comparative life cycle environmental assessment of ccs technologies

11
International Journal of Greenhouse Gas Control 5 (2011) 911–921 Contents lists available at ScienceDirect International Journal of Greenhouse Gas Control j ourna l ho mepage: www.elsevier.com/locate/ijggc Comparative life cycle environmental assessment of CCS technologies Bhawna Singh , Anders H. Strømman, Edgar G. Hertwich Industrial Ecology Programme and Department of Energy and Process Engineering, Norwegian University of Science and Technology (NTNU), Trondheim 7491, Norway a r t i c l e i n f o Article history: Received 29 January 2010 Received in revised form 12 January 2011 Accepted 31 March 2011 Available online 30 April 2011 Keywords: Carbon capture and storage Life cycle assessment Post-combustion Pre-combustion Oxyfuel a b s t r a c t Hybrid life cycle assessment is used to assess and compare the life cycle environmental impacts of elec- tricity generation from coal and natural gas with various carbon capture and storage (CCS) technologies consisting of post-combustion, pre-combustion or oxyfuel capture; pipeline CO 2 transport and geological storage. The systems with a capture efficiency of 85–96% decrease net greenhouse gas emission by 64–78% depending on the technology used. Calculation of other life cycle impacts shows significant trade-offs with fresh-water eutrophication and toxicity potentials. Human toxicity impact increases by 40–75%, terrestrial ecotoxicity by 60–120%, and freshwater eutrophication by 60–200% for the different technolo- gies. There is a two- to four-fold increase in freshwater ecotoxicity potential in the post-combustion approach. The increase in toxicity for pre-combustion systems is 40–80% for the coal and 50–90% for the gas power plant. The increase in impacts for the oxyfuel approach mainly depends on energy demand for the air separation unit, giving an increase in various toxicity potentials of 35–70% for coal and 60–105% for natural gas system. Most of the increase in impacts with CCS systems is due to the energy penalty and the infrastructure development chain. © 2011 Elsevier Ltd. All rights reserved. 1. Introduction Carbon capture and storage (CCS) is the most viable option to reduce CO 2 emissions from power plants while continuing the use of fossil fuels in order to satisfy increasing energy demand. The technology portfolio of CCS for use with power generation contains three capture techniques: post-combustion capture, pre- combustion capture, and oxyfuel capture. Captured CO 2 can then be transported by pipeline or ship and tankers for storage in geo- logical storage, depleted oil and gas fields, or used for enhanced oil recovery (EOR) (IPCC, 2005). These CCS options fare differently when compared for economic cost, level of maturity, and global warming reduction potential. CCS is a resource intensive process; it demands additional energy, chemicals, and infrastructure. The capture processes may also have certain direct emissions to air (NH 3 , aldehydes, solvent vapor, etc.) and generate solid wastes from degradation byprod- ucts. A trade-off in overall environmental impacts is expected, and therefore a systematic process of evaluation of the complete life cycles for all available CCS options is needed. Life cycle assessment (LCA) is a well-established method and best suited for such analysis. Few environmental assessments have been published with primary focus being on coal with post-combustion and/or pre-combustion Corresponding author. Tel.: +47 73598957; fax: +47 73598943. E-mail address: [email protected] (B. Singh). capture (Benetto et al., 2004; Doctor et al., 1993; Khoo and Tan, 2006; Koornneef et al., 2008; Korre et al., 2009; Rao and Rubin, 2002). Few studies have also considered natural gas CCS options (Audus and Freund, 1997; Hertwich et al., 2008; Odeh and Cockerill, 2008; Singh et al., 2010; Summerfield et al., 1995; Waku et al., 1995; Lombardi, 2003). However, many of these studies have only focused on the capture process, CO 2 emissions, and global warming. Pehnt and Henkel (2009) presented LCAs of all three capture tech- nologies and subsequent pipeline transport and storage in depleted gas field for a lignite power plant. Viebahn et al. (2007) performed LCA for CCS and other renewable energies, taking into considera- tion all relevant technologies and pollutants and presenting various life cycle impact results for a pulverized hard coal power plant with CCS. Although a few recent studies have focused on multiple environmental impacts, no comparative study of all three capture techniques with transport and storage for both coal and natural gas has been performed. This study evaluates and compares the life cycle impacts of var- ious coal and natural gas electricity generation chains with and without CO 2 capture, transport, and storage. The assessment is based on a hybrid model using elaborate physical data for all pro- cesses and economic data for infrastructure of the power plant and the CO 2 capture facility. This analysis discloses the environ- mental trade-offs and benefits explicit due to CCS with different technologies, and the results are used to identify the target sites for technology development in the chain so as to minimize the adverse impacts. Section 2 describes the methodology for the life cycle 1750-5836/$ see front matter © 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2011.03.012

