure 1. Global CO2 emissions in 2001 (IEA).

1Increased use of renewable energies and nuclear energy may also contrib-ute to reducing CO2 emissions associated with meeting energy needs.2Enhanced oil recovery (EOR) is the term used for those techniques thatare put into effect for altering the original properties of the oil to improverecovery from a producing field. Enhanced oil recovery restores reservoirpressure and improves fluid flow. The three major types of enhanced oilrecovery approaches are chemical flooding, miscible displacement (CO2

injection or hydrocarbon injection) and thermal recovery (steamflood orin situ combustion). Enhanced oil recovery is also called improved oilrecovery or tertiary recovery.3Enhanced coal bed methane (ECBM) is the term used for techniques thatincrease the recovery of methane from unmineable (uneconomic) coalseams—CO2 is selectively adsorbed into the pore volume displacing themethane.4The cost of modifications required to implement CO2 injection for EORmay in some cases prove to be substantial.

5Assume 1 ¼ 1 USD.6The Electricity Act that came into force on 1 July 2003, suggests that atax exemption worth approximately 25–40 million in the first year andincreasing every year by between 25–30 million will be established to sup-port renewable energy, energy efficiency and climate neutral electricity,including CO2 capture and storage.7While 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 centralizedpower production. For this reason, research on fuel cells has been excludedfrom this review.

Trans IChemE, Part A, Chemical Engineering Research and Design, 2006, 84(A9): 739–763

740 STEENEVELDT et al.

is performed on a limited scale at a small number of plantsaround the world (IEA GHG, 2004). Physical solvents com-monly in commercial use include methanol, dimethylethers of polyethylene glycol, propylene carbonate, andpotassium carbonates (Astarita, 1983). Conceivable com-mercially available alternatives are selective polymericmembranes and cryogenic separation. The factors influen-cing the choice of separation technology are the partialpressure of the CO2 in the feedstream, sensitivity of themethod to other impurities or trace components, CO2

recovery, capital and operating costs and environmentalimpacts (waste or by-product production). For separatingCO2 from flue gas with very low CO2 partial pressure ina large stream of mostly non-condensable gases, absorptionprocesses using chemical solvents offer distinct advantagesover the alternatives: lower energy use and costs, highercapture efficiency and better selectivity.The application of selective membranes8 and cryogenic

separation is economic for streams having both high feed

concentration of CO2 and high pressure and low concen-trations of other acidic components, like H2S. Despite theobservation that examples of the small-scale commercialapplication of CO2 absorption from flue gas can be foundaround the world,9 the treatment of power plant flue gasfor CO2 storage represents a scale-up challenge: Thecapacity of CO2 capture from flue gas for the supply ofCO2 to the food and beverage industries ranges from 6 to800 tonnes/day CO2 (Herzog, 1999; IEA, 2004b). Sincea 500 MWe pulverized coal power plant emits approxi-mately 10–12 k tonnes/day, and a natural gas combinedcycle plant approximately 4 k tonne/day, this impliesscale-up of 20–50 times (Riemer and Ormerod, 1995;IEA GHG 2000b). With absorber diameters of up to 15meters considered feasible, single train CO2 recoveryplant capacities of up to 8000 tonnes/day are believedachievable, depending on the inlet flue gas CO2 concen-tration. Larger plants could be designed with multipleabsorbers that share a common stripper (Reddy et al.,2003; Roberts, 2002).

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.

USD/tonne CO2 Common cost drivers Specific cost drivers

Capture and compression 5–90 Volume ofCO2 Location

CO2 partial pressurein source

Transport 0–20 Existing infrastructureTransport distance

Storage 2–12 Existing infrastructureStorage capacityMonitoring requirements

8The trade-off between purity and recovery typically experienced withsolution-diffusion membranes, makes it costly to achieve both high CO2

purity and high CO2 recovery.

9Fluor’s Bellingham 330 tonne per day CO2 capture plant is largestcommercial plant based on turbine flue gas.


CO2 CAPTURE AND STORAGE 741

RESEARCH ON CCS

There is significant spending on CCS research and deve-lopment around the world and in particularly in the EU, inthe USA (DOE’s Carbon Mitigation Program), Canada,Australia Japan and Norway. More than USD 80 millionexcluding the matching contributions from industry partici-pants and other research institutions has been directed atCCS research under the EUs framework 5 and 6 pro-grammes (McKee, 2002). The DOE’s Carbon MitigationProgram had an annual budget of USD 46 million in2005, with projections of a baseline funding requirementof USD 30 million per year until 2020. The IEA’s Green-house Gas Program was established in 1991, providing anearly marketplace for ideas and research on CCS. Therecently released IPCC10 Special Report on CarbonDioxide Capture and Storage (http://www.ipcc.ch/activity/srccs/index.htm) knits together the diverse threadsof research on CCS, presenting the results of 15 years ofinternational research effort. Table 2 below lists a selectionof the completed and ongoing international research projectson CCS. In addition there are pilot facilities at Karstø,Norway, Osaka, Japan (Buller et al., 2004) and at theBoundary Dam power station, Saskatchewan, Canada witha capacity of 4–8 tonnes CO2 per day (Wilson et al.,2004). The CO2 capture pilot plant with the largest designcapacity to date, of 24 tonnes CO2 per day, was opened atEsbjerg, Denmark in March 2006. An explicit goal for allongoing research on CCS is the demonstration of new tech-nology at pilot and semi-commercial scales.

CO2 CAPTURE: PATHWAYS TO LOW EMISSIONSHEAT AND POWER

The three main pathways to CO2 capture and storage areshown in Figure 4. CO2 is separated from the other com-ponents to optimize CO2 compression to the dense phase,for cost-effective transport and injection at the storagesite and to meet the purity requirements at the injection

point. All of the capture and storage pathways requireenergy, which implies that processes with CO2 capture pro-duce more CO2/kWh or CO2/product (than equivalentreference plants without capture). For most analyses, thesystem boundaries are drawn such that energy involved inexploration/mining, energy for the production and trans-port of fossil fuels, the energy required to produce andtransport important capture components like, e.g., aminesfor post-combustion and energy required for the disposalof waste is excluded from the analysis. A discussion ofsystem boundaries can be found in Haefeli et al. (2004).Lombardi (2005) found the emissions associated with con-struction and dismantling of capture plants to be negligiblerelative to that of the central combustion processes. TheCO2 emissions directly associated with capture, com-pression, transport and injection for storage or enhancedoil recovery are most often included. From a CO2 account-ing perspective, both the direct and indirect CO2 emissionsare important,11 as well as the estimated leakage from sto-rage (see e.g., Ha-Duong and Keith, 2003). Implicit to theobservation that there are additional CO2 emissions associ-ated with all concepts, the ‘CO2 avoided’ i.e., both thedirect and indirect CO2 emissions from a reference plant(without capture) less CO2 emissions from a given plantwith capture is often used in the literature. A discussionof methodological issues for calculating CO2 costs can befound in Melien (2005).

NEAR TERM IMPLEMENTATION OF CO2 CAPTUREFROM POWER PRODUCTION

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-scaleCO2 capture (and storage) from power production. Theseare 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 inthe Netherlands: BP and partners, Royal Dutch/Shell,

Figure 3. Main research directions for CCS.

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



ConocoPhillips and Scottish & Southern Energy PLC haveannounced plans for a large-scale CO2 capture and storageproject, envisioned to come on-stream in 2009 (http://www.bp.com). The chosen route is the production of

hydrogen from natural gas. The hydrogen will fuel 350MW from Scotland’s Peterhead power station while 1.3million tonnes of captured CO2 will be transported by anexisting pipeline and injected for enhanced oil recovery and

Table 2. Selection of international projects on CSS.

ProjectTotal project

funding (Million) Focus areas Timeframe Capture/storage

CANMET Energy TechnologyCentre (CETC)

R&D Oxyfuel Combustion forCO2

1994– Capture

SACS 4.5 million US Storage in Saline Aquifers:Sleipner Case

1997–2002 Storage

GESTCO 3.76 Million CO2 storage potential in Europe 1999–2002ICBM Unknown Enhanced Coal Bed Methane, coal

fields in Europe2000–2003 CO2 storage in coal

seamsGEODISC 10 million Aust Dollars Storage 1999–2002CCP 1 (http://

www.co2captureproject.com/index.htm)

28 million Dollars Entire CCS value chain Economiccomparisons of alternatives

2000–2005 CCS

RECOPOL 3.5 million Enhanced Coal Bed Methane inPoland

2001–2004 A field injection trialof CO2 into a coalseam in Poland

US DOE Carbon SequestrationProgram

30 million US per year CCS 2001–2020 CCS

NGCAS 0.6 million CO2 storage 2002–2005 CO2 storage in anoffshore depletedoil field

NASCENT 3.3 million Natural analogues in Europe forCO2 storage

2001–2004 Studying naturalaccumulations ofCO2 in geologicalformations

NACS 1.5 millionCRUST 12 million Demonstration of CO2 storage in

depleted hydrocarbon reservoirs2002–2005 CO2 storage

CCP 2 (http://www.co2captureproject.com/index.htm)

Continue the development of newtechnologies to reduce the costof CO2 separation, capture, andgeologic storage

2005–2007 CCS

EU CASTOR (http://www.co2-castor.com)

15.8 million Novel solvents, ContactingMembranes, Advanced ProcessDevelopment, 1 t/h CO2

capture Pilot plant at Esbjerg

2004–2008 CCS

CO2sink 8.7 million Ketzin CO2 injection project 2004–2009 StorageEU CO2GEONET 6 million Network of excellence 2004–2009 StorageCO2STORE (Norway and

