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Techno-economic characterisation of

CO2 sequestration technologies

A technology status survey

A synthesis report prepared by

J. C. Abanades, R. Moliner

Instituto de Carboqumica

CSIC Consejo Superior de Investigaciones Cientficas

February 2002

Report EUR 20391EN

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European Commission

Joint Research Centre (DG JRC)

Institute for Prospective Technological Studies

http://www.jrc.es

Legal notice

Neither the European Commission nor any person acting on behalf of the Commission is responsible for

the use which might be made of the following information.

Report EUR 20391EN

European Communities, 2002

Reproduction is authorised provided the source is acknowledged.

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LIST OF CONTENTS

EXECUTIVE SUMMARY 3

Part 1 THE STATE OF THE ART1. Introduction 5

1.1Global warming 51.2Mitigation options and CO2 sequestration 6

2. CO2 sequestration technologies 8

2.1 CO2 capture technologies

2.1.1 Capture of CO2 after combustion 9

2.1.2 Combustion with oxygen 102.1.3 Capture opf CO2 before combustion 112.1.4 Advanced capture and other zero emission concepts. 11

2.2 CO2 Storage options 12

2.2.1 Storage in the oceans 122.2.2 Storage in deep aquifers and other geological formations 13

2.3 An overview of EU activities on CO2 capture and sequestration 14

Part 2 CASE STUDIES

3. Techno-economic characterisation studies 15

3.1 The cost of CO2 sequestration 153.2 Cost of CO2 sequestration and markets

4. Reviewed case examples in IPTS format 17

4.1 Case 1. Coal PC plant with flue gas absorption with MEAs 194.2 Case 2. Natural Gas Combined Cycle CO2 absorption with MEAs 20

4.3 Case 3. Oxygen blown IGCC with absorption 214.4 Case 4. Pulverised coal fired with O2/CO2 224.5 Case 5. Decarbonisation of natural gas integrating a NG reformer

and CO2 absorber 22

5. References 23

FIGURES 26

TABLES 33

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Techno-Economic characterisation of CO2 sequestration technologies.

A technology status survey

Final Report

January 2002

Contract n 18347-2001-09 F1ED SEV ES

J C Abanades, R Moliner

Instituto de Carboqumica-CSIC

Dep. Energy and Environment

Miguel Luesma 4

50015 Zaragoza, SPAIN

EXECUTIVE SUMMARY

This report presents the results of a literature survey carried out by the Instituto deCarboqumica (CSIC) for the Institute for Prospective Technological Studies, a Joint ResearchCentre of the European Commission. It constitutes the final report associated with the contract18347-2001-09 F1ED SEV ES.

The objective of this work was to carry out a literature review of the status of CO2

sequestration in the world and in the European Union. Also, to review techno-economicstudies of technologies for CO2 sequestration, including a prospective dimension. Thesurvey is divided in two parts. The first part provides an overview of leading technologyoptions to capture and storage of CO2. Also, a survey of current research effortsworldwide and a short description of current activities and targets in EU-funded

projects in the field of carbon sequestration has been made. The second part of thesurvey provides a review of the key techno-economic parameters published for specificcase studies in the open literature. The techno-economic parameters have been adaptedas much as possible to the format of the IPTS energy database. It is beyond the scope ofthis contract to carry out independent cost estimations of specific technologies.

The survey shows that CO2 sequestration is a very fast growing field of research anddevelopment. It is increasingly regarded by many as a viable mitigation option toachieve deep reductions of CO2 emissions in the medium to long terms. These largereductions could be achieved with the least impact on global energy infrastructure andeconomy. The concept is best suited for large, centralised sources of CO2, but it alsoopens the way for a hydrogen-based economy, suitable for the transport vehicles andother widespread uses at small scale.

There is a broad range of options for CO2 capture and for CO2 sequestration, some ofthem based on well known processes in industry today. Specific market opportunitiesexist to facilitate large scale demonstration of carbon sequestration in the short term.

However, the large scale deployment of these technologies will be associated to asubstantial additional cost of electricity production. This is mainly because the costassociated with the separation step of CO2 from flue gases. Reviewed leading options to

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incorporate capture to power plants incur in additional costs for electricity between 1.9and 3.7 cEUR/kWh and mitigation costs between 30 and 60 EUR/Mg of CO2 avoided(see Tables 2-14). In addition, the costs for transport and final storage can add between15-30%. These figures are very sensitive to the assumptions on capital charge rates andto the fuel costs. Also, there is scope for wide reductions in these costs byimprovements in the different components and by possible breakthrough technologies

under active research and development worldwide. Therefore, it can be concluded thatcapture and sequestration of CO2 is already a promising, strong mitigation option, thatcan deliver an effective solution for deep CO2 emission reductions in the medium tolong terms.

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Part 1

THE STATE OF THE ART

1. Introduction

1.1Global warmingThere is a wide consensus from extensive research in the last three decades that rapidclimate change is already happening, that global average temperatures are increasing atunprecedented rates (Figure 1) . In parallel, CO2 emissions from anthropogenic sourceshave also been increasing in the same time frame (Figure 2) and these are known to

produce a greenhouse effect. The link between these two facts is not as immediate as it

looks from the observation of Figures 1-2, because the climate system is extraordinarilycomplex and major natural variability has occurred in the past without humanintervention (1). Also, there are still some limitations to measure the climate systemwith enough precision today. The limitatinos are stronger when comparing todaysclimate with the past, were direct measurements are much more scarce. However, avast and growing volume of rigorous data and scientific studies interpreting them, have

been produced to improve our understanding of the Earths climate and its evolutionwith time. At the same time, much effort has been placed to understand and quantifythe economic, social and political consequences of different global warming scenarios.The global warming issue has become one of the main concerns in Europe and otherdeveloped societies. The debates have reached the highest level in the political agendas

and in the interest from the media. High quality information and fair assessment hasbecome of paramount importance.

The United Nations Environment Programme (UNEP) and the World MeteorologicalOrganization (WMO) created in 1988 the Intergovernmental Panel on Climate Change(IPCC, see at www.ipcc.ch). The role of the IPCC was to assess the scientific, technicaland socio-economic information relevant for the understanding of the risk of human-induced climate change. It bases its assessment mainly on published and peer reviewedscientific technical literature. The IPCC completed its First Assessment Report in 1990.This played an important role in establishing the Intergovernmental NegotiatingCommittee for a UN Framework Convention on Climate Change (UNFCCC) by the UNGeneral Assembly. The UNFCCC was adopted in 1992 following the Earth summit thattook place in Rio de Janeiro in 1992 and entered into force in 1994.

In its Second Assessment Report, Climate Change 1995 a Summary for Policy-Makers included the statement:

The balance of evidence suggests a discernible human influence on global warming

which was at the core of the scientific and political debate that lead to the adoption ofthe Kyoto Protocol to the UNFCCC in 1997. Through the Kyoto Protocol, developed

countries agreed to reduce their CO2 emissions by 5,2% below 1990 levels. Thisprotocol has not yet been ratified although negotiations proceed at the highest politicallevel in the different Conference of the Parties.

http://www.ipcc.ch/http://www.ipcc.ch/http://www.ipcc.ch/

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Europe is responsible for about 15% of the worlds greenhouse gas emissions but hasonly 5% of its population. Europe has taken the lead in international negotiations toforce the practical implementation of the agreements and has committed itself in theKyoto Protocol to a reduction of 8% over 1990 levels. It has also recognised the need totackle far more reaching goals set by the IPCC, targeting reductions levels of 70% in the

long term (2).

The Third Assessment Report of the IPCC "Climate Change 2001" has been just issuedin 2001 (available at http://www.ipcc.ch/) providing a comprehensive and up-to-dateassessment of the policy-relevant scientific, technical, and socio-economic dimensionsof climate change. The three Working Groups contributions were already published inJuly 2001 (1,4-5) and will be used in this survey as an authoritative reference to framethe world-wide debate on global warming issues and, more specifically, on the CO2mitigation options.

1.2 Mitigation options and CO2 sequestrationSeveral gases are emitted to the atmosphere by human activity that are known tocontribute to the greenhouse effect (CO2, CH4, N2O, Halocarbons etc). There is a widevariety of mitigation options for these gases and some of these have already beensuccessfully implemented through international agreements (as is the case for CFCs).Carbon dioxide from fossil fuel burning is however the major contributor to thegreenhouse effect from human activities (about two thirds of the global warming

potential) and the most difficult to tackle. This is because the huge quantities beingemitted and because the very tight link that exists between CO2 emissions and socialdevelopment over the past 2 centuries. Since 1751 roughly 270 Gt (1Gt=10 9 metric tonsof carbon) have been released to the atmosphere from the consumption of fossil fuels

and cement production (see Figure 3). Half of these emissions have occurred since themid 1970s. The 1998 fossil-fuel emission estimate for global CO2 emissions was 6.61Gt of carbon (24.24 Gt of CO2) (6).

As can be seen in Figure 4, a large part of the carbon can be taken up by the oceans andother natural carbon sinks (1,6). Looking at the magnitudes of the carbon flows inFigure 4, it is obvious that there is a large potential to offset CO2 emissions byincreasing the activity of some natural carbon sinks. This is however still open to muchscientific and technical debate. As an example, reforestation seems to be a commonsense solution to increase the carbon uptake by inland vegetation, but there is still much

debate about how effective is reforestation as a carbon sink in the long term and evenabout how these effects can be properly quantified (5-7)

As mentioned before, the IPCC issued in July 2001 a Summary for Policy Makersdescribing the main options for mitigation of climate change by reducing greenhousegas emissions and enhancing sinks (see also ref.1). It is stated in this document thatrelevant advances are taking place in a wide range of technologies at different stages

of development, e.g., ... the demonstration of underground carbon dioxide storage.