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Page 1: Comparative life cycle environmental assessment of CCS technologies

Journal Identification = IJGGC Article Identification = 413 Date: July 6, 2011 Time: 2:47 pm

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International Journal of Greenhouse Gas Control 5 (2011) 911–921

Contents lists available at ScienceDirect

International Journal of Greenhouse Gas Control

j ourna l ho mepage: www.elsev ier .com/ locate / i jggc

omparative life cycle environmental assessment of CCS technologies

hawna Singh ∗, Anders H. Strømman, Edgar G. Hertwichndustrial Ecology Programme and Department of Energy and Process Engineering, Norwegian University of Science and Technology (NTNU), Trondheim 7491, Norway

r t i c l e i n f o

rticle history:eceived 29 January 2010eceived in revised form 12 January 2011ccepted 31 March 2011vailable online 30 April 2011

eywords:arbon capture and storageife cycle assessment

a b s t r a c t

Hybrid life cycle assessment is used to assess and compare the life cycle environmental impacts of elec-tricity generation from coal and natural gas with various carbon capture and storage (CCS) technologiesconsisting of post-combustion, pre-combustion or oxyfuel capture; pipeline CO2 transport and geologicalstorage.

The systems with a capture efficiency of 85–96% decrease net greenhouse gas emission by 64–78%depending on the technology used. Calculation of other life cycle impacts shows significant trade-offswith fresh-water eutrophication and toxicity potentials. Human toxicity impact increases by 40–75%,terrestrial ecotoxicity by 60–120%, and freshwater eutrophication by 60–200% for the different technolo-

ost-combustionre-combustionxyfuel

gies. There is a two- to four-fold increase in freshwater ecotoxicity potential in the post-combustionapproach. The increase in toxicity for pre-combustion systems is 40–80% for the coal and 50–90% for thegas power plant. The increase in impacts for the oxyfuel approach mainly depends on energy demand forthe air separation unit, giving an increase in various toxicity potentials of 35–70% for coal and 60–105%for natural gas system. Most of the increase in impacts with CCS systems is due to the energy penalty andthe infrastructure development chain.

. Introduction

Carbon capture and storage (CCS) is the most viable option toeduce CO2 emissions from power plants while continuing these of fossil fuels in order to satisfy increasing energy demand.he technology portfolio of CCS for use with power generationontains three capture techniques: post-combustion capture, pre-ombustion capture, and oxyfuel capture. Captured CO2 can thene transported by pipeline or ship and tankers for storage in geo-

ogical storage, depleted oil and gas fields, or used for enhancedil recovery (EOR) (IPCC, 2005). These CCS options fare differentlyhen compared for economic cost, level of maturity, and globalarming reduction potential.

CCS is a resource intensive process; it demands additionalnergy, chemicals, and infrastructure. The capture processes maylso have certain direct emissions to air (NH3, aldehydes, solventapor, etc.) and generate solid wastes from degradation byprod-cts. A trade-off in overall environmental impacts is expected, andherefore a systematic process of evaluation of the complete lifeycles for all available CCS options is needed. Life cycle assessment

LCA) is a well-established method and best suited for such analysis.ew environmental assessments have been published with primaryocus being on coal with post-combustion and/or pre-combustion

∗ Corresponding author. Tel.: +47 73598957; fax: +47 73598943.E-mail address: [email protected] (B. Singh).