European Commission)2.5 million Follow-up to the Sleipner project,

monitoring to track CO2

migration, focus ongeochemistry and dissolutionprocesses

2003–2006 Storage

EU ISCC 2.9 million CO2 capture using solid sorbents 2004–2007 CaptureENCAP (http://

www.encapco2.org/)22.2 million Precombustion CO2 capture 2004–2009 Capture

EU HYPOGEN, Dynamis 2006–2015 CaptureUS DOE FutureGen 1 billion US 2002–2012 CO2 capture from

coal and storageARC Enhanced Coal-Bed

Methane Recovery Project(Canada, United States andUnited Kingdom)

3.4 million Canadian $ CO2 injection into deep coal beds Storage

Frio Project (United States andAustralia)

Demonstrate CO2 sequestration inan on-shore underground salineformation

Storage

ITC CO2 Capture with ChemicalSolvents (Canada and UnitedStates)

Demonstrate CO2 capture usingchemical solvents

Storage

IEA GHG Weyburn CO2

Monitoring and StorageProject, Research projectWeyburn II CO2 StorageProject (United States,Canada, and Japan)

27 million USD CO2 for enhanced oil recovery Storage



deep geological storage in the Miller Field.13 Vattenfall ofSweden (http://www.vattenfall.com) has announced plansto build a 30 MWth lignite-based plant using oxyfuel techno-logy. The pilot plant is expected to come on-stream in 2008and will provide the design basis for scale-up of the tech-nology to 600 MWe. Although a solution for the CO2 hasnot been made known, oxyfuel boiler technology allows therecovery of high concentration CO2 Clean Energy Systems(CES) (http://www.cleanenergysystems.com) and SEQNederland, B. V. have entered into an agreement for engin-eering services for a 50 MW power plant to be built in theNetherlands, where the carbon dioxide captured from theplant will be used for enhanced gas recovery. By avoidingharmful atmospheric emissions, the proposed project couldqualify for governmental support as a ‘climate neutral com-bustion technology’, under current Dutch law (see footnote 6).

THE CONTENDING TECHNOLOGIES:POST-COMBUSTION CO2 CAPTURE

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

CmHn þF mþn

4

� �(O2 þ 3:77N2)

�! mCO2 þn

2H2Oþ (F� 1) mþ

n

4

� �O2

þF mþn

4

� �3:77N2 (1)

The large amounts of excess air required for combustioncontrol in current boiler and gas turbine technology resultin a dilute CO2 stream that also has significant oxygencontent. Chemical absorption processes employ the reversiblenature of the reaction of an aqueous alkali solvent with anacid gas. MEA (monoethanolamine), MDEA (methyldietha-nolamine) and DEA (diethanolamine) are currently themain chemical solvents of interest for acid gas treatment.The process technology for acid gas removal from naturalgas was developed during the 1920s (Herzog, 1999). ForMEA, the fundamental reaction for the process is:

C2H4OHNH2þH2OþCO2 �!C2H4OHNH3þHCO3

The reaction proceeds to the right at low temperature25–1008C allowing absorption from the gas stream. Thesolvent can be regenerated, and the CO2 recovered as aconcentrated stream, by heating the solvent solution intothe temperature range of 100–1508C to reverse the absorp-tion chemistry (Aboudheir et al., 2003). The economicamount of CO2 removal for post-combustion is between80% and 95% CO2. Kvamsdal et al. (2005b) found thatthere was an efficiency gain in lowering the CO2 capturefrom 90% to 75%, but found a sharp increase in capitalcosts for 95% capture. There are three main technology sup-pliers (see Table 3). From the process flow diagram shownin Figure 5, incoming gas is cooled, and enters the CO2

absorber where CO2 is taken up by the solvent at tempera-tures typically between 40 and 808C. The top section of thecolumn is used as a water wash to prevent solvent carry-overand to correct the water balance. The rich solvent is pumpedto the top of the stripper where the solvent is regenerated atabout 100–1408C, at around 60 kPa (g) (Barchas and Davis,1992; Roberts et al., 2004).

While many of the constituent elements of the aminescrubbing process consists of widely-known technology,the development of inhibitors and their application to

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

12CCP: CO2 Capture Project: Carbon Capture Project, see http://www.co2captureproject.org.13Injecting the carbon dioxide into the Miller Field reservoir more thanthree kilometres under the seabed could extend the life of the field byabout 20 years and enable additional production of about 40 million barrelsof oil that are not currently recoverable.



cost-effectively prevent degradation and corrosion is akey area of technology know-how. Apart from the concernsfor the purity of the CO2 at the point of use, the impuritiesin the flue gas are also important for the overalldesign and cost of the CO2 removal plant (Herzog et al.,1991). The relatively high oxygen content of flue gasrepresents a particular challenge for amine absorption dueto degradation of amine by the oxygen. Solutions ofMEA that are partly degraded are aggressive at highconcentrations, causing high rates of corrosion, degradationof column internals and other elements (includingfilters) and reaction with other components in the gas.Flue gas from combustion will usually contain acidiccomponents NO2 and SOx, hydrogen sulfide (H2S),HCl, arsenic, and mercury. MEA removes nearly all ofthe 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 acidiccomponents react with the amine to form stable salts thatreduce the absorption capacity, accumulate in the solutionand cannot be regenerated by heating in the stripper. Thisrepresents a loss of solvent from the system and increasesthe solution viscosity undesirably. The elimination of heatstable salts results in operating costs for reclaiming thesolvent and for handling the waste stream of sulphate andnitrate salts. MEA is typically recovered from the heat

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

Abb Lummus Kerr McGee Fluor (Econamine FG Plus)Mitsubishi Heavy Industries/

KEPCO (KS-1 Process)

Solvent used 15–20 wt% aqueous MEA (Mono-ethanolamine)þ inhibitor

30 wt% aqueous solutionMEA

KS-1

Solvent Replacement Cost(USD/tonne CO2)

2.3 2.28

Source of CO2 Coal Natural gas Natural gasCommercial experience The largest capacity delivered is

800 tonnes/day of CO2 utilizingtwo parallel trains

Many plants worldwiderecovering up to 330tonnes/day of CO2 in asingle train for use inbeverage and ureaproduction

First commercial plant at 200tonnes/day CO2 recoveryfrom a flue gas stream hasbeen operating in Malaysiasince 1999 for ureaproduction

Figure 5. Typical flowsheet for CO2 capture using MEA.

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



stable salts through reaction with soda ash (Reddy et al.,2003; Kvamsdal et al., 2005b). In addition to the solventdegradation, other gaseous components also affect the driv-ing force for CO2 absorption, an effect that becomes morepronounced at elevated pressures (De Koeijer and Solbraa,2004). The limits on SO2 and NO2 concentration in the fluegas being treated for CO2 removal by MEA absorption arerecommended 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 noteliminated, but simply reduced to an acceptable rate(Heggum et al., 2005). Fly ash and soot removal is alsoimportant to prevent both foaming in the absorber andfurther reactions with the solvent.Post combustion treatment is costly and energy-intensive

because of the large volume of gas to be treated, the lowpartial pressure of CO2 in the flue gas, the presence of con-taminants that may be detrimental to the solvent and theenergy demand associated with solvent regeneration.MEA has a high heat of absorption (which needs to be sup-plied in the regeneration step), the absorption of CO2 ismodest and concentrations much greater than 20–30%result in corrosion problems. The energy requirements forpost-combustion CO2 capture are summarized in Table 4.Extraction of LP steam from the steam turbine, instead ofincreasing the fuel demand gives 2–3% gain in fuel effi-ciency (Bolland and Undrum, 2003; Kvamsdal et al.,2005b). Compression of CO2 to export pressure and theregeneration heat for the amine solution are the largest con-sumers of energy. In addition to increased fuel costs, oper-ating costs for post combustion plants are incurred byreplacing consumed solvent (0.2–1.6 kg/CO2 tonne) andthe use of chemicals for the removal of decomposition pro-ducts (e.g., 0.03–0.13 kg NaOH, 0.03–0.06 kg activatedcarbon/tonne CO2) (IPCC, 2005). Improvements thathave already been identified could potentially reduce theenergy requirements for post-combustion capture from theresearch efforts aimed at overcoming the weaknesses ofthe predominant approaches for post-combustion CO2

removal are outlined in Figure 6.

IMPROVED ABSORPTION

An overview of existing solvents is given in Table 4.Sterically hindered amines have more favourable reactionstoichiometry, such that the theoretical capacity is higherthan MEA, and lower heat of absorption/regeneration.Examples of sterically hindered amines are 2-amin-2-methyl-1-propanol (AMP), and the proprietary solventsmarketed by Mitsubishi Heavy Industries, KS-1, KS-2and KS-3 (White et al., 2003). A large research effort isbeing directed at improved solvents to improve the CO2

loading, reduce the energy requirement for solvent circula-tion and regeneration and to overcome solvent degradation(Chakma, 1995; Chakma and Tontiwachwuthikul, 1999;Mimura et al., 1999; Zheng et al., 2003; Cullinane andRochelle, 2003; Leites, 1998; Erga et al., 1995; Arestaand Dibenedetto, 2003; Bai and Yeh, 1997; Chakravartiet al., 2001; Mimura et al., 1995; Mimura et al., 2003).Improving the activated potassium carbonate process hasbeen investigated using piperazine (e.g., Cullinane andRochelle, 2003; Bishnoi and Rochelle, 2002). There is evi-dence that the capture process efficiency can be substan-tially improved by careful design of a mixture of solvents(Melien, 2005; White et al., 2003). While current suppliersof technology, ABB Lummus, Fluor and Mitsubishi/Kansai Electric Power Company (KEPCO) are pursuingresearch on improved solvents, there is ongoing researcharound the world including at the Tokyo Electric PowerCompany, TNO,15 in the Netherlands and at Praxair,Table 5 gives an overview of some of the amine-basedsolvents under development.