Technological options for emissions reduction include improved efficiency of end use

devices and energy conversion technologies, shift to low-carbon and renewable biomass

fuels, zero-emissions technologies, improved energy management, reduction of

industrial byproduct and process gas emissions, and carbon removal and storage.

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Table 1 provides estimates by the IPCC of potential greenhouse gas emission reductionsin the 2010 to 2020 timeframe (5). One of the key conclusion in this study is therecognition that at least up to 2020, energy supply and conversion will remaindominated by relatively cheap and abundant fossil fuels. The IPCC predicts that naturalgas, where transmission is economically feasible, will play an important role inemission reduction together with conversion efficiency improvements, and greater use

of combined cycle and/or cogeneration plants. Before 2010, low-carbon energy supplysystems can make an important contribution through biomass from forestry andagricultural by-products, municipal and industrial waste to energy, dedicated biomass

plantations, where suitable land and water are available, landfill methane, wind energyand hydropower, and through the use and lifetime extension of nuclear power plants.

After 2010, emissions from fossil and/or biomass fuelled power plants could be reduced

substantially through pre or post-combustion carbon removal and storage.

Environmental, safety, reliability and proliferation concerns may constrain the use of

some of these technologies.

In Table 1, there are a number of categories of low cost CO2 mitigation and even

positive economic effects. These are usually termed least regrets options. The majordrawback of this group of technologies is their limited impact. They may be sufficientto meet short-term goals, but there is a concern that they will not be able to address the

problem in the mid- to long-terms.

To meet probable emissions targets in the mid- to long-term, more costly mitigationtechnologies must be considered, specifically nuclear, large scale use of renewableenergy, and CO2 capture and sequestration. Nuclear must address the issues of safety,waste, and public acceptance. Renewables have to overcome the problems of cost,intermittent supply, and limited geographical applicability. CO2 sequestration offers, in

principle, some attractive advantages (8):

It is cautious to have available a broad range of strategies to help meet future policygoals on CO2 emissions in a time of uncertainty about what mitigation option is the

best option after exploiting the least regret options.

Sequestration technologies provide a long-term greenhouse gas mitigation optionthat allows for continued large-scale use of abundant fossil energy resources.

With continued research, these technologies have the potential to provide a cost-effective mitigation option in response to policies aimed at limiting greenhouse gasemissions and ultimately stabilising greenhouse gas concentrations in theatmosphere.

These technologies can be used as an alternate option in case new non-fossil energysources like solar or present non-fossil energy sources like nuclear cannot gainsufficient market share and/or acceptance.

These technologies could be a low cost mitigation option if hydrogen was to becomea major energy carrier.

In summary, CO2 sequestration is a relatively new, competitive and viable option formitigating CO2 emissions along with current efforts at improving efficiency, fuelswitching and the development of renewables. The global sequestration capacity is hugeeven when the Oceans are excluded (Figure 5), and breakthroughs in some emergingstorage options (like mineral sequestration) could make it even bigger. The technology

as a whole (capture of CO2, conditioning for transport, storage and monitoring) must beable to compete economically with other costly mitigation options when the leastregret options prove insufficient to achieve more demanding reduction targets. It also

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has to demonstrate that no unacceptable environmental impacts and public health risksexist with the different storage options. These aspects are reviewed briefly in the nextsection.

2. CO2 sequestration technologiesThe focus in the following paragraphs is on CO2 sequestration understood here as thecapture and storage of CO2. Other mitigation options that also can sequester carbon, likereforestation and/or changes in land use, ocean fertilisation etc. are specificallyexcluded of the discussions from this point.

Capture and sequestration technology schemes can only be established in large CO2 -emitting industrial sources like power plants, cement production, natural gas production(that may contain a high proportion of CO2) etc. In the future, similar opportunities forCO2 sequestration may exist in the production of hydrogen-rich fuels (e.g., hydrogen ormethanol) from carbon-rich feedstocks (e.g., natural gas, coal, or biomass). Specifically,

such fuels could be used in low-temperature fuel cells for transport or for combined heatand power (8-10).

The review of the different technologies presented below is taken mainly frominformation from the IEA Greenhouse Gas R&D Programme (IEAGHG)(http://www.ieagreen.org.uk). Also from works on the subject carried out at the MITCO2 Sequestration Initiative (http://sequestration.mit.edu ). These are world authoritieson the subject of carbon sequestration that have published over the years authoritativeassessments of the different capture and storage technologies. Were appropriated, someupdates are introduced from works published in the Fourth and the Fifth InternationalConference on Greenhouse Gas Control Technologies (GHGT4 and GHGT5) also co-

organised by the IEA GHG Programme.

2.1 CO2 Capture Technologies

The different capture technologies can be organised according to where the carboncapture is carried out: capture before the fuel combustion, combustion with oxygen, andcapture after fuel combustion. It is implicitly assumed that the final fate of any fuel forenergy use is the products of its combustion. However and as mentioned above, captureof CO2 can also be applied to reduce the carbon content of a fuel and/or produce carbonfree energy carriers (like hydrogen ). These concepts can be easily classified as capture

before combustion. The main technological options are discussed in the next paragraphsunder these three categories, leaving a final section on advanced capture and zeroemission concepts to outline emerging processes that are receiving increasing attentionas potential breakthrough technologies for the medium to long terms. The discussionsand examples are focused on electricity production, although they could also be appliedto other large point sources of emissions. No much distinction is made in this overview

between the primary technology (the source of CO2) that is used for fuel processingand/or power generation. This aspect is left for the specific case studies selected forsection 3.

2.1.1 Capture of CO2 after combustion.The existing world infrastructure to produce electricity and heat from the directcombustion of fossil fuels with air is immense and rapidly growing, specially in

http://www.ieagreen.org.uk/http://www.ieagreen.org.uk/http://sequestration.mit.edu/http://sequestration.mit.edu/http://www.ieagreen.org.uk/

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developing countries. Therefore it would be ideal to have available a technology toseparate CO2 from combustion gases downstream the power station as it is a common

practice for SO2 removal in modern plants incorporating Flue Gas Desulfurisation(FGD) units. This retrofitting option should be, in principle, the most attractive onerespect to any other alternative involving a widespread deployment of completely newtechnologies.

Unfortunately, things are not so easy with post-combustion capture of CO2. The volumeconcentration of CO2 in combustion gases ranges from 15% for coal combustion to 3%for a natural gas combined cycle. The remaining gases are mainly nitrogen, someoxygen and water vapour. It would not be practical to store flue gases underground

because there would be insufficient storage space and because too much energy wouldbe required for compression (9). Technologies have also been proposed and evaluated indetail to put in contact the combustion gases with sea water that could absorve CO2 in aonce-through mode of operation (11). However, the most attractive technological optionfor post combustion capture is still the separation of CO2 from combustion gases and theconditioning of the CO2 in liquid form, ready for disposal.

In the following paragraphs, the absorption technologies available for CO2 separationare outlined. These are considered as leading options in key reviews of the subject (8-9,12-16) and therefore we leave other alternatives and less developed approaches forsection 2.1.4. Figure 6 outlines the principle of operation of these systems. These arewidely used in petroleum, natural gas and chemical industries for the separation of CO 2.Chemical absorption is based on the use of aqueous solutions of mainly mono- (MEAs),di- or tri-ethanol aminas and other inorganic compounds (sodium hydroxide, carbonateand potassium carbonate) which form weakly bonded intermediate compounds withCO2. These processes can be used at low CO2 partial pressures, but the flue gas must befree of SO2, O2, hydrocarbons and particulates. Hydrocarbons and particulates cause

operating problems in the absorber. The two chemical absorption processes mostcommonly applied to remove CO2 from flue gases are the MEA process and theactivated potassium carbonate process (8).

Physical sorbents suitable for absorption of CO2 are typically methanol (in the Rectisolprocess), N-methy-2-pyrrolidone (Purisol), polyethylen glycol di-methylether (Selexol)or propylene carbonate (Fluor solvent). These physical sorbents rely on solubility and

partial pressure gradients to absorb CO2. The latest are better suited for high pressureoperations as described in section 2.1.3.

There are large scale commercial CO2 recovery plants using absorption processes (seefor example the Table 4 in reference 13) and therefore this can be considered as amature technology that can be (and has been) evaluated in detail from economic andtechnological perspectives in a large number of studies. However it contains someunavoidable limitations: the large flow of gas that has to be treated necessarily leads tolarge size of absorption equipment , the low concentrations of CO2 requires powerfulsorbents that will in turn require much energy to be reactivated. Much work is in

progress worldwide to improve the quality of the sorbents (in terms of activity andchemical stability required in continuous cyclic operations) and the design of thegas/liquid contactor to reduce unit size and capital costs.

Other techniques usually termed as postcombustion technologies are cryogenics.membranes and adsorption technologies. The first ones are limited to streams with highconcentration of CO2 and should be regarded as a purification step more than a

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separation process. Existing membranes can not achieve high degrees of separation ofCO2 from flue gases. Therefore , multiple stages and/or recycles would be requiredincreasing complexity and costs. Much development is required before membranescould be used in large scale for capture in power stations (8,9,13). The same applies toadsorption processes based on zeolites, activated carbons or other materials capable ofadsorbing CO2 in the flue gases and deliver it in a sorbent regeneration step at higher

temperatures and/or lower pressures. Much better sorbents should be developed tomake attractive these options (13).