750-5836/$ – see front matter © 2011 Elsevier Ltd. All rights reserved.oi:10.1016/j.ijggc.2011.03.012

© 2011 Elsevier Ltd. All rights reserved.

capture (Benetto et al., 2004; Doctor et al., 1993; Khoo and Tan,2006; Koornneef et al., 2008; Korre et al., 2009; Rao and Rubin,2002). Few studies have also considered natural gas CCS options(Audus and Freund, 1997; Hertwich et al., 2008; Odeh and Cockerill,2008; Singh et al., 2010; Summerfield et al., 1995; Waku et al.,1995; Lombardi, 2003). However, many of these studies have onlyfocused on the capture process, CO2 emissions, and global warming.Pehnt and Henkel (2009) presented LCAs of all three capture tech-nologies and subsequent pipeline transport and storage in depletedgas field for a lignite power plant. Viebahn et al. (2007) performedLCA for CCS and other renewable energies, taking into considera-tion all relevant technologies and pollutants and presenting variouslife cycle impact results for a pulverized hard coal power plantwith CCS. Although a few recent studies have focused on multipleenvironmental impacts, no comparative study of all three capturetechniques with transport and storage for both coal and natural gashas been performed.

This study evaluates and compares the life cycle impacts of var-ious coal and natural gas electricity generation chains with andwithout CO2 capture, transport, and storage. The assessment isbased on a hybrid model using elaborate physical data for all pro-cesses and economic data for infrastructure of the power plantand the CO2 capture facility. This analysis discloses the environ-

mental trade-offs and benefits explicit due to CCS with differenttechnologies, and the results are used to identify the target sites fortechnology development in the chain so as to minimize the adverseimpacts. Section 2 describes the methodology for the life cycle
Page 2: Comparative life cycle environmental assessment of CCS technologies

Journal Identification = IJGGC Article Identification = 413 Date: July 6, 2011 Time: 2:47 pm

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12 B. Singh et al. / International Journal o

ssessment and section 3 gives a detailed description of the tech-ologies and inventories of the systems. Section 4 presents resultsnd discussion for the life cycle environmental impacts. Further, aensitivity analysis is made to investigate the variation in impactsith the transport distance. Section 5 presents the conclusion and

utlook for future work.

. Methods

In this study, the hybrid LCA approach is used to model theystems as it offers the advantage of both the data specificity ofrocess LCA and the system completeness of input–output analysis.he detailed unit process level information obtained from processodel data and the Ecoinvent v2 database (Ecoinvent Centre, 2007)

s used together with the input–output model of the US econ-my (Suh, 2005). The characterization factors from ReCiPe 2008ethod v1.02 (ReCiPe, 2009) are used to estimate the potential

nvironmental impacts of the emissions incurred. A factor of 0.24,4-DCB kg eq/kg (Veltman et al., 2010) for human toxicity potentialf monoethanolamine (MEA) is used.

The environmental impacts are categorized into 10 environ-ental mid-point indicators: global warming potential (GWP),

errestrial acidification potential (TAP), fresh water eutrophicationotential (FEP), marine eutrophication potential (MEP), photo-hemical oxidant formation potential (POFP), particulate matterormation potential (PMFP), human toxicity potential (HTP), terres-rial ecotoxicity potential (TETP), fresh water ecotoxicity potentialFETP), and marine ecotoxicity potential (METP). A sensitivity anal-sis is performed to study the influence of the CO2 transportistance over the impact potentials.

. System description

.1. General framework for all power plants and CCS systems

.1.1. Power plantAll power plants are assumed to have 400 MW net electricity

utput and the ‘functional unit’ for the study is chosen as 1 kWh ofet electricity produced. The net electrical efficiencies (as LHV) oforld average and best-available technologies are taken from IEA

2008). Specific performance parameters and emission factors areiscussed separately for each power plant. Fig. 1 shows the fore-round system boundaries of the studied CCS systems and Table 1resents the performance parameters of the studied power plants.rocess information on technical parameters is gathered from theiterature and used to define process model data for the study (Singht al., 2011). The foreground system consists of fuel combustion inhe power plant, the capture process, and transport and storage ofO2.

The LCI data for fuel supply and combustion (for state-of-artechnologies) is derived from the Ecoinvent v2 database (Ecoinvent,007). The Ecoinvent database provides data for average powerlant in a specific geographical location, which is then adapted tostimate the emissions from the best-available technologies. Emis-ion factors for futuristic power plant technologies are based oniterature (Croiset and Thambimuthu, 2000; Dillion et al., 2005;EA GHG, 2000 in IPCC, 2005; IEA, 2008; Nord et al., 2009; Ratafia-rown et al., 2002; Tan et al., 2002; Yan et al., 2006), and the

nventory of the capture operation is based on process modelingata. Infrastructure for power plant and capture unit is accounteds capital investment (IPCC, 2005) attributed to various sectors in