Even though improved amines, e.g., can save regenerationoperating costs, they may have slower reaction kinetics andthus require longer gas–liquid contact time in the absorber.The design of improved contacting equipment that addition-ally overcomes the known operational problems with packedcolumns (flooding, channelling, entrainment and foaming) isthus another area where improvements are needed. Improved

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

Natural Gas DerivedFlue Gas (GJ/tonne CO2)

Coal Derived Flue Gas(GJ/tonne CO2) Comment

Fuel Efficiency without CO2

capture58% (Combined Cycle,

0.04 bar condenserpressure 400 MW)

45% (PulverizedBituminous Coal 600 MW)

Captured CO2 Compressionto 100 bar (g)

0.4 0.4 Specific power consumption willdecrease with decreasingpressure ratio

Blower (overcome pressuredrop in absorber)

0.1–0.34 0.04–0.1 Average MW of coal-derived fluegas is higher (values fromBolland and Undrum, 2003)

Pumps 0.21–0.33 0.06–0.11 Lower circulating vol requiredfor higher concentration CO2

in flue gas (values from IPCC,2005; pg 117)

Sub Total Power Power: 0.71–1.07 Power: 0.51–0.61Regeneration Heat

(Equivalent Power)2.7–3.3 (0.62–0.76) 2.7–3.3 (0.62–0.76) Equivalent power from LP steam

extraction (from Bolland andUndrum, 2003)

Fuel Efficiency (%) with CO2

capture�47–50% �34–36%

15TNO is a contract research and specialist consultancy with its corporatecentre in Delft, The Netherlands, see http://www.tno.nl.



packing, (e.g., Aroonwilas et al., 2003; Kvamsdal et al.,2005b) and the use of contacting membranes (e.g., SøybeGrønvold et al., 2005; Feron and Jansen, 2002; Feron,1992, 1994; Falk-Pedersen et al., 1999) has been investi-gated. DeMontigny et al. (2005) found significantly highermass transfer coefficients for polymeric contactors ascompared to structured packing. While membrane systemspotentially have a smaller footprint and lower weight thanconventional systems (Herzog and Falk-Pedersen, 2001),their modular nature implies that economy-of-scale benefitsfor very large scale CO2 capture plants are likely to be verymodest or non-existent. The combination of chemicalabsorption and selective membranes has also beensuggested, so as to perform absorption and desorption in asingle unit, see Mano et al. (2003) and Okabe et al.(2003). The combination of polymeric microporous mem-branes and DEA has been investigated by Bao andTrachtenberg (2005). The use of the carbonic anhydrase tocatalyse and accelerate CO2 absorption and desorptionforms the basis of the start-up company Carbozyme Inc.16

Other avenues that have been investigated are increasedconcentration of solvent (Aboudheir et al., 2003), so as toreduce circulation rates and thus energy requirements forregeneration, removal of oxygen, so as to enable the useof solvents that are intolerant of oxygen (Nsakala et al.,2003). Ammonia has been proposed as an alternative toamines and can be employed to capture all three majoracid gases (SO2, NOx, CO2) in addition to any Hg, HCland 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 givenlimits, a single process to capture all acidic and toxic gasesis expected to reduce the total cost and complexity of emis-sion control systems. Unlike the MEA process, ammonia isnot expected to have absorbent degradation problems thatare caused by sulphur dioxide and oxygen in flue gas, isnot expected to cause equipment corrosion and couldpotentially reduce the energy requirements for CO2 capture.Recently, Powerspan Corp.,17 reported the application ofammonia for simultaneous reduction of SO2, NOx andmercury and announced the start-up of a pilot plant fortesting the novel emission control concept that includesCO2 removal in 2006. In addition to the absorptionprocesses using ammonia as a regenerative solvent, CO2 cap-ture for the production of fertilizer has also been investigated.

Split flow, where a portion of the side draw from theabsorber is fed to the stripper, bringing the operating lineof the absorber parallel to the equilibrium line and soimproving the thermodynamic efficiency (and thus lowerreboiler duty) of the absorber has been suggested (Reddyet al., 2003). Kvamsdal et al. (2005b) found that at lowCO2 loading and the correspondingly low regeneration temp-erature, a split flow regime gives no appreciable decrease inreboiler duty solid sorbents for CO2 have also been investi-gated (Abanades et al., 2004; Green et al., 2002).

The purity of CO2 from post-combustion capture is typi-cally 99.9% (vol.) (Sander and Mariz, 1992). However,CO2 derived from combustion gases may contain sulphuroxides, nitrogen oxides, several different low molecularweight hydrocarbons, carbon monoxide, and mercury.The concentrations of these impurities may vary greatlyin individual processes; also, the variety of possible CO2

sources is responsible for a large number of potentialimpurities in the produced CO2.

POWER BLOCK/CAPTURE INTEGRATION

Energy requirements can be reduced by pursuingenergy integration between the CO2 capture plant and thepower plant. The recirculation of flue gas is the most

Figure 6. Post-combustion research directions.

Table 5. CO2 solvents under development.

Absorbent Licensor Absorbent

Fluor-Daniel Ecoamine MEAþ additivesABB Lummus-Global MEAMitsubishi KS-1, KS3TNO (future) CORALUniversity of Regina PSRPraxair Amine BlendsCANSOLVw CANSOLVw

16http://www.carbozyme.us/. 17http://www.powerspancorp.com.



studied integration option (Bolland and Sæther, 1992).Combinations of the aforementioned measures have alsobeen evaluated: For example Mimura et al. (1997) haveinvestigated the combination of new solvent technologyand integration of the steam requirements for the CO2 strip-per with the power plant, and found that the energy penaltyfor CO2 capture and compression can potentially be low-ered to 10–11% for natural gas and 15% for conventionalcoal. Chinn et al. (2004) proposed engineering options forreducing the costs of amine-based CO2-capture from theflue gas of a 400 MW natural gas combined cycle power,potentially bringing the costs of CO2 capture to around35 USD/tonne. These potential improvements includeddepressurization of the lean solvent and vapour compres-sion; elimination of contact coolers before the absorber,the use of structured packing, direct integration of thestripper and Heat Recovery Steam Generator and recycleof a portion of the flue gas to increase the CO2 feedconcentration to the absorber.It has been argued that post combustion CO2 capture

affords power producers greater operational flexibility torespond to short term market signals than those alternativesthat require integration between the power block and thecapture plant (e.g., Gibbins et al., 2005). This may be valu-able in terms of fluctuations in both the prices of CO2 quotaand electricity and in overcoming the barrier that potentialmismatches in timing between the life of power plants andCO2 required for enhanced oil recovery may present. Typi-cally, operational flexibility comes at a cost (e.g., increasedcapital cost) that must be weighed against the uncertainvalue of the future benefits.

NEW TURBINE CYCLES

Applying new turbine cycles to produce flue gas withhigher CO2 content may avoid some of the challenges forpost-combustion CO2 capture. For example, the Combicapconcept (Lynghjem et al., 2004) comprises two gas turbinesthat are interconnected by a CO2 separation system and anintegrated combustor-heat exchange system (see Figure 7).Combicap aims at producing a flue gas stream with a higherCO2 partial pressure. By recirculating the flue gas streamfrom the main gas turbine, a novel semi-closed top cycleis proposed employing a working fluid of mostly N2

(approximately 85%) and CO2 (approximately 10%). TheCO2 concentration is limited by the oxygen required inthe combustor for complete combustion. Gas exiting theCO2 removal unit needs to be heated up to the hot gastemperature of the helper gas turbine unit. This requiredheat may be provided by heat exchange, without addingCO2 to the gas, or by supplementary firing that will leadto some additional CO2 in the exhaust gases if naturalgas is burned. Increasing the CO2 partial pressure (.1.5bar), potentially lowers the cost of CO2 capture by, e.g.,polymer membrane systems. The use of novel, fixed sitecarrier membranes where an amine group and othercross-linking agents (e.g., Fl) are incorporated into thestructure of a polymer membrane for CO2 capture fromflue gases has been investigated. (e.g., Hagg and Lind-brathen, 2005). The Combicap concept exhibits relativelyhigh overall fuel efficiency (approximately 50%) dueto the high temperature at the turbine inlet and has lowformation of NOx since the combustor receives both fresh

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



air and recycled flue gas. The advantages of the increasedCO2 partial pressure and modest temperature for CO2

separation are partially offset by the increased complexityand higher degree of integration of the process.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 cycleuses a high pressure ratio gas turbine, composed of ahigh pressure inter-cooled shaft and a low pressure powershaft. The high pressure air from the compressor iscooled and then humidified in an air saturator. The humidi-fied air is heated in a heat recovery section that uses theturbine exhaust before entering the turbine combustor.Arguments for HAT cycles are that the added cost of amore expensive gas turbine, the air saturator and theincreased number of heat exchangers is offset by eliminationof 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 maintainthermal conditions in the combustion zone and preventoverheating of the furnace liner materials, some of theflue gas would be recycled to the furnace. Using oxygeninstead of air opens up new possibilities for increased com-bustion efficiencies. Trace impurities exit with the CO2

stream and where these can be stored with the CO2 couldresult in overall lower emissions abatement costs. The oxy-fuel pathway to CO2 capture and storage is discussed in thefollowing section.