2.1.2 Combustion with oxygen.An alternative approach for removing CO2 from the flue gas is to use oxygen forcombustion instead of air. As discussed above, much can be gained by increasing theconcentration of CO2 in the combustion gases. Since the target in scrubbing flue gas isto separate the CO2 from the nitrogen, eliminating the nitrogen from the air removes the

primary source of nitrogen and greatly simplifies the flue gas clean-up. In theory, theCO2 concentration in the flue gas can be increased to over 95% on a dry basis when

firing with oxygen (13). In order to maintain thermal conditions in the combustion zoneof the boiler, some of the flue gas would be recycled to the furnace (see Figure 7).

In the systems outlined in Figure 7, producing the oxygen or oxygen enriched air nowbecomes a major expense. However, using oxygen instead of air opens up newpossibilities for increased combustion efficiencies. Also, trace impurities would end upin the CO2 effluent stream and might be suitable for disposition together with the CO 2achieving a Zero Emission Power plant (13, 17). Since SO2 and NOx emission controlsalready introduce added costs to the production of electricity, these could be counted ascredits towards the CO2 control.(8, 13)

This approach is also open for retrofitting applications of existing coal fired boilers.Earlier experiments in USA in the 80s and in Europe under JOULEII showed that theswitch to a O2:CO2 mode of operation in power stations did not present any majortechnical problem that could not be overcome (13). Substantial effort is still goingworldwide in this direction of research, from advanced concepts for air separation toreduce O2 production costs to large scale application of fuel combustion with enrichedair (13). However, this technology may be better suited for new plants because new

plants can better take advantage of the improved efficiency opportunities related tooxygen use and because of questions concerning retrofits (e.g., air inleakage) (8).

2.1.3

Capture of CO2 before combustion.

A simple scheme representing this concept is presented in Figure 8 extracted fromDavidson et al. (9). The concept implies a newly constructed power plant although mostof the individual units are commercially available (like in the ammonia productionindustry) and/or at an advance stage of development and demonstration. In fact, thistechnology is regarded by many experts as one of the most promising options tointegrate CO2 capture in advanced, high efficiency power generation concepts from coal(using IGCC cycles), oil or natural gas combined cycles.

The fuel is reacted with oxygen and/or steam to give synthesis gas (CO+H 2). The

carbon monoxide is reacted with steam in a catalytic shift converter to produce CO 2 andH2. All these operations are carried out at high pressure and high partial pressures ofCO2, greatly simplifying the separation of CO2 from H2. Advanced concepts for this

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separation are also being investigated (reactive membranes). Hydrogen can then beburn in an existing gas turbine with little modification (although this is not acommercially proven technology, at least two gas turbine manufactures are known tohave undertaken tests on combustion of hydrogen rich fuels (9,30). Also, The

precombustion route opens up opportunities for polygeneration (18), in which,besides electricity and CO2, additional products are produced. For example, instead of

sending H2 to a turbine, it can be used to fuel a hydrogen economy. Syngas, moreover,is an excellent feedstock for many chemical processes.

The strategic importance of this route justifies the selection of two case studies insection 3 to review the benefits of this approach respect to other leading options.

2.1.4 Advanced capture and other zero emission concepts.CO2 separation technologies account for more than two thirds of the cost of CO2sequestration processes (8,9,14,15,18). Even the most established options, that are

proven in other industrial sectors, can still be considered as emerging technologies

when applied to the specific conditions, scales and the world capacity that is required tobecome a serious mitigation option of CO2. Therefore, important improvements arelikely in formulating new solvents that can significantly reduce the energy penaltyassociated with chemical absorption and reduce other operational limitations. Also,oxygen separation from air is at the core of several of the schemes outlined above andsome of the most efficient concepts for coal utilisation like IGCCs. Moderateimprovements can be expected with time in existing air separation technologies or even

breakthrough processes for O2 production through new membranes. The development ofnew membranes for different separation operations and/or added catalytic properties isa field of intense research and development. Examples of current activities in USA inthese fields are outlined by Schmidt and Beecy (19). Some new EU funded projects

under the Energy Programme include membranes as a R&D subject (see section 2.3)

There is also a clear scope for the development of completely new concepts that couldsubstantially reduce CO2 capture costs. Examples of these new concepts are theChemical Looping Combustion, where the fuel (in gas form) is oxidised with a solidoxide to produce CO2 and H2O. The reduced oxygen carrier is then reoxidised by air ina second reactor and recirculated to the first reactor (20). Also, power technologiessuch as fuel cells or other advanced cycles are evolving and may become available touse the hydrogen rich fuel gas produced after CO2 separation. These technologies arelikely to yield higher energy efficiencies and, therefore, further reduce the penalties

associated with CO2 capture (9). Under this category is a novel concept aiming fordemonstration at the Los Alamos National Laboratory in USA is the Zero EmissionCoal Alliance (ZECA) process (see at http://www.lanl.gov/energy/est/zec/zec.html andwww.zeca.org ). This is based on the separation of CO2 from coal gasification gaseswith CaO after a shift converter, and the subsequent calcination of the CaCO3 toregenerate the sorbent and produce CO2. The hydrogen resulting after the separation ofCO2 is used in a high temperature fuel cell that also supplies part of the heat forcalcination. Parallel activities with a similar cycles are being carried out in Japan andtwo new projects with EU funding are currently being negotiated in Europe with

participation of CSIC. These options have not been included as case studies because it isaccepted that they are at a very early stage of development to provide reliable estimates

for the critical techno-economic parameters targeted in this survey.

http://www.lanl.gov/energy/est/zec/zec.htmlhttp://www.lanl.gov/energy/est/zec/zec.htmlhttp://www.zeca.org/http://www.zeca.org/http://www.zeca.org/http://www.lanl.gov/energy/est/zec/zec.html

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2.2CO2 storage optionsThe main options available for storage of CO2, in a scale sufficiently high to have animpact as a greenhouse gas mitigation option are:

Storage in the oceans

Storage in geological formations (deep aquifers, depleted gas and oil reservoirs ordeep coal seems, mineral sequestration, etc).

Figure 5 shows the orders of magnitude of worldwide storing capacity (8 and 18). Otherstorage options are being proposed with different limitations in their storage capacityand/or their perceived costs and environmental impact and these are described in theIEAGHG report on ocean sequestration (21) and US DOE report on CO2 sequestration(10). Parts of the contents of these two web sites and some comments from general

papers from the lead authors have been reproduced below.

2.2.1 Storage in the oceans

The oceans represent the largest potential sink for anthropogenic CO2. It alreadycontains an estimated 40,000 GtC (billion metric tons of carbon) compared with only750 GtC in the atmosphere and 2200 GtC in the terrestrial biosphere. As a result, theamount of carbon that would double the atmospheric concentration would change theoceans concentration by less than 2% (18). As discussed in the introduction, a largefraction of the CO2 emitted from anthropogenic sources in the last two centuries could

be absorbed by the Oceans. However transfer of dissolved carbon from the surfaceocean waters to the deep ocean waters is a very slow process. Various modelling studieshave demonstrated that a possible way to accelerate this slow transfer process betweensurface and deep ocean water is the injection of CO2 directly into the deep ocean water(21) Model simulations also indicate that retention times of greater than 1000 yearswould be achieved by injecting at depths of 3000m. Furthermore at depths greater than3000m the density of liquid CO2 exceeds that of seawater allowing it to sink to evengreater depths or collect in pools on the ocean floor. Installing sub-sea pipelines andstructures at this depth is outside the experience of current technology and laying

pipelines at 3000m is not, at present, a practical option. However injection via verticalpipes, from a ship or platform, is being considered (Figure 9, adapted from ref. 12).

The storage capacity of Oceans is huge and the estimates of costs of availabletechnologies for transport and disposal have not identified major barriers for a

implementation of this options in several favoured sites in the world (18). The mainconcerns are of environmental character: the concept of ocean storage will only beacceptable if the impact on the marine environments is far less than the avoided impactof continuous emissions to the atmosphere. Major international collaborative programsare in progress to test and demonstrate this concept and evaluate these environmentalimpacts (18).

2.2.2 Storage in deep aquifers and other geological formations

The basic principle associated with all subterranean methods of storing CO2 is that it isstored in a geological structure which contains it and prevents short-term or medium

term release to the atmosphere. The structure must consist of a permeable layer, to allowingress of CO2 and an impermeable or low-permeable layer to prevent escape of CO2 tothe atmosphere. Geological sinks for CO2 include deep saline formations, depleted oil

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and gas reservoirs, and deep coal seams that are dispersed worldwide. Together, thesecan hold hundreds to thousands of gigatons of carbon (GtC), and the technology toinject CO2 into the ground is well established (18). CO2 injection into geologicalformations for enhanced oil recovery (EOR), is a mature technology (22). In 1998,around 43 million metric tons of CO2 per year were injected at 67 commercial EOR

projects in the United States (18).

Sequestration in deep saline formations or in oil and gas reservoirs is achieved by acombination of three mechanisms: displacement of the in situ fluids by CO2, dissolutionof CO2 into the fluids, and chemical reaction of CO2 with minerals present in theformation to form stable, solid compounds like carbonates. Displacement dominatesinitially, but dissolution and reaction become more important over time scales ofdecades and centuries (18).The most significant international project demonstrating the viability of CO2sequestration is the Sleipner Project, which started up in 1996. The Sleipner oil and gasfield, operated by Statoil, is located in the North Sea about 240 km off the coast of

Norway. To meet commercial specifications, the natural gas from this field needs to

reduce its CO2 concentration from about 9% to 2.5%. This is a common practice at gasfields worldwide in which the CO2 captured from the natural gas is vented to theatmosphere. At Sleipner, however, CO2 is compressed and pumped into a 200-m-thicksandstone layer, the Utsira Formation, which lies about 1000 m below the seabed(Figure 10). About 1 million metric tons of CO2 (equivalent to about 3% of Norwaystotal annual CO2 emissions) have been sequestered annually (18).