S I/O 1998 database (Suh, 2005). Other emissions arising frompstream, e.g., the production of fuel (coal/natural gas), absorbent,tc. and the emissions from downstream, e.g., waste treatment andisposal – are also included in the assessment.

house Gas Control 5 (2011) 911–921

3.1.2. Pipeline transportThe captured CO2 is supplied to the transport chain at 110 bar

and transported over 500 km to a geological storage site. Trans-port mainly requires construction, maintenance, dismantling, andmonitoring of the pipeline. The optimum economic pipe diameteris estimated for each case (Peters et al., 2003; Zhang et al., 2006)and the LCI data for pipeline is derived from ecoinvent v2 (off-shore natural gas pipeline in North Sea with a diameter of 1000 and25 mm thickness). This conservative approach will likely overesti-mate material requirements. In practice, bigger diameter pipelineswith higher mass flow rates are expected to be used, reducingthe material use and cost per ton CO2 transported. Some addi-tional energy is also required for recompression of CO2, due to thepressure drop. A pressure drop of 10 bar per 100 km (Spath andMann, 2004; Wildbolz, 2007) demands a recompression stationafter 300 km to maintain the pressure well above the critical pres-sure. The energy required for recompression for a pressure drop of30 bar using a gas turbine efficiency of 85% is calculated for eachcase and is supplied from a power plant similar to the referenceplant without CCS.

3.1.3. Geological storageStorage mainly requires well drilling, CO2 injection, and moni-

toring. CO2 is to be stored above supercritical pressure; thereforeadditional energy is required to inject CO2 into storage formation ata pressure higher than reservoir fluid pressure. A single CO2 injec-tion well is assumed at the geological storage site about 1000 mbelow the sea floor. LCI data for the well is taken as offshore drillingwell from ecoinvent v2. The energy required for injection is cal-culated for each case, assuming reservoir at hydrostatic pressureof 78.4 bar (Wildbolz, 2007) and overpressure of 20 bar (Wildbolz,2007; Zweigel and Heill, 2003). This energy is assumed to be sup-plied from a power plant, similar to the reference plant withoutCCS. Monitoring of the storage site is not included in this study,and leakage of the injected CO2 is assumed to be negligible.

3.2. Post-combustion capture, transport and storage system

In a typical post-combustion capture process, the treated fluegas is passed through a chemical absorption column where thesolvent takes up the CO2. The CO2-rich solvent is regenerated byheating in the stripper unit. The CO2 is then compressed and sup-plied to the pipeline (Fig. 1).

The supercritical coal power plant consists of a combustionchamber, a steam-cycle unit and a state-of-art flue gas treatmentfacility. A net efficiency of 43.4% (IEA, 2008) is assumed for theplant and the emissions are derived from ecoinvent v2 database.For the system with CO2 capture, 90% CO2 is assumed to be cap-tured using monoethanolamine (MEA). Some fresh MEA is addedto make up for the losses (degradation losses and vapor losses)during the process. The energy requirements for the capture pro-cess are for regeneration of the solvent, solvent pumps, flue gasblower, cooling water pumps, and CO2 compression, resulting in anenergy penalty of 10.2% (estimated from IPCC, 2005). The captureprocess also removes SO2, NO2, and particulates (Rao and Rubin,2002). SO2 and NO2 react with MEA forming heat stable salts, result-ing in a nominal removal efficiency of 99.5% for SO2 and 25% forNO2 (Rao and Rubin, 2002). A solvent make-up of 1.6 kg MEA/tCO2(IPCC, 2005) is needed due to its loss via vapors and formation ofdegradation products. Besides chemical solvent, the capture pro-cess also requires caustic soda to reclaim the amine from the heatstable salt and activated carbon to remove degradation products.

Air emissions and degradation waste from the capture process arequantified based on literature (IEA GHG, 2006; Koornneef et al.,2008; Rao and Rubin, 2002; Veltman et al., 2010). The CO2 prod-uct is dried and compressed to 110 bar, supplied to pipeline, and
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B. Singh et al. / International Journal of Greenhouse Gas Control 5 (2011) 911–921 913

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ig. 1. Foreground process flow chart for the modeled CCS systems, including indicaO2 capture.

ransported over 500 km. The optimum economic pipe diameter of00 mm is estimated. An energy demand of 574 kW is calculatedue to the pressure drop in the pipeline, and additional 161 kW isequired for the storage.