THE CONTENDING TECHNOLOGIES: OXYFUELALTERNATIVES FOR CO2 CAPTURE

Since nitrogen is the highest concentration component inthe flue gas from power stations, removal of nitrogen inoxyfuel processes (also called pre-combustion denitrogena-tion) simplifies downstream CO2 separation. One of the ear-liest investigations of oxyfuel CO2 capture was by Holt andLindeberg (1988), who suggest oxygen firing instead of airand recirculation of CO2 and H2O as the working fluid ina partially closed turbine cycle. Air separation precedescombustion so that the combustion products are chieflyCO2, and water with small amounts of other acid gases(e.g., SOx, NOx), possible impurities such as HCl and Hgderived from the fuel used, and inert gas components, suchas nitrogen, argon and oxygen either derived from the

oxygen feed, the fuel stream or air leakage into thesystem. Oxyfuel concepts for both natural gas and coal feed-stock have been proposed Croiset and Thambimuthu (2000)and Tan et al. (2002), and holds potential for more efficientNOx, SO2, particulate, trace element and moisture removalsince the gas volume that has to be treated for flue gas puri-fication is much reduced. Another challenge for the oxyfuelroute is the relatively low purity CO2 produced. The researchdirections for oxyfuel technology are given in Figure 8.

Combustion temperatures in oxyfuel processes are con-trolled by recycling a portion of the flue gas, steam orwater back to the combustion chamber. Because of thehigher heat capacity of carbon dioxide a reduced inertgas/O2 ratio is typically required (approaching 2.5 : 1instead of 4 : 1 for air) (Chatel-Pelage et al., 2003; Tanet al., 2002). The net flue gas, after cooling to condensethe water vapour, contains 80–98% CO2 depending onthe 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 approxi-mately 4 g/kWh) will not be recovered from oxyfuel cyclesusing water condensers. The advantages of oxyfuel can beoffset by the cost of O2/N2 separation, the high oxygendemand and the efficiency penalty incurred by flue gasrecirculation. For oxyfuel boilers air leakage into thesystem undermines the extra capital and power associatedwith high purity oxygen and lowering the oxygen purityfrom 99.5% to 95% will significantly reduce the power con-sumption. While the amount of excess air (largely deter-mined by variations in air/fuel distribution betweenburners in multi-burner installations) of 15–20% excessair is normally required in pulverized coal combustion boi-lers to ensure adequate burnout, 10–20% excess oxygen isrequired for oxyfuel boilers. With significant air in-leakage,inert gas removal to achieve the desired CO2 purity isrequired. In general, fuel efficiency decreases with increas-ing oxygen and CO2 purity.

A promising potential application of oxyfuel technologythat has been reported (Wilkinson et al., 2003b) is the retro-fit of power plant boilers and a range of refinery heaters inthe Grangemouth refinery complex in Scotland. The con-version of gas and oil fired heaters to an oxy-fuel boilerrequired minor burner modifications (a new O2 injectionsystem and a new flue gas recycle line with a separate

Figure 8. Oxyfuel research directions.



blower) that could potentially yield increased boiler ther-mal 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 concen-tration in the flue gas in the Grangemouth case increased to60%. Impurities (SOx, NOx) and gases (excess O2, N2,Argon) representing about 10% of the stream are separatedfrom CO2 at low temperature (2558C). After cooling,compression and drying of the separated or non-recycledflue gas, the product for sequestration comprises 96%CO2.

18 Production of ultra-pure CO2 for storage would bepossible by adding distillation steps to the separation pro-cess. Theoretical studies have concentrated on the retrofitoption, however, there are advantages in applying oxyfueltechnology to modern ultra-supercritical boilers since theirincreased efficiency reduces the oxygen demand per unitof generated electricity and therefore the cost end efficiencypenalty of O2/CO2 recycle combustion.

OXYFUEL TURBINE CYCLES

The AZEP concept (Sundnes, 1998; Sundkvist, 2005;Griffin et al., 2003), involves the integration of a ceramicmembrane in the combustor. The ceramic membraneallows transport of oxygen and heat, such that the combus-tion products, chiefly CO2 and H2O are expanded in oneturbine, while the heated oxygen-depleted air drives themain combined cycle gas turbine. The optimum operatingwindow for the membrane is such that the turbine inlettemperature is lower than most of the advanced gas tur-bines, resulting in lower efficiencies.19

Several novel turbine cycles using water, CO2 or a mix-ture of H2O/CO2 as the working fluid have been proposedin the literature (e.g., Mathieu, 2003). Table 6 contains abroad comparison of the main oxyfuel cycles. The CleanEnergy Systems (CES) process is a variant of the water-cycle (H2O recycle) and the Graz cycles (77% H2O and23% CO2 recycle). A combustor is fired with a mixtureof recycled high pressure water/steam, fresh oxygen andnatural gas or synthesis gas. The combustion is performedat essentially stoichiometric conditions to produce steamand CO2 at high temperature and pressure that powers a tur-bine. The turbine exhaust is used for water/steam heatingand is reheated to above 13708C by combustion ofadditional gas. The remaining turbine sections may haveintermediate feed water heaters before the exhaust stream(approximately 90% H2O, 10% CO2) enters a partial con-denser and then a condenser/CO2 recovery section. CEScommissioned a 20 MWth gas generator at the Kimberlinapower plant, California in May 2005. Considerable effortwill be required to further develop the gas generator andthe ultra high pressure/temperature turbines required fora full-scale commercial process.The Graz-cycle consists of a high pressure (40 bara)

combustor, which is fed with natural gas, oxygen, CO2 andsteam. The combustor exit stream, at 13288C, is expandedin a high pressure turbine. The turbine exit stream iscooled in a heat recovery steam generator (HRSG), wherehigh-pressure steam is produced (174 bar, 5608C) and then

expanded to 40 bar in a steam turbine. The hot gas fromthe HRSG is further expanded in a low pressure turbinebefore being finally cooled in a condenser. The condensedwater and CO2 are separated in the condenser. The CO2

stream is compressed (with intercooling) before it is mixedinto the combustor, as an inert gas for the control of the com-bustor exit temperature. The water collected from the con-denser 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 isremoved from the cycle (Jericha et al., 2003).

In addition to the lowering the overall fuel efficiency,recirculation of a H2O/CO2 cooling/mixing mediumrequires the development of turbo-machinery capable ofusing CO2/H2O mixtures as the working fluid at high temp-eratures and pressures. The practical design of condensersfor good heat recovery from the working fluid (with rela-tively high concentration of non-condensable gases) isanother important challenge. The development of gas tur-bines capable of operating with very high temperatureswill 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

Chemical Looping combustion, proposed by Richter andKnoche in 1983, divides combustion into intermediateoxidation and reduction reactions that are performedseparately with a solid oxygen carrier circulating betweenthe separated sections. Oxides of iron, copper, chrome,manganese and nickel have been investigated (Lyngfeltet 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 componentsof a chemical looping process are: solid oxygen carriers;a chemical looping system; fuel and air supplies; heatutilization/recovery and CO2 capture. Although there arevarious ways to perform CLC, a fluidized-bed combustionsystem has some advantages over other alternatives, e.g.,good heat transfer and effective transport of the solidoxygen carriers between the two reactors. At the presentstage of development, the mechanical stability and chemi-cal reactivity over many cycles are the main developmentissues for this process.

OXYGEN MEMBRANES

Conventional methods of oxygen production, i.e., cryo-genic separation (99.99% O2) and vacuum pressure swingadsportion (90–94% O2) consume about 200 kWh/tonneO2. The largest single train air separation unit can produceapproximately 3500 tons per day (TPD) of oxygen, a quan-tity sufficient to support an oxy-fuel power plant havingroughly 200 MWe output. Larger single train units(.5000 TPD) seem possible and to offer some modestimprovement in economy-of-scale. (Wilkinson et al.,2003a). A less energy intensive (and thus potentially morecost effective) alternative that has been pursued is the useof oxygen transport membranes to produce pure oxygenfrom air (e.g. Asen, 2001). Three different alliances—leadby Air Products (e.g., Carolan et al., 2001), Praxair andthe AZEP alliance (Griffin et al., 2003) have been working

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



on the development of oxygen transport membranes. Theadvanced zero emission power concept (AZEP) entails theintegration of an oxygen conducting membrane withconventional power turbines (Sundkvist et al., 2005;Moller et al., 2005). Robinson et al. (2004) report thattheoretical studies show that the incorporation of anoxygen transport membrane into steam methane reformingimproves hydrogen yield and lowers CO2 and NOx

emissions. These dense membranes consist of complexcrystalline structures, allowing oxygen ions to diffuse inthe direction of decreasing oxygen partial pressure givenan adequate electronic conductivity that allows the countermigration of electrons.20 At low temperatures, the ionic con-ductivity of the ceramic material is often too low so that thetransport process requires high temperatures, i.e., .7008C,making it attractive to combine these membranes withexothermic processes/reactions (Skinner and Kilner, 2003;Bouwmeester and Van Der Haar, 2002; Dyer et al., 2000;Bredesen et al., 2004). In addition to achieving adequateoxygen flux, mechanical and compositional stability overrepeated thermal and oxygen concentration cycles,preventing fouling/coking, achieving a high surface area/volume design and module fabrication for large-scale appli-cations are very serious development and commercializationchallenges for these types of membranes.