Abandoned, un-economic coal seams are another potential storage site. CO2 diffusesthrough the pore structure of coal and is physically adsorbed to it. This process issimilar to the way in which activated carbon removes impurities from air or water. CO2can also be used to enhance the recovery of coal bed methane (18) In some cases, this

can be very cost-effective or even cost-free, as the additional methane removal canoffset the cost of the CO2 storage operations.

2.3 An overview of EU activities on CO2 capture and sequestration

An overview of International collaborative projects and activities in the field of CO 2capture and sequestration worldwide is given at www.ieagreen.org.uk. Japan isregarded as having the largest and longest running carbon capture and sequestrationtechnologies research program (18). A highlight of their program is the ResearchInstitute of Innovative Technology for the Earth (RITE, see at

http://www.rite.or.jp/English/E-home-frame.html ). Recently, the U.S. DOE increasedits carbon capture and sequestration research budgets including a broad range oftechnologies in its portfolio. Its Vision 21 program is designed to possess thescientific understanding of carbon sequestration and to develop to the point ofdeployment those options that ensure environmentally acceptable sequestration toreduce anthropogenic CO2 emissions and/or atmospheric concentrations (seewww.netl.doe.gov/products/gcc/indepth/carbseq/seq_ind.htm for more information).

In January 2001 was published the sixth environment action program of the EuropeanCommunity Environment 2010: Our future, Our choice (2). The Commission calls inthis document for far-reaching global emission cuts after Kyoto time scales, in the order

of 20-40 % by 2020 and up to 70 % in the longer term compared to 1990. In the reportfrom the European Climate Change Programme in June 2001 one of the proposed

http://www.ieagreen.org.uk/http://www.rite.or.jp/English/E-home-frame.htmlhttp://www.netl.doe.gov/products/gcc/indepth/carbseq/seq_ind.htmhttp://www.netl.doe.gov/products/gcc/indepth/carbseq/seq_ind.htmhttp://www.netl.doe.gov/products/gcc/indepth/carbseq/seq_ind.htmhttp://www.rite.or.jp/English/E-home-frame.htmlhttp://www.ieagreen.org.uk/

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actions recommended to achieve major GHG reduction in Europe is CO2 capture andsequestration (2,3).Major active projects in Europe are mainly being focused on the sequestration side. TheEU funded SACS project, leaded by Statoil, has become the world demonstrationexample of how CO2 sequestration can be made real. The SACS project, was

established to monitor and research the storage of CO2 in the unique facility of theSleipner field in Norway. GESTCO is another major effort on the field of CO2sequestration assessing the potential for geological storage in Europe that has receivedfunding under the Fifth Frame Work Programme (EESD). NASCENT is another EESD

project aimed to learn from natural analogues where CO2 is stored in the geologicalenvironment. There is also an European component in the Weyburn project in Canada(see at www.ieagreen.org.uk.). Finally, some projects are under negotiation in theEESD and ECSC programmes that include a renewed interest on the capture side (seeat http://www.cordis.lu/eesd ).

The SACS and GEUS projects, together with the IEA Greenhouse Gas Programme, and

Technology Initiatives in the UK have gained support from the EESD Programme todevelop a Thematic Network on CO2 Capture and Sequestration (CO2NET). At the timeof writing, twenty nine different organisations in nine European countries have joinedthe existing partners as founder members to develop the Thematic Network. Differentagencies from EU member countries are running their own National Programmes oncapture and sequestration and these are also aimed for further integration underCO2NET2.

http://www.ieagreen.org.uk/http://www.cordis.lu/eesdhttp://www.cordis.lu/eesdhttp://www.cordis.lu/eesdhttp://www.ieagreen.org.uk/

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Part 2

CASE STUDIES

3. Techno-economic characterisation studies

3.1 The cost of CO2 sequestration

As mentioned above, most plausible scenarios accept that fossil fuels will remain as themain source of energy well into the 21st century. They supply today over 85% of theworlds energy needs. They have been a major contributor to the high standards ofliving enjoyed by the industrialised world. In the power generation sector, the cost of

producing electricity keeps falling even with stringent pollution controls on NOx, SO2,unburned hydrocarbons, and particulates (8-10).

If the CO2 sequestration option was finally accepted by society as a practical solution tomitigate global warming, the economic considerations would be the only criteria tochoose between the different options for mitigation of greenhouse gases. Despite therelative novelty of these concepts and the lack of full demonstration sites with realeconomic data, there is considerable bibliography on costs associated with differentCO2 sequestration options.

Recent comprehensive reviews and economic studies for capture and zero emissions

power plants have been published by the IEA GHG programme (http://www.ieagreen.org.uk ) and the MIT Sequestration Initiative (http://sequestration.mit.edu). Upto date overview of power generating costs for advance cycles have also been compiledand made available by DOE (23). The IEA Coal Research has also published a generalreview of technoeconomic parameters relevant for capture and sequestration of CO2from coal utilisation (13). Finally, several papers were presented at the latest GHGT-5and GHGT-4 Conferences from companies with specific interest on full scale CO2sequestration projects in the short and medium terms. These reviews and updates arerevisited in the following section to supply the information needed to quantify thegeneral technoeconomic parameters for the IPTS database.

It is essential that all CO2 control options are compared on a consistent basis. Thisrequires the development of standard data reporting and comparison in the form ofreference cases. The commercial technologies must be clearly separated fromdeveloping advanced technology. In particular, this is because cost and performance

projections for advanced technologies are commonly too optimistic compared to theiractual cost and performance once commercialised (13,23). Advances in commercialtechnologies with time as a result of continuous and small improvements in

performance and cost savings need to be estimated as well.

Before entering in details, it is worthwhile understanding why CO2 separation and

capture is still regarded by many in the energy sector as expensive. Reasons includesome common sense statements (8):

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It will always be more expensive to sequester CO2 than to just emit it to theatmosphere.

Most studies show that the bulk of the cost in sequestering power plant CO 2 are dueto separation and capture (including compression) as opposed to transport andinjection.

The main separation process (commercial and in operation) based on MEAs is old

and has never been optimised for large scale capture from power plants. The basis of design is very different for plants producing CO 2 for commercial

markets as compared to plants producing CO2 for sequestration. This relates to thedifference between the cost of capture and the cost of avoidance, as discussed

below.

As stated by Herzog (8), the primary difference in capturing CO2 for commercialmarkets versus capturing CO2 for sequestration is the role of energy. In the former case,energy is a commodity, and all we care about is its price. In the latter case, using energygenerates more CO2 emissions, which is precisely what we want to avoid. Therefore,capturing CO2 for purposes of sequestration requires more emphasis on reducing energy

inputs than the traditional commercial process (8).

Figures 11 helps to define the difference between CO2 captured and CO2 avoided andthe concept of the energy penalty. With equal fuel inputs in both the reference andcapture plants, the power output of the capture plant will always be less than the poweroutput of the reference plant, because of the energy requirements for separating andcompressing the carbon dioxide. Equally, if both power plants are requested to producethe same amount of electricity, the capture plant will be consuming more fuel tocompensate the energy and efficiency penalties associated with the capture process. Insummary, the emission reduction of carbon dioxide needs to be compared with the

original emissions from the power plant without capture as shown in Figure 11.

3.2 Niche markets for CO2 sequestration

Recycling or reuse of CO2 emitted or captured from power plants would seem to be anattractive alternative to the disposal options discussed in the two preceding sections.However, the problem is finding enough uses to sequester a significant amount of theCO2 generated. The total industrial use of CO2 in USA is about 40 million tonnes peryear but this is only about 2% of the produced annually from power plants (8). About80% of this CO2 is used in enhanced oil recovery (EOR) and is supplied from CO2 gaswells at prices much cheaper than power plant CO2. The use of CO2 in enhance coal bed

methane operations is also regarded as a potentially competitive mitigation option inEurope and abroad (8,12). Figure 12 is an scheme of these operations.

There are numerous specific opportunities to reuse CO2 in industrial processes, andcertain processes such as ethylene and ammonia production produce high concentrationCO2 streams that are often currently released to the atmosphere. The standard way of

producing hydrogen today is through steam reforming of methane which can beregulated to produce a CO2 /H2 mixture which is easily separable. This CO2 could besequestered or utilised in another process. With increasing interest in the use ofhydrogen as an energy carrier and fuel in the future, this CO2 source is likely to growand create an opportunity for additional mitigation (8). Refineries, especially those that

use heavier crudes, can also provide some opportunities for CO2 capture (31). TheSleipner project by Statoil is another example of large scale production of almost pureCO2 as a byproduct because the need for purification of the natural gas to make it of

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commercial quality (13,18). In these examples the mitigation cost can be associatedonly to the compression and disposal component. Therefore they are prime targets todemostrate geological sequestration concepts.

New applications might be found if further research is done on interesting potentialreaction pathways. However, since CO2 is a very stable molecule, considerable energy is

required to transform it into products. The industrial sector still has only very limitedcapacity for utilisation of the large quantities of CO2 that are generated by the powersector (8, 9).

4. Reviewed case examples in IPTS format

In the following sections specific case applications extracted from leading studiespublished in the open literature are surveyed. Criteria for selection of the case studiesare discussed in each case as well as the relative uncertainties and discrepancies inresults between the different works. Each section is concluded with the Table of

Techno-economic parameters in the IPTS format for each case study.