In natural gas fired power plant, electricity is produced using state-of-art natural gas combined cycle with a net efficiencyf 58.1% (IEA, 2008). The emissions from the power plant areerived from Ecoinvent v2 database. For the system with CO2 cap-ure, 90% CO2 is assumed to be captured using MEA as solvent

ith co-capture of SO2, NO2, and particulates (Rao and Rubin,

002). The energy requirements for the capture process result in annergy penalty of 8% (estimated from IPCC, 2005). The MEA basedmissions are quantified based on Veltman et al. (2010) and NVE

f the systems boundaries: (a) post-combustion, (b) pre-combustion and (c) Oxyfuel

(2007). Degradation reclaimer waste contains corrosion inhibitors(Thitakamol et al., 2007; Veltman et al., 2010) making it hazardousto landfill and therefore the waste is assumed to be incinerated.Captured CO2 is compressed to 110 bar at the power plant andsupplied to the pipeline. The optimum economic pipe diameterof 200 mm is calculated, and the energy demand is 261 kW forrecompression and 73 kW for injection.

3.3. Pre-combustion capture, transport and storage system

In a typical pre-combustion capture process, steam and oxygenare added to the primary fuel producing a mixture of hydrogen andcarbon monoxide (syngas). This is followed by the ‘shift’ reaction

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Table 1Performance parameters for different power generation systems.

Parameters Coala Natural gasa

Worldaverage

SupercriticalBAT

IGCC Supercriticalwith post-combustioncapture

IGCC with pre-combustioncapture

Oxyfuelcapture

Worldaverage

NGCC Partialoxidation

NGCC withpost-combustioncapture

Partialoxidation withpre-combustioncapture

Oxyfuelcapture

CO2 capture – – – 90% 90% 90% – – – 90% 85% 96%Net efficiency 35% 43.4% 44.1% 33.2% 37.6% 34.6% 42% 58.1% 56% 50.1% 48.1% 46.8%Energy penalty – – – 10.2% 6.5% 8.8% – – – 8% 7.9% 11.3%Co-capture – – – SO2, NO2,

particulatesParticulates – – – – SO2, NO2,

particulatesParticulates –

Solventconsumption

kg/tCO2 – – – 1.6 (MEA) 0.007 (selexol) – – – – 1.6 (MEA) 0.007 (selexol) –

Power plant capitalcostb

$/kW 1286 1286 1326 2096 1825 1857 568 568 447 998 978 1034

CO2 sequestered Mt/y – – – 2.2 2.1 2.2 – – – 1 1 1.1Energy for

transport andstorage

kW – – – 735 696 735 – – – 334 327 356

EmissionsCO2 g/kWh 946.6 763.4 722.8 100.1 85.7 95.5 479.6 346.7 359.7 40.5 62.8 17.4SO2 mg/kWh 673.5 543.2 287.5 26.8 341.0 679.4 4.3 3.1 3.2 0.0005 3.7 3.9NOX mg/kWh 637.6 514.2 328.6 641.1 389.8 322.1 428.2 309.6 321.2 343.9 374.0 194.1NH3 mg/kWh 7.2 5.8 1.6 39.0 1.9 2.0 – – – 12.7 – –Particulates mg/kWh 108.5 87.5 86.1 57.3 51.1 109.4 4.3 3.1 3.2 1.8 1.9 3.9Solvent mg/kWh – – – 56.5 – – – – – 22.8 – –Solid degradation

productkg/tCO2 – – – 3.2 0.007 – – – – 3.2 0.007 –

a 8000 full load hours per year with plant life-time of 25 years.b IPCC (2005), Rubin et al. (2007).

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o convert CO to CO2 by the addition of steam. The CO2 is removedrom the CO2/H2 gas mixture, and the gas mixture is then suppliedo combined cycle power plant (Fig. 1).