THE CONTENDING TECHNOLOGIES:PRE-COMBUSTION CO2 CAPTURE

The pre-combustion route is premised on the productionof synthesis gas, CO2 removal and combustion of hydro-gen. Hydrogen is produced from a variety of feedstockincluding natural gas, naphtha, heavy oils or coal in pro-cesses that convert the hydrocarbon source into synthesisgas. The production of synthesis gas comprises the reform-ing, partial oxidation and water gas shift reactions:

CxHy þ X H2O, xCOþ (xþ y=2) H2

CxHy þ x=2O2, xCOþ y=2H2

COþ H2O,CO2 þ H2

Different synthesis gas technologies have differentapproaches to the supply/removal of the heat of reactionand for the supply of oxygen and steam, implying differentways of combining or coupling the reforming and partialoxidation reactions. The shift reactions convert the CO toCO2 and increase the hydrogen yield. For coal and heavyoils various forms of gasification form the main synthesisgas production technology. Pre-combustion CO2 capturebased on coal is termed integrated gasification combinedcycle (IGCC). The two predominant synthesis gas technol-ogies from natural gas are steam methane reforming (SMR)and autothermal reforming (ATR). SMR introduced in the1930s is by far the most common process. The currentupper limit for the capacity of single trains SMR plants isaround 480 tonnes/day hydrogen, and hydrogen is recov-ered at high pressure using pressure swing absorption. ASMR unit consists of Ni-alloy tubes filled with catalyst,which are heated externally by burners. The ATR is alarge refractory-lined vessel with a burner and catalyst

Table 6. Comparison of the main oxyfuel alternatives.

Main feature Technology developer(s) Working fluid

Cycleefficiency (from

Kvamsdal et al., 2005a)

Technicaldevelopmentchallenges

AZEP Mixed ConductingMembranes for O2/N2

separation integratedwith Combustor andGas Turbine; Large-scale (.45 MW) muchlonger term

Consortium: Norsk HydroAlstom, Siemens,Borsig, Ulster Univ, PSI,Lund Technical Univ,Areva

Air 51 Membrane (O2 Flux,Mechanical Strengthand Stability, Scale-up), Ceramic Sealingat High Temperature,High TemperatureHeat Exchange,Combustor DesignTurbine integrationwith reactor

Graz 3 Turbines (2 High, 1Low Pressure), SteamCycle, Recycle of CO2and steam

Prof Jericha from TechnicalUniveristy of Graz

77% H2O,23% CO2

43 Integrated Steam/GasTurbine Non-Condensable gases inCondenser

Water 2 Turbines (High andLow Pressure), Twocombustors, Recycleof Heated Water

Clean EnergySystems (CES)

90% H2O,10% CO2@ 808C

44 Integrated Steam/GasTurbine Non-Condensable gases inCondenser

Chemicalloopingcombustion

Combustion occurs inreducing atmosphere(oxygen present asmetal oxide) Circulatemetal oxide betweencombustion andoxidizing sections/reactors

Consortium in CCP: BP,Alstom Boilers,Chalmers University,CSIC (Spain), ENI

Air as fluidizingmedium

51 Metal Attrition Fine Dustto Turbine Turbineintegration with reactor

20Oxygen separation occurs as O2 molecules diffuse to the membrane sur-face, followed by dissociation into oxide ions, ions are transported throughthe membrane by sequentially occupying the oxygen ion vacancies andrecombine on the other side of the membrane, liberating electrons. Theion transport is counterbalanced by a flow of electrons in the oppositedirection. The driving force is the difference in the oxygen partial pressurebetween the permeate and retentate sides of the membrane. Since the trans-port mechanism is based on ion transport and not molecular sieving, theselectivity of the membranes is infinite as long as there are no cracks orother surface imperfections.



bed. The partial combustion of natural gas with oxygen andsteam occurs in the burner, and the reactants equilibrate inthe catalyst bed to form synthesis gas. The addition ofsteam is required to prevent coking and and sootformation (Wilkinson and Clarke, 2002).The production of hydrogen from fossil fuels is energy

intensive, and about 20–25% of the energy is irreversiblydissipated during the conversion (see Corradetti andDesideri, 2004; Ertesvag et al., 2005). Typically the pro-duct stream from the shift reactors has a CO2 concentrationof CO2 in the range 15–60% (dry basis) and the totalpressure is typically 2–7 MPa, which enables more effi-cient CO2 separation (by e.g., amine absorption or physicalabsorbents like Selexol). Using amine absorption to recoverthe CO2 followed by a PSA (Sircar and Golden, 2001) unitfor hydrogen recovery, the efficiency penalty for the CO2

capture unit in a natural gas fired large SMR plant isaround 3% at 88% capture (IEA GHG, 1996). CO2 captureis already commonly used in the production of ammoniaand urea. The main research directions for pre-combustionCO2 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 tothe cost of the air separation unit, the compression of airand oxygen requires substantial power, comprising the largestparasitic load on a reformer or integrated gasification facility.The integration between the reforming and turbine units canimprove thermal efficiencies: For example, air extractedfrom the gas turbine air compressor can be mixed with theproducts from the pre-reformer and preheated against exhaustgas before entering the reformer and steam generated from thewaste heat from reforming is used in the steam turbine. ForIGCC units, the high partial pressure of the CO2 allows theuse of physical solvents (e.g., Selexol). Cryogenic separation(e.g., Fluor’s CO2LDSep

w) is another alternative. The para-sitic load from air separation can be reduced by extracting aportion of the air from the compressor of the gas turbine tofeed the air separation unit. However, because of reliabilityproblems associated with 100% integration found at severaldemonstration IGCC facilities, current industry thinking inthe US is that about 50% integration is the recommendedmaximum (Rosenberg et al., 2005).For air-blown systems, the introduction of nitrogen mark-

edly 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 higherCO2 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.

INTEGRATED GASIFICATION COMBINEDCYCLE (IGCC)

Worldwide there are more than 400 gasifiers in operationthat do not generate electricity, but produce synthesis gas andvarious other by-products of high rank coal and residual oilgasification. In these facilities, CO2 is separated after thegasification stage. CO2 capture costs for IGCC plants areamong the lowest reported, see Table 7. The synthesis gasor 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 novelshift reactor and IGCC concept. There are a number ofgasification technology suppliers, among them GeneralElectric (acquired from ChevronTexaco), Shell, FosterWheeler, E-GAS (ConocoPhillips and Fluor alliance) andMitsubishi Heavy Industries (McDaniel and Hornick,2002). A comparison of gasification technologies can befound in Zheng and Furinsky (2005) and Rosenberg et al.(2005). Despite the worldwide commercial use and accep-tance of gasification processes and combined cycle powersystems, the integration of a coal gasification with acombined cycle power block to produce electricity as aprimary output is relatively new, and has been demonstratedat only a handful of facilities around the world (see Table 8for an overview). The commercial gasification processesbelieved most suited for near-term IGCC applicationsusing coal or petroleum coke feedstock are the GeneralElectric, ConocoPhillips, and Shell entrained-flow gasifiers.Each of these technologies is currently deployed at anoperating commercial IGCC facility (see Table 8).

HYDROGEN TURBINE

The hydrogen turbine is the unit that is common for allpre-combustion technologies for all fuels. Pure hydrogenpresents several complex challenges for flame stability dueto its very high flame speed when premixed, and its high

Figure 9. Pre-combustion research directions.



temperatures when non-premixed. The high flame tempera-tures resulting from hydrogen combustion are attenuated bythe addition of nitrogen and/or steam. General Electric’s(GE) IGCC group has utilized fuels with H2 contentsbetween 8% and 62% and fuels having up to 95% H2 havebeen used in GE turbines in process plants. General Electricreports having completed feasibility testing for 100%H2 fuelto define the entire combustion map that shows that ratios of50/50 H2/N2 can produce very low NOx as well as provideenhanced output in a modern IGCC gas turbine. The rate ofNOx generation varies exponentially with flame temperatureand linearly with the amount of time that the gases areexposed to the flame zone. NOx emissions can be reducedeither with a conventional, diffusion-based combustor withnitrogen and/or steam dilution, or with a dry low emissions(DLE) premixed combustion system.At present, only dilution based on diffusion is commer-

cially available for hydrogen-rich combustion and increasesin hydrogen content increase the required amount of dilutiongases. Although steam is the more effective of the two dilu-ents, steam dilution results in higher metal temperatures of

the hot-gas components that can reduce equipment lifetimesif firing temperatures—and thereby also engine efficiency—are not reduced. Moreover, steam extraction has a directnegative impact on the energy efficiency of a combinedcycle. So, nitrogen is generally preferred over steam fordilution, but for high hydrogen content, the large volumetricflow to the combustor presents a design challenge.

Modifications to the combustors and fuel mixing systemare the principal requirements when converting a naturalgas turbine to burn hydrogen-rich fuels. Although hydrogenhas almost three times more energy by mass than naturalgas, by volume the energy density is much lower. As aresult, hydrogen fuelled gas turbines will require largerdelivery piping, manifold, valves and nozzle sizes thannatural gas-burning engines currently need. Compressinghydrogen to a greater operating pressure than natural gas,to increase its volumetric energy density, would mitigatethe increased size requirements for delivery equipment.The flammability range of hydrogen is quite large com-pared to other fuels, so that the fuel/air ratio can bethrottled for much leaner combustion.

Table 7. Cost comparisons of the main technology options.