Five case studies have been selected. As mentioned above, power generation in theworld mainly relies on the burning of fossil fuels (mainly coal and natural gas) in air,so the capture of CO2 after combustion approach outlined in section 2.1.1 will bestudied for both coal-fired simple cycle power plants (PC) and natural gas-firedcombined cycles (NGCC) in cases 4.1 and 4.2. Another case study will focus on thesubstitution of air by a mixture of CO2 /O2 in a PC power plant (case 4.3). Finally two ofthe most promising concepts for coal and natural gas, based on gasification(for coal)and the shift reforming of the fuel gas towards CO2 and H2 are analysed (cases 4.4 and4.5).

There is large number of variables that affect the overall-technoeconomic parameters ofeach case study. Their detailed analysis is far beyond the objective of this survey.However most of these variables characterising the performance of a particular capture

process can be grouped on the following three main parameters (24,25):

The availability, or number of operating hours per year.

The capital charge rate (r), in % per year. It is used to annualise the capitalinvestment of the plant and can be roughly correlated to the cost of capital.Specifically, the capital component of the cost of electricity equals the capital

charge rate times the capital cost divided by the number of operating hours per year. The fuel cost (FC), defined on the lower heating value (LHV).

The individual studies reviewed may use different values for each of these threeparameters. Consequently, the results that can be obtained differ from each other notonly because of technological variations amongst the processes, but also because of theeconomic assumptions. Figure 12 is an example to illustrate the variability to theseassumptions of one of the key parameters used to characterise mitigation option: thecost per ton (Mg) of CO2 avoided, as defined in Figure 12. As can be seen in this Figure,the estimated costs of avoidance of CO2 can nearly double within a reasonable range ofvalues for these parameters. Therfore, it is obvious that to compare the technologies

evaluated by each study and the attractiveness of the capture at different types of powerplants, the original studies should be adjusted to a common economic basis. Thisinformation is fully available for three of the case studies in the work of Davis (25) at

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the MIT. For the two remaining cases an attempt is made to follow consistent criteriawith those used by the MIT group who set the following additional reference data(rewritten in Euro and kilowatt-hour assuming 1EUR =0.9 $, 1 kWh= 3412 BTU):

Availability: 6570 h/a (75%)Capital charge rate: 15%/year

Coal price (LHV): 0.00471 EUR/kWhGas price (LHV): 0.0111 EUR/kWh

Other parameters that also affect cost-estimates are similar in most of the studiesreviewed (CO2 capture efficiencies between 80-96% and electric output of the referencecases between 400-600 MW) and therefore they affect less the costs estimates per unitof energy produced or used.

The final choice of technoeconomic parameters from the example provided by IPTSand the available information in the literature surveyed is as follows, for each casestudy:

Availability factor. This is the fraction of time that the plant can be operated on ayearly basis (considering both planned and un-planned outages)

Capacity factor. This is understood as the average fraction of power being producedrespect to the maximum power output of the plant.

Fuel efficiency (kWh/kWh). This is the power output of the plant respect to the fuelenergy input (calculated on LHV).

Forced outage rate. This is an estimate of the fraction of time without operating theplant due to unforeseen causes.

Gross capaciy (MW). Power output (as electricity in all the cases considered in this

survey) Technical lifetime (a).

Construction time (a)

Economic life time (a)

Specific capital cost. EUR/kW.

Specific variable operating costs, EUR /kW a

Emission Factor during operation: SO2, kg/TJe Emission Factor during operation: NOx, kg/TJe Emission Fact. during op.: particulates, kg/TJe Emission Factor during operation, no capture: CO2, kg/TJe Emission Factor during operation, after capture: CO2, kg/GJ

e Cost of CO2 avoided. EUR /kg of CO2 avoided:

Cost of electricity production, no capture: EUR/kWhe Cost of electricity production, after capture: EUR/ kWhe

Prices are also referred to a common base and they were adjusted by David (24) in thefirst 3 cases. Finally, all the cost calculations include the cost of conditioning the CO 2 toa pressure of between 100 and 150 atm. The cost for disposal is not included. This canadd between 10-15 Euro/ton CO2 to the cost of capture (15, 18). Potential economic

benefits from the use of CO2 in operations such as EOL and ECBM are not consideredin this survey. Obviously, they can substantially reduce or even overcome the costs of

capture

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4.1 Case 1. Coal PC plant with flue gas absorption with MEAs

Today, simple cycle pulverised coal (PC) combustion plants still account for most of theelectricity generation worldwide. The widespread availability of coal, the continuousreductions in capital costs, the increasing efficiencies (towards higher steam conditions)

and the availability of cost-efficient SO2 and NOx control technologies guaranty thatcoal PC boilers will play an important role for many years in the world energy

production sector. Pulverised coal is combusted with air in a coal-fired boiler to producehigh-pressure steam, that is used for power generation in a steam turbine. The flue gasexiting the boiler is passed through a heat exchanger to heat up the air going into the

boiler, a desulfurisation unit to remove SO2, and, finally, a stack. The selected captureplant has an amine (MEA) absorption CO2 removal unit that follows the desulfurisationFGD unit. The following studies were reviewed and put in a comparable format byDavis (24):

University of Utrecht, Netherlands (Hendriks, 1994, from ref. 24);

EPRI (Smelser et al., 1991; Booras and Smelser, 1991, from ref. 24); SFA Pacific (Simbeck, 1999, from ref. 24);

IEA (Stork Engineering Consultancy, 1999, from ref. 24);

The IEA study is based on a PC plant for which the steam cycle is super-critical. Table2 shows how the economics of the capture processes at PC plants compare across thedifferent studies reviewed before adjustment. These studies have also been the basis forthe review by IEA Coal Research (13). The studies are then adjusted to a commoneconomic basis as defined above. Table 3 shows how the economics of the capturecompare across the different adjusted studies (24). The average incremental electricity

cost at a PC capture plant after adjustments is 3.9 cEUR/kWh and the averagemitigation cost 57.8 EUR/ton of CO2 avoided. This is for plants with nets power outputsof 400-600 Mwe. The energy penalty varies from 15.9% up to 34.1% (24). These

parameters are also projected to year 2012 using a composite model to analyse thesensitivity of these figures to key cost parameters (24,25). We have assumed a linearincrease of the technoeconomic parameters to estimate 2000 and 2010 projections in theIPTS format (Table 4). Emission factor for CO2 is calculated assuming a 90% collectionefficiencies. The emission factors for other pollutants are assumed to be under the limitsof foreseeable emissions in advanced reference cases of PC plants without CO 2 capturecompiled in reference (23) by the US DOE.Also note that the original O&M is broken down into a fixed cost (65%) and a variable

cost (35%). This assumption relies on the EPRI studies analysed (24) which estimatethe fixed portion of operation and maintenance costs to be 65% of the total O&M costs.The fuel cost is added to the variable O&M costs to estimate the final set of parametersin IPTS format.

4.2 Case 2.Natural Gas Combined Cycle CO2 absorption with MEAs

The review of this case study has also received considerable attention in the literature.The Natural Gas Combined Cycles (NGCC) represent an available technology that

produces less carbon dioxide per energy output than IGCC and PC power plants. Thecarbon content per unit of energy in coal is typically 2.5 times that of natural gas. In

addition NGCC have the highest thermal efficiency of all the options, which makescarbon emission factors go below 50% of those of a coal-based power plant producingthe same amount of electricity. Natural gas is combusted in a gas turbine with air. To

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keep the turbine inlet temperature at a permissible level, a high overall excess air ratioin the gas turbine is needed, which can lower the CO2 concentration in the flue gases

below 4% in volume. Waste heat is then recovered in a heat recovery steam generatorto drive a steam turbine generator for additional power generation. The capture plantconsidered in this case example has an amine absorption CO2 removal unit that followsthe heat recovery step.

The following four detailed studies were reviewed by Davies (24) at the MIT, who putin a consistent and comparable basis with identical methodology as in case 4.1, thefollowing studies:

SFA Pacific (Simbeck, 1999, from ref. 24);

Trondheim (Bolland and Saether, 1992, from ref. 24);

IEA (Stork Engineering Consultancy, 1999, from ref. 24);

Politecnico di Milano, Italy (Chiesa et Consonni, 1999, from ref. 24).

The study from Politecnico di Milano and the IEA report from the Stork Engineering

Consultancy compare the conventional combined cycles (which have a CO2 chemicalabsorption ahead of the stack) with similar combined cycles for which part of theexhaust gases is recycled to the gas turbine compressor. This recycle reduces the flowrate of exhaust gases to be treated and increases the CO2 concentration; hence, capitalinvestments and steam consumption in the stripper can be lowered. According to theMilan and IEA studies, the scheme with recycling is slightly more advantageous to theeconomics of the capture than the base scheme; the incremental cost of electricity isclaimed to be reduced by about 10% and 15%, respectively. Nevertheless, to avoidtechnical variations between the four NGCC power plants studied, these combinedcycles with flue gas recycling were not further investigated; they illustrate, however,

that innovation in power generation can contribute to improve the economics of CO2capture (24).

Table 6 shows how the economics of the capture processes at NGCC plants compareacross the different adjusted studies (24). The average incremental electricity cost at a

NGCC capture plant after adjustments is 1.77 cEUR/kWh and the average mitigationcost 57 EUR/Mg of CO2 avoided. The energy penalty varies from 9.8% up to 16.1%.

These figures have been translated to the IPTS format (Table 7) as in the previoussection. Date for other emission have been obtained from the DOE review on market-

based coal technologies (23) and it is assumed that the capture plant does not affect

these levels of emissions.