The integrated coal gasification combined cycle (IGCC) powerlant consists of a gasification unit, a gas cleaning unit, and a gas-red combined-cycle unit. A net efficiency of 44.1% (IEA, 2008)

s assumed for the plant and the emissions are derived fromatafia-Brown et al., 2002. For the IGCC system with CO2 capture,0% CO2 is assumed to be captured using selexol. The efficiency

oss due to ‘water–gas-shift’ reaction and solvent circulation isssumed to be 6.5% (derived from IPCC, 2005). Consumption of.005 kg selexol/MWh from IGCC is projected (Rubin et al., 2005);owever no literature is found considering solvent loss to atmo-phere or emission of solvent degradation products. An additionaleduction of particulates by 50% from syngas is assumed (Odehnd Cockerill, 2008) by the selexol capture process. Selexol is non-oxic and has a low vapor pressure (Chen, 2005), therefore it isssumed that all spent solvent ends up as solid waste and is incin-rated. CO2 compressed to 110 bar at the power plant is thenupplied to pipeline and transported over 500 km. The optimumconomic pipe diameter is estimated to be about 300 mm andhe energy demand is 544 kW for recompression and 152 kW fortorage.

For a natural gas based system, the natural gas, steam, and oxy-en are fed to the reformer. In the auto-thermal reformer, partialombustion of methane provides the heat for the endothermiceforming reaction, hence avoiding CO2 emissions from externalring (Solli et al., 2009). A net efficiency of 56% is assumed for thelant as the literature suggests a range of 54.5–56.2% (Nord et al.,009, IEA GHG, 2000 in IPCC, 2005). In the pre-combustion CO2apture unit, 85% CO2 is assumed to be captured using selexol. Thefficiency loss of 7.9% is assumed (IEA GHG, 2000 in IPCC, 2005).he optimum economic pipe diameter is estimated to be about00 mm and the energy requirement is 255 kW for recompression,nd 71 kW for injection.

.4. Oxyfuel capture, transport and storage system

In a typical oxyfuel combustion process, fuel is combusted inither pure oxygen or O2/CO2 mixtures, thus eliminating nitrogenrom the flue gas. The flue gas consist mainly of CO2 and waterapor together with excess oxygen, which after cooling to condenseater vapor, contains about 80–98% CO2 (IPCC, 2005) (Fig. 1). Appli-

ation of oxyfuel combustion in power plant implies reduction inet efficiency due to energy requirement of the air separation unitASU).

For the coal power plant, a baseline efficiency of 43.4% (sames supercritical power plant) with an overall efficiency loss of 8.8%oints is assumed (Dillion et al., 2005), and the emission factorsre based on literature (Croiset and Thambimuthu, 2000; Dilliont al., 2005; IPCC, 2005; Yan et al., 2006). 90% CO2 is assumed to beaptured by condensation separation, which is then compressed,ried, and further purified before delivery to pipeline. The opti-um economic pipe diameter is calculated to be about 300 mm.

he pressure drop in the pipeline results in an energy demand of74 kW for recompression, and an additional 161 kW is requiredor the storage.

In the natural gas oxyfuel combustion system, the baseline effi-iency is 58.1% (same as NGCC power plant), with an assumption of1.3% efficiency loss (Dillion et al., 2005) due to energy allowanceor ASU, and the emission factors are derived from the literature

eview (Dillion et al., 2005; IPCC, 2005; Tan et al., 2002). 96% CO2 isssumed to be captured. The optimum economic pipe diameter isstimated to be about 200 mm, and the energy demand is 278 kWor recompression and 78 kW for injection.

house Gas Control 5 (2011) 911–921 915

4. Results and discussion

The main objective of the CCS systems is to control CO2 emis-sions, having some co-benefits for SO2, NOx, and particulatesremoval with certain technologies. However, there are variousother direct and indirect emissions throughout the value chain,from raw material extraction for fuel and infrastructure, to thewaste treatment and disposal. Table 2 presents impact charac-terization results for six power plant systems each for coal andnatural gas. As expected, the impact scores for all categories arehigher for world average technology than the best-available tech-nology (supercritical plant for coal and NGCC for natural gas),showing the potential for possible environmental improvements.The global average efficiency of hard coal-fired plants is only 35%,ranging from 33% in China to 42% in Japan, while the global aver-age efficiency of natural gas-fired plants is only 42% ranging, fromabout 33% in Russia to 49% in Western Europe. The current effi-ciency of most plants is well below the possible levels (43% forcoal and 58% for natural gas) and there is much potential for sig-nificant efficiency improvements. However, comparison with CCSsystems shows that the world average technology implies lowerimpacts for certain categories, raising concerns for toxicity andeutrophication impacts with use of CCS. Table 3 gives the percent-age change in impact for the systems with different CO2 capturetechnologies. Fig. 2 shows global warming impact (GWP) from dif-ferent electricity generation systems, with a breakdown into directimpact from combustion at power plant and indirect impact fromthe value chain. The impacts are unevenly distributed over var-ious processes, e.g., fuel extraction, transport, combustion at thepower plant, CO2 capture, infrastructure, solvent production – aswell as locations, e.g., mining sites, offshore natural gas produc-tion facility, chemical manufacturing sites, power plant facility,dispersed transportation, iron & steel industry, etc. Fig. 3 presentsthe relative contribution of processes towards the total impactfor all three CCS approaches with coal and natural gas feedstock.Table 4 presents the result of sensitivity analysis for transportchain.