ReferenceFuel cost($/kg)

Estimated cost of CO2

avoided USD/tonneEstimated capitalcost (USD/kW)

Estimated capital(USD/kW)

Post-combustion natural gas combined cycleParsons, 2002, 508 MW NG 2.82 74 0.949 1099NETL, 2002, 379 MW NG 3.55 45 0.875 911IEA GHG, 2004, MEA, 776 MW NG 3 41 1.844 938Melien, 2005, 392 MW NG 2.96 57 1.09 1261Rubin et al., 2005, 507 MW NG 4.44 49 1.099 909Rubin et al., 2005, 507 MW NG 4.44 68 0.733 909

Post-combustion pulverized coal sub-critical boilersSimbeck, 2001, 294 MW 0.98 45 2.09 1059Alstom et al., 2001, 255 MW 96% capture 1.3 73 2.228 1941Chen et al., 2003, 140 MW 1.2 56 1.48 837Chen et al., 2003, 282 MW 1.2 48 1.48 647

Post-combustion pulverized coal super and ultracritical boilersParsons, 2002b, 329 MW PC 1.29 51 1.83 2219Parsons, 2002b, ultracritical boiler, 367 MW PC 1.29 49 2.35 1943IEA GHG, 2004, MEA, 666 MW PC 1.5 29 4.061 1894Rubin et al., 2005, 492 MW PC 1.25 40 3.102 1936

Oxyfuel boilerDillon et al., 2005, 532 MW 1.5 27 1857

Oxyfuel natural gas cycleDillon et al., 2005, 440 MW 3 47 — 1034

Pre-combustion NG combined cycleJacobs, 2003, 392 MW NG 3.52 68.4 1.329 1076Melien, 2005, 358 MW NG 2.96 76

IGCC GE oxygen-fired, bituminous coalSimbeck, 2002, 455 MW BC 0.98 22 2.151 2067IEA GHG, 2003, 730 BC 1.5 16 4.682 1495Rubin et al., 2005, 492 BC 1.25 20 2.749 1748Melien, 2005, 699 MW BC 0.3 14.5 6.8 1919Melien, 2005, 424 MW 2.96 34.4 1.47 1089

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

Wabash Power Station Polk Power Station Willem Alexander Puertollano Negishi

Gasifier technology Conoco Phillips GE Energy Shell Prenflo (Uhde/Krupp) GE EnergyLocation Indiana, USA Florida, USA Buggenum, Netherlands Spain JapanGas turbine GE MS 7001FA GE MS 7001FA Siemens V 94.2 Siemens V 94.2 MHI 701FFuel feedstock Bituminous coke/

Petroleum cokeBituminous coke/



Petroleum cokeAsphalt

Thermalefficiency (HHV)

39.7 37.4 41.4 41.5 Unknown



Although hydrogen combustion turbines are not presentlycommercially produced, there appears to be no majortechnical barriers for gas turbines burning gases withhydrogen contents up to roughly 70%. While immediateefficiency gains could be obtained using hydrogen in placeof natural gas, these would likely be offset by NOx controlconsiderations, such as a lean fuel/air mixture to limit thecombustion temperature. Since efficiency and powerroughly can be considered equal between these fuels, themost significant gain from converting to hydrogen fuelledgas 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 tur-bine. Steam injection was selected as the method of limit-ing NOx production. An alternative to steam injection isto use inlet fogging techniques (e.g., Van de Burgt,2004). Such techniques are increasingly used in commer-cial operation to increase turbine output (up to 20%), toreduce heat rate, to improve turbine efficiency and toreduce NOx emissions. These systems inject only of theorder of 1% H2O by weight in a fine spray upstream ofthe compressor. Wotzak et al. (2005), report on the suit-ability for hydrogen utilization of the GE Frame 5002Cand 6001B gas turbines at the BP Prudhoe Bay Facility.All the three big suppliers (GE, Siemens and Alstom) com-municate a general interest in developing low emission andhigh-efficiency hydrogen combustion. This is also mani-fested through their participation in big research projectssuch as ENCAP (EU) and FutureGEN (USA).

ADVANCED OPTIONS

Many novel pre-combustion concepts or improvementshave been published (see for example Middleton et al.,2002; Holt et al., 2003; Jordal et al., 2003). A few ofthem are mentioned here. The sorption enhanced reactionprocess (SER) combines catalytic shift conversion (ofcarbon monoxide and steam to hydrogen and carbondioxide) with a high temperature CO2 adsorption systemusing 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 carriedout in a multi-bed pressure swing adsorption unit which isregenerated using low pressure steam which is subsequentlycondensed to leave a relatively pure CO2 stream.The removal of hydrogen in dehydrogenation and syn-

thesis gas reactions with membranes has been widelystudied. Two different approaches have been investigated:Integration of a membrane into the reformer and integrationof a membrane into the high temperature shift reactor.Product removal may occur by H2 permeation through aPd-alloy or composite Pd-ceramic membrane or a ceramicporous membrane. The permeation of the sweep gas ontothe feed (i.e., retentate) side also contributes to increasingthe conversion.

CO2 PURITY REQUIREMENTS

The CO2 purity requirements for the whole CCS chainare being formulated. For CO2 capture for enhanced oilrecovery (EOR), experience from existing large-scaleEOR 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 contentof gas produced from the Jackson Dome in the USA canbe as low as 65%, while the McElmo Dome (USA) pro-duces 98–99% CO2. The CO2 purity requirements forECBM and storage only (i.e., no hydrocarbon production)are believed to be less stringent than those for EOR. ForEOR, components like N2 and O2 below 300 and 50 ppmlevels respectively may be required, although for theSACROC EOR project in the USA (for example), a maxi-mum content of 4 mol% N2 is specified. Since immisciblecomponents may increase the minimum miscible pressurein the reservoir and thus decrease the efficiency of CO2

injection, the total concentration of components immisciblewith oil (CH4, Ar, N2 and H2) is important and the effect ofthe immiscible components is likely to be assessed for eachEOR project. Oxygen present in the gas stream may causeprecipitation reactions and reduce the permeability of thereservoir, or react exothermally with oil and cause over-heating at the injection point. Particulates pose the dangerof pore blockage near the injection well thereby reducingreservoir permeability. Acidic compounds, such as H2S,COS, CO, SO2 and NOx are corrosive and will be repro-duced with the recovered hydrocarbons, affecting thechoice of materials and potentially increasing the down-stream processing required. Sulphur components may alsodowngrade produced hydrocarbons by increasing their sul-phur content. Where water-alternating-gas (WAG) technol-ogy is the EOR strategy adopted, the CO2 stream will comeinto contact with water at the top of the well. To preventhydrate formation, heating of the CO2 above 158C maybe required. The composition of the gas to EOR will, inother words, have important implications for the modifi-cations that are required at the injection point and forinvestments in the downstream oil and gas processingequipment.

RELATIVE POSITION OF THE MAIN CONTENDERS

Haines et al. (2004) present a methodology for screeningand comparing different processes for CO2 capture.Reported costs of CO2 capture are packed with technologi-cal and economic assumptions. Numerous comparisons ofoptions 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), Steinberget al. (1984). The recent IPCC report on CCS (IPCC,2005) contains a thorough review of a number of technologycomparisons that have been performed. Table 7 presents aselection of the reported costs in the literature. For compari-sons between different approaches to CO2 capture to bemeaningful, the competing methods must be based onshared assumptions about plant size, feedstock quality, pro-duct quality, CO2 delivered (purity, temperature andpressure), and the quality of available utilities (e.g., coolingwater temperature). For natural gas fired systems, techno-economic studies show that the fuel price has the largestimpact on the production cost of electricity, making thefuel efficiency of new concepts the most important selectioncriterion (e.g., Moller et al., 2005). Theoretical fuel efficiencyachievable on paper can in turn be based on optimisticassumptions about, e.g., turbine inlet temperatures, turbineefficiencies, steam levels achievable in Heat RecoverySteam Generators, lowest pressure achievable in condensers



and heat exchangers that cannot be built using currentmaterial technology (e.g., assuming that high temperatureheat exchange with synthesis gas is possible even in theoperational areas where metal dusting21 is known to occur).Technology choice implies a trade-off between fuel effi-

ciency, other operating expenses like maintenance or plantavailability and capital costs. Internal consistent compari-sons do not necessarily result in credible costs for CO2 cap-ture and storage: conventions or published methods (e.g.,Turton et al., 2003) for preparing cost estimates maydiffer from in-house standards for doing economic analysisthat include assumptions about fuel and capital costs(including the economic life of the plant, on-stream factors,weighted average cost of capital, inflation effects, interestcharges during construction, taxation, commissioningcosts and contingency elements). In addition to other site-specific details like labour costs and weatherization costsassociated with temperature or other extremes, methodsfor assessing costs often reflect a firm’s orientationtoward risk. For this reason, published costs are often nottransferable across organizational boundaries.

THE CONTENDING TECHNOLOGIES: NOVELMETHODS OF CO2 CAPTURE

Given the glaring disadvantages of the conventionalmethods, there is room for novel methods that can bringabout a step-change in efficiency of CO2 capture. In additionto the commercially available separation techniques, thenumber of different concepts for separating CO2 is limitedonly by the creativity of the scientists and engineers whoare 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 toorganic material) and formation of CO2 hydrates. Anair-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 announcedthat a larger field trial of the bioreactor for the combinedremoval of CO2 and NOx.22

The use of dry regenerable sorbents has also been investi-gated. The CO2 is chemically absorbed by the sorbent and isthen subsequently released in a second step to produce a con-centrated stream of CO2 at which point the sorbent is regen-erated and recycled. Sorbents such as sodium carbonate,calcium oxide and lithium silicates/zeolites have been inves-tigated (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 withamines have also been suggested (Contarini et al., 2002).While the carbonation of CaO to CaCO3 involves theseparation of CO2 above 6008C, and regeneration at9008C, temperatures of about 30–1008C are used to regen-erate amine impregnated solids. Reactor systems that havebeen suggested for this type of process include fixed bedreactors, 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) ona large scale are the costs of solids handling and dustelimination equipment, the cyclic absorption capacity andmechanical strength of the absorbent. Electric swing adsorp-tion, involving the adsorption of CO2 on a charged carbonsubstrate and high-temperature polymer (solution-diffusion)membranes have also been proposed (e.g., Van der Sluijset al., 1992).

A further possibility for solid fuel firing is described byAlstom (Griffin et al., 2003)—a high temperature carbonateloop is proposed in which calcined limestone is used toremove CO2 from oxygen rich flue gases. Limestone circu-lates between a high temperature calciner—that producesfree lime and CO2 for subsequent processing and dispo-sal—and a high temperature region of the furnace whereCO2 is absorbed.