4.3 Case 3. Oxygen blown IGCC with absorption

Integrated gasification combined cycles (IGCC) are regarded by many as the short andmedium term solutions to boost the efficiencies and environmental performances of coal

based power generation systems. Despite several ongoing demonstration and somefully commercial projects around the world, IGCC is regarded as an emergingtechnology. It has received considerable attention in the capture/sequestration studies

because, as will be seen below, it is particularly well suited for highly efficient optionsfor CO2 capture at low relative cost respect to the reference plants without capture. This

is mainly because in these cases the reference plant includes the costs associated withthe air separation unit (ASU).

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In the IGCC system used as a reference case study, coal is first converted in an oxygen-blown gasifier into synthesis gas. The syngas is then used to drive a gas turbine. Finally,waste heat is recovered to drive a steam turbine for additional power generation. In thecapture plant there is an additional unit for the shifting of the syngas to CO2 and H2followed by the removal of CO2. Because the syngas is under pressure, it is possible touse physical solvents, which need less energy for regeneration than chemical solvents.

Desorption of CO2 is followed by compression and drying.

The following studies studying the economics of capture option in IGCC systems werereviewed by David (24) and David and Herzog (25) and their main parameters arecompiled in Table 8:

Argonne National Laboratory (Doctor et al., 1997, from ref. 24);

Politecnico di Milano, Italy (Chiesa et al., 1998, from ref. 24);

SFA Pacific (Simbeck, 1998, from ref. 24);

University of Utrecht, Netherlands (Hendriks, 1994, from ref. 24);

EPRI (Condorelli et al., 1991, from ref. 24);

IEA (Stork Engineering Consultancy, 1999, from ref. 24).

All of these studies consider oxygen-blown gasification, and absorption by a physicalsolvent (Selexol). The Argonne study points out that a reference plant is moreeconomical if gasification is air-blown rather than oxygen-blown, but it demonstratesthat it is more economical to use oxygen-blown rather than air-blown gasification forthe capture. The studies are then adjusted to a common economic basis, as defined inthe previous paragraphs and in the original reference (24). Table 9 shows how theeconomics of the capture processes at IGCC plants compare across the different studiesonce adjusted. Table 10 shows how the economics of the average IGCC plant once

transformed to the IPTS format from averaging data form Table 9 (24). The averageincremental electricity cost at an IGCC capture plant after adjustments is 1.91cEUR/kWh and the average mitigation cost 30 EUR/ton of CO2 avoided. The energy

penalty varies from 6.4% up to 21.4% (24). The data on plant emissions other that CO2are obtained from the estimates by the US DOE (23) for an advance oxgen blown IGCC

plant. It is assumed that the capture plant does not affect these emissions, althoughpotential for a zero emissions power plant clearly exists with these concepts asmentioned in section 2.1.4.

4.4 Pulverised coal fired with O2/CO2

As mentioned in previous paragraphs and section 2.1.2 a different approach to reducethe cost of gas separation is to increase the concentration of CO2 in the flue gas. Thiscan be achieved by increasing the concentration of oxygen in the feed gas andeventually by recirculating part of the flue gas. In principle, coal combustion at higheroxygen concentration is also attractive because it can increase combustion efficienciesand reduce the size of flue gas treatment units (26).

The following list of references have been considered to compile the relevant economicdata from the recent published studies on this option:

CCU (Okawa et al, 1999 reference 27)

SFA Pacific (Simbeck, 1999, reference 28 ) Univ. of Essen (Gttlicher et al, 1999, reference 16)

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Except in the work by Simbeck (28) it has not been possible to extract the necessaryinformation to put the different studies in a comparable basis as in section 4.1-4.3.Therefore only this work has been selected for this purpose, leaving the rest of works asa reference to support some on the chosen values that represent this option. Table 10includes the raw data from the original reference (28) and the update of data resultingfrom the application of a proportionality rule to the adjusted data by David (24) on the

reference plant without capture, which should be identical to the case 4.1 of Simbeck.

Table 11 includes the final set of parameters in IPTS format for this case. Both he costof mitigation and electricity are roughly consistent with those reported by Gotlinger etal (16) and others reviewed by Smith (IEACR, ref 13). All the cost estimates are for anew plants, design and built to integrate the capture process. Retrofitting of existing

plants are substantially more expensive when comparing mitigation costs (29).

The use of CO2/O2 mixtures to burn natural gas in combined cycles has also beenextensively studied (17, 30-31) and their developers claim much higher efficiencies andlower costs that for the case in 4.2. However, the detailed economic studies, are more

scarce for these options and have not been included as cases studies.

4.5 Decarbonisation of natural gas integrating a NG reformer and CO2 absorber

This case study corresponds to the main process outlined in section 2.1.3. The mostrecent and relevant studies comparing CO2 capture options (9,14,15,29,30,32) considerthis option as one of the most promising leading options to provide high efficiency useof natural gas in a combined cycle integrating CO2 capture. Although many questionsremain to be investigated and optimised, no major technological barriers are envisaged.

Natural gas reforming is a commercial process in, for example, ammonia production.Burning of H2 in a gas turbine is under strong development by at least two turbine

manufactures (9).

The following list of references have been considered to compile the relevant economicdata from the recent published studies on this option:

SFA Pacific (Simbeck, 1999, reference 28 )

Hustad (Hustad, 2000, reference 30)

IEA GHG (Audus, 2000, reference 15).

As in the previous case, the need for a reference case comparable with the economic

and technical basis used in section 4.1-4.3, has put the emphasis on the work bySymbeck (28), that has been adjusted in Table 12 to match the reference case of aNGCC used in section 4.2. Economic estimates for the cost of electricity and mitigationcosts from Symbeck are much higher than those recently reported by Hustad andAudus. However, this can be largely due to the economic assumptions on capitalcharge rates (15% vs 8 and 10%) and fuel costs (75% more expensive in the study bySimbeck). To be consistent with the data in Tables 4,7,10, 12. The numbers in Table 14for the year 2000 have been estimated with the same assumption that the previous cases(see first paragraphs in section 4 and David (24)). The final results in Table 14 showthat this option is in fact comparable with the previous case studies under theassumptions adopted for the column of year 2000. However, the scope for cost

reduction and efficiency gains is much higher when using roughly similar criteria thatHustad (30) to estimate the parameters for the year 2010.

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Other technical options affecting the steps related to the natural gas reforming, havebeen analysed recently in detail by Symbeck (28-29) and Hustad (30). Some of themresult in further reduction of costs of electricity and mitigation of CO2 in 10-20%.Recognising the potential advantages of these cycles, intense research is being devotedto demonstrate the main concepts, and this is partially promoted by the IEA GreenhouseProgramme (see at www.ieagreen.org.uk).

5. References

1. "Climate Change 2001: The Scientific Basis". Intergovernmental Panel on ClimateChange, Technical Summary of the Working Group I Report. D L Albriton, L GMeira Filho et al. 2001, available at: www.ipcc.ch/pub/wg1TARtechsum.pdf

2. Environment 2010: Our Future, Our Choice The Sixth Environment ActionProgramme of the European Community 2001-2010, available at:http://europa.eu.int/comm/environment/newprg/index.htm

3. European Climate Change Programme. Report June 2001. Available at:

http://europa.eu.int/comm/environment/climat/eccp_longreport_0106.pdf4. "Climate Change 2001: Impacts, Adaptation and Vulnerability". Intergovernmental

Panel on Climate Change, Technical Summary of the Working Group II KD Whiteet al. 2001, available at: http://www.ipcc.ch/pub/wg2TARtechsum.pdf

5. Climate Change 2001: Mitigation". Intergovernmental Panel on Climate Change,Technical Summary of the Working Group III Report. Filho et al. 2001, available at:www.ipcc.ch/pub/wg1TARtechsum.pdf

6. Marland, G., T.A. Boden, and R. J. Andres. 2001. Global, Regional, and NationalCO2 Emissions. In Trends: A Compendium of Data on Global Change. CarbonDioxide Information Analysis Center, Oak Ridge National Laboratory, U.S.Department of Energy, Oak Ridge, Tenn., U.S.A. Available at:

http://cdiac.esd.ornl.gov7. Luo Y, Wan S, Hui D, Wallace L. L. Acclimatization of soil respiration to warming

in a tall grass prairie.Nature. vol 413, 622, 11 October 2001.8. Herzog, H.; Drake, E.; Adams, E. CO2 Capture, Reuse, and Storage Technologies

for Mitigating Global Climate ChangeA White Paper; DOE 9 of 10 EST: WhatFuture for Carbon Capture and Sequestration? Order No. DE-AF22-96PC01257;U.S. Government Printing Office: Washington, DC, 1997, available at:http://sequestration.mit.edu/bibliography

9. Davidson J., Freund P., Smith A. Putting Carbon Back in the Ground. IEAGreenhouse Gas R&D Programme, Cheltenham. UK, February 2001

10.U.S. Department of Energy. Carbon Sequestration Research and Development;DOE/SC/FE-1; U.S. Government Printing Office: Washington, DC, 1999 (availableat www.ornl.gov/carbon_sequestration).

11.Goldthorpe S, Davison J, Capture of CO2 using water scrubbing,Proceedings of theFifth International Conference on Greenhouse Gas Control Technologies. D.Williams et al. (Editors). Cairns, Australia. CSIRO, 2000

12.Herzog, H.; Eliasson, B.; Kaarstad, O. Capturing Greenhouse Gases. Sci. Am. 2000,282 (2), 7279.

13.Smith I M,. CO2 reduction, prospects for coal. IEA Coal Research. CCC-26. Dec1999.