CO2 TRANSPORT

The transport of CO2 by land-based pipelines is a well-established practice worldwide: For example, 50 milliontonnes/year of CO2 are transported in pipelines thatextend over more than 2500 km in western USA, mostlycarrying CO2 from natural sources to enhanced oil recoveryprojects (IEA GHG, 2002a; West, 1974). The Cortez pipe-line is the largest example, with a diameter of 30 in and acapacity of 12.2 Mt CO2/year. The CO2 for this pipeline isproduced from the McElmo field, operated by KinderMorgan, which contains 97 mole% of pure CO2. Beforethe CO2 is pumped down the pipeline, it is cleaned,dehydrated and compressed to supercritical pressure(145 bar). The use of pumps to transport supercriticalCO2, rather than compressors for gas phase transport,reduces operating costs significantly. In 2007, the firstlong distance (150 km) offshore CO2 pipeline will becommissioned as part of the Snøhvit LNG project.

The most widely used operating pressure is between 7.4and about 21 MPa, although the design pressure isobviously dependent on the desired delivery conditions,the transportation length and the composition of the gasto be transported. Above 7.4 MPa, CO2 exists as a singledense phase over a wide range of temperatures. The solubi-lity of water in CO2 (to determine the percentage freewater) and corrosion rates are important considerationsfor establishing the material specification for a CO2 pipe-line. Water solubility in CO2 is given in Heggum et al.(2005). Existing practice for inhibiting hydrate formationand preventing excessive corrosion rates for carbon steel isto reduce the water content to ppm-levels using eithermolecular sieves, glycol (MEG/TEG) or alumina desiccants.

The requirement for CO2 pipelines, used for EOR in theUSA, is maximum 600 ppm water (Heggum et al., 2005).While accurate estimations of the water solubility is keyto determining the corresponding corrosion rates and thusthe dehydration/corrosion inhibition requirement, the solu-bility of water in CO2 is influenced by the concentration ofother components (e.g., hydrocarbons, N2) (Skovholt,1993). The presence of hydrocarbons tends to lower thewater solubility, as do decreasing temperatures. For deepwater pipelines, the static head contributes to increasedpressure and increased water solubility, and thereforetends to prevent the formation of free water. At the LNGplant at Hammerfest in Norway, CO2 will be removed

21Boudard reaction: 2CO ! Cþ CO2. One of the mechanisms that lead tothe disintegration of metals. The critical temperature range is 400–8008Cand the relative concentrations of CO2/CO determining the reaction rate.22http://www.greenfuelonline.com.



from the natural gas prior to the LNG liquefaction unit. Thedrying requirement for CO2 pipeline transporting thecaptured CO2 to the Tubaen formation, is 50 ppm water,which is the engineering practice for transportation of naturalgas (Heggum et al., 2005; Maldal and Tappel, 2004).An important area of future research is to improve under-

standing of the influence of the impurity concentration onthermo-physical properties such as critical pressure andtemperature, mixing properties and how changing CO2

gas properties affect the design and operating parametersof the compression equipment.Transport scenarios for CO2 have been reported by

Skovholt (1993) and Svensson et al. (2004): For longdistance, offshore transport of CO2 an alternate approachto pipelines is a logistics chain consisting of CO2 liquefac-tion and intermediate storage facilities, ships, loading andunloading systems. It has been proposed that liquid CO2

is transported at a temperature of 2508C and a pressureof 7 to 8 bars. Large-scale liquefaction of CO2 is bestachieved in an open cycle, using the CO2 feed as therefrigerant where the refrigeration is partly or fully pro-vided by the feed gas itself. The liquefaction processincludes compression, cooling and expansion to the liquidproduct specification. In addition volatile gases and waterare removed (in gas scrubbers and an adsorption gasdrier). The process delivers CO2 at 6.5 bara and 2528Cto the storage tanks, with power consumption of about110 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 forpipeline transportation. Even though Yara International andthe Anthony Veder Group routinely transport CO2 by shipfor the North-European market, the ships currently in serviceare too small for large-scale ship-based transport of CO2: Yaracharters three ships carrying 900–1200 tonnes of CO2 (1000and 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 flexibilityto also transport LPG have been studied, the carrying capacitywill be influenced by harbour conditions, volumes and dis-tances (Berger et al., 2004).Ship-based transport would require liquefaction plants

and intermediate storage at each loading site (Lekvaet al., 2005). If an onshore CO2 hub were to be introduced,intermediate storage facilities matching the incomingamounts of liquefied CO2 would also be needed. Caremust be taken to avoid dry-ice formation in the processplant, storage and when loading and unloading. In thedense phase, CO2 is pumped to a pressure sufficient toavoid phase transition during transfer and further to theinjection pressure required. The total costs of ship-basedtransport are calculated to 23–31 USD/tonne for volumeslarger than 2 million tonnes/year and distances limited tothe North Sea (Berger et al., 2004).

CO2 STORAGE: PROJECT AND GEOLOGICALTIMESCALES

Geological storage of CO2 in the earth’s upper crust is anaturally occurring phenomenon. Carbon dioxide frombiological activity, volcanic activity, and chemical reac-tions is found underground either as dissolved/precipitatedcarbonate minerals, or in supercritical form. Candidate

geological formations for CO2 storage are depleted oiland gas reservoirs, deeply buried saline aquifers and uneco-nomic coal seams (Buller et al., 2004; Heinrich et al.,2003). A review of geological storage of CO2 can befound in Benson (2005). Depleted oil and gas reservoirshave the advantages of being proven traps; having well-known reservoir geology and of having infrastructuresthat can readily be adapted for CO2 transport and injection.Nevertheless, relatively few hydrocarbon reservoirs arecurrently depleted or near depletion, so that the timing ofCO2 storage will depend on reservoir availability (Beecyand Kuuskraa, 2005). Deep saline aquifers that could beused for long term CO2 storage are innumerable: In bothcases—depleted reservoirs and saline aquifers—much ofthe injected gas will eventually dissolve in the formationwater, while some may react with the minerals to form car-bonate precipitates. Rough IEA (2004b) estimates of howmuch CO2 could be stored in the various geological optionsare .15 Giga tonnes in unminable coal seams, 920 Gigatonnes in depleted oil and gas fields and 400–10 000Giga tonnes in deep saline aquifers. Table 9 below liststhe large-scale CO2 injection projects worldwide.

CO2 STORAGE AT SLEIPNER, IN SALAH ANDSNØHVIT

Motivated by the offshore CO2 tax imposed by theNorwegian government, currently at around 54 USD pertonne, since 1996 about 1 million tonnes per year of CO2

have been separated from the natural gas and stored in asaline aquifer (the Utsira formation) at the Sleipner field.A special feature of the field is the high carbon dioxide con-tent. Initial gas produced from the main field contains about9 mole% CO2 which must be reduced to an average of 3mole% to meet customer specifications (Baklid et al.,1996; Hansen et al., 2005). The CO2 is stripped from thewell-stream using an activated MDEA absorption process.The amine plant, which weighs about 9000 tonnes and is35 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 baraprior to being transferred to the Sleipner A platform forinjecting into the base of the saline aquifer (Hansen et al.,2005). The cost of CO2 storage by this method has been esti-mated to be close to 15 USD per tonne CO2 (Torp, 2004).

To predict the migration path of the injected CO2 and thestorage capacity of a reservoir, the appraisal of the reservoirgeometry and the presence of faults must be conducted overa range of scales. In addition, the construction of simplifiedgeological models based on all the available data may beneed to supplement reservoir simulation. As CO2 is buoyant

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

Year LocationCO2 injection rate

(million tonnes/year)Projecttype Operator

1996 Sleipner, Norway 1 Storage Statoil2000 Weyburn, Canada 1.2 EOR EnCana2004 In Salah, Algeria 1.3 Storage BP2004 K12B 0.2 Storage Gaz de France2006 Snøhvit 0.7 Storage Statoil2009 Gorgon, Australia 3.3 Storage Chevron



(in both gaseous and fluid phases) it will tend to rise to thetop of the repository reservoir. Assessment of the depth tothe top of the reservoir is therefore a basic prerequisite ofCO2 storage, allowing a first order estimate of short-termstorage capacity, and the assessment of likely migrationpathways (Buller et al., 2004). The detection of possiblereservoir compartmentalization and/or the potential forfault-related leakage is also important. The presence of reser-voir compartmentalization could lead to a rapid increase information pressures with time as fluid flow betweencompartments is inhibited. The identification of small-scalefaulting requires seismic data of adequate resolution (Ibid).The migration of CO2 in the Utsira Formation has been

monitored using 4D23 seismic. A baseline survey wasshot prior to injection in 1994, and repeat surveys haveso far been acquired in 1999, 2001, 2002 and 2004. The2004 seismic survey revealed that (after the injection ofapproximately 7 million tonnes) the area of the supercriti-cal CO2 plume was about 2 km2 with a maximum lateralmigration from the injection point of 1.5 km to the north-east (Hansen et al., 2005; Arts et al., 2004).Very long term geo-modelling of the Utsira aquifer

suggests that most of the CO2 will eventually dissolve inthe formation water: flow simulation models, calibratedwith the 4D seismic data, have been used to predict theCO2 behaviour in the Utsira Formation, over periods ofhundreds to thousands of years. The results of thesemodels predict that, following accumulation beneath therock cap seal for a few years after the injection hasceased, the CO2 will spread laterally on top of the brinecolumn with migration routes controlled by the topographyof the Utsira Formation/cap rock interface. It has beensuggested that the area size of the free CO2 plume mayreach its maximum size after a few hundred years, andmost of the CO2 will have dissolved into the aquifer afterbetween 5000 and 50 000 years (Hansen et al., 2005).The non-porous mineral volume composition of theUtsira formation is mainly quartz (76%), K-feldspar(7%), plagioclase (3%), mica (5%) and calcite (7%).Long-term (10 000 year perspective) numerical modellingof the reactivity of the CO2 in the aquifer indicates thatonly minor dissolution of the calcite occurs: the totalvolume of minerals undergoes little change and the overallporosity is unaffected over time (Audigane et al., 2005;Hansen et al., 2005).

At depths below 800 m, the properties of supercriticalCO2 (including its high density) potentially provide forthe efficient usage of the pores in the sedimentary rocks(Benson, 2005). Carbon dioxide can remain trapped under-ground through a number of mechanisms: trapping belowthe cap rock; retention as an immobile phase trapped inthe free pore volume of the storage formation (also calledresidual 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 maybe trapped by reacting with the minerals in the storage for-mation and cap rock to produce carbonate minerals. Byavoiding deteriorated wells, or open fractures or faults,injected CO2 will be retained for very long periods oftime.24 The Sleipner case has yielded considerable insightwhich has been worked into a Best Practice Manual forCO2 storage by the SACS and CO2STORE

25 projects.BP, the Algerian National oil and gas company, Sona-

trach, and Statoil are participants in the In Salah gas project,comprising eight gas fields in the central Saharan region ofthe country (Riddiford et al., 2004). Like at Sleipner, natu-rally occurring CO2 must be removed from the producedgas to meet market specifications. Adequate seal integrity,storage potential, good reservoir properties and a suitablereservoir pressure were the main criteria for identifying agood CO2 storage solution for the project. In addition, place-ment of the CO2 must be such that it is retained within theaquifer zone and is not reproduced with hydrocarbonsduring the life of the field. There is no CO2 tax in Algeriaand storage of CO2 is being done for environmentalconsiderations only. Starting in 2004, approximately 1.2million tonnes per year CO2 has been removed, compressedand in this case injected at a depth of 1800 m into an aquifersection at a remote corner of the Krechba gas field.

Maldal and Tappel (2004) describe the planned CO2 injec-tion 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 thenorth-western part of the Snøhvit field, into the Tubaenformation, CO2 injection at Snøhvit will extend knowledgeof CO2 storage in offshore aquifers since there are importantdifferences between the Utsira and Tubaen formations (seeTable 10). Similarly to the CO2 injection into the Utsiraformation, 4D seismic will be employed at Snøhvit tomonitor the CO2 injection. To provide a broader base ofdata, one of the gas producers could be deepened and usedas a monitoring well for the injection if deemed necessary.

In addition to the existing and planned CO2 storage pro-jects, experience with CO2 flooding for EOR is relevant forstorage: Hypotheses about the interaction of CO2 with othercomponents (hydrocarbons, nitrogen and H2S) may betested against existing data from EOR projects. In addition,monitoring techniques and safe practice encompassingproper operator training, maintenance procedures, pressuremonitoring, reliable gas detection systems, emergency shut-down procedures and other safety systems relevant for EOR

Figure 10. CO2 injection at the Sleipner Field.

23Data along the three geometric dimensions plus time-interval data.

24As discussed previously, detailed seismic mapping can be used to ident-ify fractures and faults.25The aim of the CO2STORE is to prepare the ground for widespreadunderground storage of CO2 in aquifers. CO2STORE is a research projectwith 19 participants from industry and research institutes, partly funded bythe European Union.



can be adapted for CO2 storage. In this regard, experiencefrom 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 feasibleto store CO2 in geological formations. Chevron is propos-ing to remove CO2 from produced gas at the Gorgonfield, containing approximately 14% CO2 off WesternAustralia. The CO2 will be injected into the DupuyFormation at Barrow Island (Oen, 2003, cited in IPCC,2005). In the Netherlands, CO2 is being injected at pilotscale into the almost depleted K12-B offshore gas field(van der Meer et al., 2005, cited in IPCC, 2005).

REALIZING THE VALUE CHAIN: OPPORTUNITIES ANDCHALLENGES FOR VALUE CREATION

Trials with the use of CO2 for producing incremental oilbegan as early as the 1950s (Holm and O’Brien, 1971) andthe large-scale injection of CO2 into subsurface geologicalformations was first undertaken in Texas, USA, in the early1970s, for EOR as a response to the first oil price shock.Miscible CO2 flooding has become an increasingly import-ant enhanced oil recovery technique in the USA for reco-vering residual or bypassed oil. At present there are 71active 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 PermianBasin, located in west Texas and the adjoining area ofsouth-eastern New Mexico and account for approximately4% (206 000 barrels/day) of the total USA oil productionin 2004 (Oil and Gas Journal, EOR Survey, April 122004). Approximately 30 million tonnes per year CO2 areinjected for EOR worldwide (Oil and Gas Journal EORsurvey, April 12 2004). The largest EOR injection ratesexceed 10 ktonne/day, the typical emission rate of a500 MW coal-based power station (Herzog, 1999). WithCO2 EOR, the CO2 content of the produced gas changesfrom 1 to 5% vol at the start and goes beyond 80% towardsthe 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 technol-ogy can increase oil recovery by 7–15% for land-basedfields as compared with water flooding alone: Holt et al.(2005) surveyed a selection of real field projects worldwideand concluded that CO2 injection yielded, on average26

incremental oil recoveries above 12% and 17% of the orig-inal oil in place for sandstone and carbonate reservoirs,respectively. In a report issued by the Norwegian PetroleumDirectorate27 (http://www.npd.no) in 2004, reservoircharacteristics (including the spacing of wells) in Norwaydictate lower incremental oil recovery (3–7%) for offshorefields. Accurate predictions of the EOR potential for agiven field can however only be assessed through extensivereservoir modelling using a numerical reservoir simulatorand 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

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

Table 10. Comparison of salient features of utsira and tubaen formations.

Depth (m) Porosity Permeability Gas cap

Utsira (CO2

from Sleipner)800–1000 35–40% 1–8 Darcy No

Tubaen (CO2

from Snøhvit)2400–2600 10–16% 130–880

mDarcyMinor

Gas Cap

26The CO2 floods included in SINTEF Petroleum Research’s database with115 CO2 injection projects.27http://www.npd.no/Norsk/Produkterþ ogþ tjenester/Publikasjoner/Oversiktþ sokkelpublikasjoner/Rapport_CO2_2004.htm.



around USD 11/tonne for pure, high pressure CO2 duringthe 1990s (Stevens et al., 2001). The production of CO2

with the hydrocarbons is an important issue, since typicallymore than 50% and up to 67% of the injected CO2 returnswith the produced oil (Bondor, 1992) and is usually separ-ated and re-injected into the reservoir. The remainder istrapped in the oil reservoir either by dissolution in reservoiroil that it is not produced and in reservoir pore spaceunconnected to the flow path for the producing wells.28

The Great Plains Synfuel Plant, near Beulah, NorthDakota, gasifies 16 326 metric tons per day of lignite coalinto 3.5 million standard cubic metres per day of combustiblesyngas, and close to 7 million standard cubic metres of CO2.A part of the CO2 is captured at high pressure by a physicalsolvent based on methanol. The captured CO2 is compressedand 2.7million standard cubicmeters per day are piped over a325 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 evaluationconsisting of reservoir simulation, an assessing the neededplatform modifications, transportation of CO2 and–notleast–in accessing the best CO2-sources for a total need of5 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 aver-age potential increase of 7.9% in hydrocarbon pore volume(HCPV). The value (purchase price) of CO2 delivered toexport terminals that feeds CO2 into the transportation infra-structure was estimated to be between 7.9 and 12.8 USD/tonne. When this is compared to the cost of CO2 capturefrom industrial flue gasses (e.g., a low estimate of 25 USD/tonne) and transportation from point sources to the exportterminals (e.g., 4 USD/tonne), it is evident that the use ofCO2 for EOR can cover only a fraction of the total costsassociated with CO2 capture, transport and storage.

CONCLUSIONS

The fundamentals of combustion and separation pro-cesses suggest that the capture of high purity, high concen-tration CO2 from fossil fuels requires energy. Improvedenergy efficiency and fuel switching are thus clearlysuperior strategies for curtailing CO2 emissions, althoughthese strategies do not actively capture CO2 from beingthe concern of a few specialists with strong convictionsabout man-made impacts on the earth, the substantial com-mitment of public resources to CCS R&D has contributedto establishing research on carbon dioxide capture and sto-rage as part of the mainstream. CO2 capture is premised onthe safe long-term storage of CO2 in geological formations.There is sufficient industry-wide know-how for realizingCO2 capture from dilute stationary sources of CO2, butpoor economics prevents this knowledge from being putinto practice. None of the major pathways for capturing

CO2 from power generation identified at present standsout as having greater inherent potential for substantiallylowering the costs of CO2 capture in the next decade.The challenges for chemical engineering are many: to por-tray 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 increasedexploration of hybrid processes (e.g., integrated separationand reaction) that combine the attractive aspects of conven-tionally discrete unit operations for improved energy andexergy efficiency. The increasing number of storage pro-jects worldwide provides a basis for improved strategiesfor the mitigation and management of risk associatedwith deep geological storage. The use of CO2 for EORcan cover only a fraction of the total costs associatedwith CO2 capture from power production, transport andstorage. Apart from technical advance, legislation and regu-latory changes will be the stronger drivers for closing theknowing-doing gap for CO2 capture and storage.

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ACKNOWLEDGEMENT

Valuable recommendations on literature sources and comments onearlier drafts were received from Gelein de Koeijer.

The manuscript was received 9 November 2005 and accepted forpublication after revision 13 February 2006.



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