14.Audus H, Technologies for CO2 Emission Reduction. IEA Greenhouse Gas &D

Programme 1999. Available at www.ieagreen.org.uk

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15.Audus H., Leading options for the capture of CO2 at power stations. InProceedingsof the Fifth International Conference on Greenhouse Gas Control Technologies. D.Williams et al. (Editors). pp 91. Cairns, Australia. CSIRO, 2000

16.Gttlicher G., Prusheck R. Analysis of development potentials for power stationswith CO2 removal/concentration. in Greenhouse Gas Control Technologies;Eliasson, B., Reimer, P., Wokaum, A., Eds.; Elsevier Science: New York, 1999.

pp8317.S. Houyou, P. Mathieu and R. Nihart. Techno-Economic Comparison of Different

Options of Very Low CO2 Emission Technologies. In Proceedings of the FifthInternational Conference on Greenhouse Gas Control Technologies. D. Williams etal. (Editors). pp 1003. Cairns, Australia. CSIRO, 2000

18.Herzog, H.. What Future for Carbon Capture and Sequestration?. EnvironmentalScience and Technology, 35:7, pp 148 A153 A, April 1, 2001

19.C. Schmidt and D. Beecy . Overview of the U.S. Carbon Sequestration Program InProceedings of the Fifth International Conference on Greenhouse Gas ControlTechnologies. D. Williams et al. (Editors). pp 1044. Cairns, Australia. CSIRO,2000.

20.Lyngfelt A.,Leckner B.,Mattisson T. A fluidized-bed combustion process withinherent CO"2 separation; application of chemical-looping combustion. Chemical

Engineering Science. pp 3101-3113. 56 (10) May 2001.21.Ormerod W G, Freund P. and Smith A. Ocean Storage of CO2. IEA Greenhouse

Gas R&D Programme, February 1999. Availble at: http://www.ieagreen.org.uk22.Stevens, S. H.; Gale, Sequestration of CO2 in Depleted Oil & Gas Fields: Global

Capacity, Costs and Barriers In Proceedings of the Fifth International Conferenceon Greenhouse Gas Control Technologies. D. Williams et al. (Editors). pp 278.Cairns, Australia. CSIRO, 2000

23.U.S. Department of Energy. Market-Based Advanced Coal Power Systems. FinalReport. Office of Fossil Fuels.DOE/FE-0400, p374, May 1999. Available at:

http://www2.fossil.energy.gov/coal_power/special_rpts/market_systems/market_sys.shtml

24.David, J. Economic Evaluation of Leading Technology Options for Sequestration ofCarbon Dioxide, M.S. Thesis, Massachusetts Institute of Technology, Cambridge,MA, 2000 (available at http://sequestration.mit.edu/bibliography) .

25.David, J. and H. Herzog. The Cost of Carbon Capture. In Proceedings of the FifthInternational Conference on Greenhouse Gas Control Technologies. D. Williams etal. (Editors). pp 985. Cairns, Australia. CSIRO, 2000.

26.Croiset E., Thambimuthu K.V., Coal combustion with flue gas recirculation forCO2 recovery. in Greenhouse Gas Control Technologies; Eliasson, B., Reimer, P.,

Wokaum, A., Eds.; Elsevier Science: New York, 1999. pp58127.Okawa M, Kimura N, Kiga T, Yamada T, Amaike S. CO2 abatement investigationusing O2/CO2 combustion and IGCC. in Greenhouse Gas Control Technologies;Eliasson, B., Reimer, P., Wokaum, A., Eds.; Elsevier Science: New York, 1999.

pp575.28.Simbeck D, A portfolio selection approach for power plant CO2 capture, separation

and R&D options. in Greenhouse Gas Control Technologies; Eliasson, B., Reimer,P., Wokaum, A., Eds.; Elsevier Science: New York, 1999. pp119.

29.Simbeck D.R. , McDonald M. Existing Coal Power Plant Retrofit CO2 ControIOptions Analysis In Proceedings of the Fifth International Conference onGreenhouse Gas Control Technologies. D. Williams et al. (Editors). pp 103. Cairns,

Australia. CSIRO, 200030.Hustad C.W., Review over Recent Norwegian Studies Regarding Cost of Low CO 2

Emission Power Plant Technology In Proceedings of the Fifth International

http://www.ieagreen.org.uk/http://www2.fossil.energy.gov/coal_power/special_rpts/market_systems/market_sys.shtmlhttp://www2.fossil.energy.gov/coal_power/special_rpts/market_systems/market_sys.shtmlhttp://www2.fossil.energy.gov/coal_power/special_rpts/market_systems/market_sys.shtmlhttp://sequestration.mit.edu/bibliography)http://sequestration.mit.edu/bibliography)http://sequestration.mit.edu/bibliography)http://www2.fossil.energy.gov/coal_power/special_rpts/market_systems/market_sys.shtmlhttp://www2.fossil.energy.gov/coal_power/special_rpts/market_systems/market_sys.shtmlhttp://www.ieagreen.org.uk/

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Conference on Greenhouse Gas Control Technologies. D. Williams et al. (Editors).pp 1295. Cairns, Australia. CSIRO, 2000.

31.Wilkinson M.B., Boden J.C., Panesar R.S. and Allam R.J. A Study on the Captureof Carbon Dioxide from a Large Refinery Power Station In Proceedings of the Fifth

International Conference on Greenhouse Gas Control Technologies. D. Williams etal. (Editors). pp 179. Cairns, Australia. CSIRO, 2000.

32.Simbeck D. Update of New Power Plant CO2 Control Options Analysis InProceedings of the Fifth International Conference on Greenhouse Gas Control

Technologies D. Williams et al. (Editors). pp 193. Cairns, Australia. CSIRO, 2000.

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FIGURES

Figure 1. Deviations of average temperatures in the northern hemisphere respect to the averagein the 1961-1990 period. (from ref 1).

Figure 2. Records of change in atmospheric concentration of CO2 from differnt sources. (see ref1 for details).

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Figure 3. Evolution of the global CO2 emmisions from anthopogenic sources (see ref 6 fordetails).

Figure 4. The global carbon cycle and the main carbon flows (from ref. 6)

0

1000

2000

3000

4000

5000

6000

7000

1850 1875 1900 1925 1950 1975 2000

Year

Millionmetrictonso

fcarbo

TotalGasLiquidSolidFlaring

Cement

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Figure 5. Orders of magnitude of global sequestration capacity of CO2 (from ref. 8 and 18).A: Anthropogenic emissions (Gt/a); B: Coal seems; C: Oil and gas reservoirs; D: Deepaquifers; D: Oceans

Figure 6. Capture of CO2 from combustion flue gases using an absorption process (section2.1.1)

Air

Combustiongases

N2,O2,H2O, etc

Sorbent

Sorbent + CO2

Regeneration

Heat

CO2

Combustor

100

10.000

A B C D E

7

Gigatonsofca

rbon.

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Figure 7. Combustion of coal with O2/CO2 to produce flue gases suitable for sequestration(section 2.1.2)

Figure 8. The production of hydrogen from coal, integrating capture of CO2 before combustion(section 2.1.3)

Combustor

CO2 for

disposal

H2O, O2

CO2N2

Air

ASU

O2

Purification

CO2

Coal

Oxygen

GasifierSulphur

Removal

Shift

Conversion

CO2

Capture CO2 toStorage

H2 RichFuel GasSlag

N2 , O2 , H2O

to Atmosphere

Steam

Generator

Air Gas

Turbine

Steam

Turbine

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Figure 9. An scheme of CO2 storing options in the oceans (from ref. 12)

Figure 10. CO2 sequestration at Sleipner field in Norway (from ref. 9)

1000 m

2000 m

3000 m

4000 m

1

2

3

4

53

5

H2O

Disolution Dispersion Isolation

1.- Droplet plume 3.- Dry ice 5.- CO

2

lake

2.- Dense plume 4 .- Towed pipe

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Figure 11. The difference between CO2 captured and avoided (from ref. 8)

Figure 12. An schematic representation of Enhanced Oil Recovery (EOR) applications wherethere is an added benefit to CO2 sequestration.(similar scheme for forharced coal bed methane).

0 0.2 0.4 0.6 0.8 1

Emitted

Captured

CO2 Produced (kg/kWh)

Reference

Plant

Capture

Plant

CO2 avoided

CO2 captured

CO2 Miscible

Zone OilAdditional

Oil Recovery

CO2 Inyection

OilProduction

well

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Figure 13. The effect of capital charge rate and fuel costs on the main technoeconomicparameters for a Natural Gas Combined Cycle (1300, 700 /kw capital costs with and withoutcapture, O&M costs assumed to be 4%, efficiencies 50 and 60% (LHV) and 0.75 avalability)

30

35

40

45

50

55

60

65

70

0,05 0,07 0,09 0,11 0,13 0,15

Capital charge rate

/MgCO2avoided

2 /GJ

4 /GJ

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TABLES

Table 1. Estimates by the IPCC of potential greenhouse gas emission reductions in the 2010 to2020 timeframe (***) includes fuel switching, efficiency gains, renewables and carbon captureand sequestration, see ref. 5 for details).

Table 2. The economics of the capture processes at PC plants using absorption, comparedacross the different studies reviewed at the MIT (24) before adjustment. Data in bracketscorrespond to the reference plant without capture.

Sector Greenhousegas

Historicemissionsin 1990(MtCeq/yr)

Historic Ceqannualgrowth rate in1990-1995(%)

Potencialemissionreductions in2010(MtCeq/yr)

Potencialemissionreductions in2020(MtCeq/yr)

Buildings CO2 only 1.650 1.0 700-750 1.000-1.100

Transport CO2 only 1.080 2.4 100-300 300-700

Industry-energy efficiency-material efficiency

CO2 only 2.300 0.4300-500

~200700-900

~600

Industry Non CO2 gases 170 ~100 ~100

Agriculture CO2 only

Non CO2 gases

210

1.250-2.800

n.a.

150-300 350-750Waste CH4 only 240 1.0 ~200 ~200

Montreal protocolreplacementapplications

Non CO2 gases 0 n.a. ~100 n.a.

Energy supply andconversion (***)

CO2 only (1.620) 1.5 50-150 300-700

Technoeconomic parameter/ Ref. case (see 4.1) Utrecht EPRI Simbeck IEA GHG

Capacity factor 0.685 0.65 0.75 0.913

Fuel efficiency (LHV) 31.5 (41.0) 23.8 (36.1) 37.4 (44.4) 33.0 (45.6)

Gross capaciy (MWe) 462 (600) 338 (513) 336.5 (400) 362 (501)

Specific capital cost EUR/kWe 2303 (1278) 2760 (1254) 2247 (1444) 2062 (1135)

Fuel costs EUR/kWe a 152 (117) 120 (78.5) 68.6 (57.7) 146 (106)

Operation & mantainance costs EUR/kWe a 88.7 (40.7) 202 (69.6) 89.8 (57.7) 110 (60)

Cost of mitigation, EUR/Mg of CO2 avoided 37 79 42 50

Cost of electricity : cEUR/kWhe 6.74 (4.14) 11.6 (5.11) 7.54 (5.06) 7.06 (4.16)

Capital charge rate, %/year 7.1 11.4 15.0 14.8

Fuel cost (LHV), EUR/GJ 2.22 1.39 1.08 1.661 EUR=0.9 $; 1 MJ=947.8 BTU;

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Table 3. The economics of the capture processes at PC plants using absorption compared acrossthe different studies reviewed at the MIT (24) after adjustment to a common economic base (seelist in pages 17-18 and ref. 24). Data in brackets correspond to the reference plant withoutcapture.

Table 4. The economics of the capture processes in PC plants using absorption with MEAs inthe IPTS format. Base data from the survey reported in reference 24. Data between incorrespond to the reference plant without capture.

Technoeconomic parameter/ Ref. case (see 4.1) Utrecht EPRI Simbeck IEA GHG

Capacity factor 0.75 0.75 0.75 0.75

Fuel efficiency (LHV) 31.5 (41.0) 23.8 (36.1) 37.4 (44.4) 33.0 (45.6)

Gross capaciy (MWe) 462 (600) 338 (513) 336.5 (400) 362 (501)

Specific capital cost EUR/kWe 2303 (1278) 2760 (1254) 2247 (1444) 2062 (1135)

Fuel costs EUR/kWe a 97.8 (75.2) 130 (85.4) 82.5 (69.3) 93.4 (67.9)

Operation & mantainance costs EUR/kWe a 94.2 (43.1) 218 (75.2) 89.9 (57.7) 97.8 (52.6)

Cost of mitigation, EUR /Mg of CO2 avoided 50 81 43 56

Cost of electricity : cEUR/kWhe 8.19 (4.72) 11.6 (5.31 ) 7.76 (5.23) 7.62 (4.42)

Technoeconomic parameter 2000 2010

Availability factor 0.9 0.9

Capacity factor 0.75 0.75

Fuel efficiency (LHV) 30.9 (41.2) 35.2 (42.2)

Forced outage rate ... ...

Gross capaciy (MWe) 375 (500) 417 (500)

Technical lifetime (a) ... ...

Construction time (a) ... ...

Economic life time (a) ... ...

Specific capital cost EUR/kWe 2322 (1278) 1978 (1226)

Specific fixed operating costs EUR/kWe a 100 (75.2) 87.8 (77)

Specific variable operating costs EUR/kWe a 115 (54) 89.7 (107)

Emission Factor during operation: SO2 kg/TJe .(180) .(180)

Emission Factor during operation: NOx kg/TJe .(170) .(170)

Emission Fact. during op.: particulates kg/TJe .(11) .(11)

Emission Factor: CO2 kg/GJe 29.2 (219) 25.7 (214)

Cost of mitigation, EUR /Mg of CO2 avoided 54.4 38.7

Cost of electricity : cEUR/kWhe 8.6 (4.9) 7.2 (4.6)

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Table 5. The economics of the capture processes at NGCC plants using absorption with MEAscompared across the different studies reviewed at the MIT (24) before adjustment . Data inbrackets correspond to the reference plant without capture

Table 6. The economics of the capture processes at NGCC plants using absorption comparedacross the different studies reviewed at the MIT (24) after adjustment to a common economicbase (see list in pages 17-18 and ref. 24). Data in brackets correspond to the reference plantwithout capture

Technoeconomic parameter/ Ref. case (see 4.2) Simbeck Trondhein IEA GHG Milan

Capacity factor 0.75 0.8 0.913 0.8Fuel efficiency (LHV) 53.0 (60) 44.5 (52.2) 47.2 (56.2) 48.1 (53.3)

Gross capaciy (MWe) 354 (400) 615 (721) 663 (790) 337 (531)

Specific capital cost EUR/kWe 1260 (539) 1463 (837) 873 (460) 897 (590)

Fuel costs EUR/kWe a 156 (138) 175.2 (150) 136 (114) 192 (173)

Operation & mantainance costs EUR/kWe a 50.4 (21.9) 38.9 (20.2) 37.3 (18.7) 28 (16.3)

Cost of mitigation, EUR /Mg of CO2 avoided 86 40 39 36

Cost of electricity : cEUR/kWhe 6.0 (3.7) 4.8 (3.4) 3.6 (2.4) 5.2 (4.0)

Capital charge rate, %/year 15 8.6 13.1 15.5Fuel cost (LHV), EUR/GJ 3.50 3.09 2.22 3.67

1 EUR=0.9 $; 1 MJ=947.8 BTU

Technoeconomic parameter/ Ref. case (see 4.2) Simbeck Trondhein IEA GHG Milan

Capacity factor 0.75 0.75 0.75 0.75

Fuel efficiency (LHV) 53.0 (60) 44.5 (52.2) 47.2 (56.2) 48.1 (53.3)Gross capaciy (MWe) 354 (400) 615 (721) 663 (790) 337 (531)

Specific capital cost EUR/kWe 1260 (539) 1463 (837) 873 (460) 897 (590)

Fuel costs EUR /kWe a 137 (122) 164 (140) 155 (130) 152 (137)

Operation & mantainance costs EUR /kWe a 50.4 (21.9) 38.0 (19.7) 32.8 (16.1) 26.3 (16.1)

Cost of mitigation, EUR /Mg of CO2 avoided 86 59 48 32

Cost of electricity : c EUR /kWhe 5.4 (3.2) 6.1 (4.12) 4.6 (3.1) 4.5 (3.5)

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Table 7. The economics of the capture processes at NGCC plants using absorption with MEAsin the IPTS format. Base data from the survey reported in reference 24. Data in bracketscorrespond to the reference plant without capture

Table 8. The economics of the capture processes at IGCC plants using absorption with MEAscompared across the different studies reviewed at the MIT (24) before adjustment. Data between

in correspond to the reference plant without capture

Technoeconomic parameter 2000 2010

Availability factor 0.9 0.9Capacity factor 0.75 0.75

Fuel efficiency (LHV) 47.8 (55.0) 53.1 (59.3)

Forced outage rate ... ...

Gross capaciy (MWe) 435 (500) 448 (500)

Technical lifetime (a) ... ...

Construction time (a) ... ...

Economic life time (a) ... ...

Specific capital cost EUR/kWe 1125 (602) 1103 (586)

Specific fixed operating costs EUR/kWe a 152.6 (133) 150 (123)

Specific variable operating costs EUR /kWe a 37.2 (18.2) 33.0 (17.6)

Emission Factor during operation: SO2 kg/TJe (negligible) (negligible)

Emission Factor during operation: NOx kg/TJe .(20) .(20)Emission Fact. during op.: particulates kg/TJe (negligible) (negligible)

Emission Factor: CO2 kg/GJe 11.7 (102) 10.5 (95)

Cost of mitigation, EUR /kg of CO2 avoided 54.4 47.1

Cost of electricity : c EUR/kWhe 5.5 (3.7) 4.7 (3.5)

Technoeconomic parameter/ Ref. case (see 4.3) Argonne Milan Simbeck Utrecht EPRI IEA GHG

Capacity factor 0.75 0.75 0.75 0.75 0.75 0.75

Fuel efficiency (LHV) 34.8 (38.2) 37.3 (43.7) 37.2 (47.3) 36.3 (43.6) 29.6 (36.8) 38.2 (46.3)

Gross capaciy (MWe) 377.5 (413.5) 345.6 (404.1) 314.4 (400) 500 (600) 347.4(431.6) 382 (408)

Specific capital cost EUR/kWe 1874 (1480) 2126 (1707) 1963 (1444) 1999 (1405) 2391 (1778) 2449 (1634)

Fuel costs EUR/kWe a 88.3 (81.0) 82.5 (70.8) 82.5 (65) 85.4 (70.8) 104.9 (84) 81 (66.4)

Operation & mantainance costs EUR/kWe a 81.8 (67.9) 52.6 (57.7) 78.8 (57.7) 68.6 (47.4) 104.4 (75.9) 108.8 (70.1)

Cost of mitigation, EUR /Mg of CO2 avoided 20 20 30 26.7 34.4 46.7

Cost of electricity : cEUR/kWhe 6.51 (5.35) 6.55 (5.33) 6.58 (4.89) 6.54 (4.27) 8.66 (6.16) 8.03 (5.51)

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Table 9. The economics of the capture processes at IGCC plants using absorption comparedacross the different studies reviewed a