4.1. Global warming potential (GWP)

There is considerable reduction in GHG (CO2 equivalents) byapplication of CO2 capture; however the life cycle reduction ratesare significantly lower than the CO2 capture rates at the powerplants (Fig. 2). The CCS systems reduce the life-cycle GHG emissionsby 74–78% for coal power plants and 64–73% for the natural gaspower plants. The lower efficiency of GHG reduction in the casewith natural gas feedstock is due to relatively lower contributionof CO2 emissions from the fuel combustion process than from coalin the electricity generation systems.

Direct emissions of CO2 at the power plant without capture con-tribute to more than 90% of life cycle GHG emissions in the case ofcoal and more than 82% in the case of natural gas. For the powerplants with CCS system, the direct CO2 emissions at the coal plant isresponsible for over 46% of life cycle GHG emissions and over 30%at the natural gas plant, except for oxyfuel combustion with CCSat the natural gas power plant, where direct CO2 emission makesonly about 15% of life cycle GHGs due to high capture efficiency(Fig. 2).

The remaining CO2eq in the CCS chain are mainly emitted in thefuel supply chain, dominated by coal mining for coal systems andgas production and transportation for natural gas systems. Con-tribution from MEA production and reclaimer waste disposal is

also of relative significance for post-combustion CCS systems. Pri-mary infrastructural requirements (power plant, fuel production,and transport and storage infrastructure) contributes about 7–9%to the life cycle GWP impact for different CCS systems and is dom-
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Table 2Absolute impact scores for 1 kWh of electricity generation from different technologies.

Impact GWP TAP FEP MEP POFP PMFP HTP TETP FETP METPUnit (kg eq) CO2 SO2 P N NMVOC PM10 1,4-DB 1,4-DB 1,4-DB 1,4-DB

Coal power generation systemsWorld average coal 1.0 × 100 1.6 × 10−3 4.0 × 10−6 2.1 × 10−4 1.5 × 10−3 5.6 × 10−4 1.2 × 10−2 2.2 × 10−5 2.0 × 10−4 2.6 × 10−4

Supercritical BAT 8.4 × 10−1 1.3 × 10−3 3.3 × 10−6 1.7 × 10−4 1.2 × 10−3 4.5 × 10−4 9.8 × 10−3 2.0 × 10−5 1.7 × 10−4 2.1 × 10−4

Supercritical BAT with CCS 2.2 × 10−1 1.1 × 10−3 7.7 × 10−6 2.4 × 10−4 1.5 × 10−3 4.2 × 10−4 1.5 × 10−2 4.2 × 10−5 5.1 × 10−4 3.9 × 10−4

IGCC 8.0 × 10−1 9.3 × 10−4 1.0 × 10−6 1.1 × 10−4 9.5 × 10−4 3.5 × 10−4 5.4 × 10−3 1.8 × 10−5 8.0 × 10−5 1.0 × 10−4

IGCC with CCS 1.8 × 10−1 1.1 × 10−3 2.3 × 10−6 1.4 × 10−4 1.1 × 10−3 3.8 × 10−4 7.6 × 10−3 2.8 × 10−5 1.3 × 10−4 1.9 × 10−4

Oxyfuel with CCS 2.0 × 10−1 1.5 × 10−3 5.2 × 10−6 1.7 × 10−4 1.2 × 10−3 5.1 × 10−4 1.3 × 10−2 3.3 × 10−5 2.4 × 10−4 3.3 × 10−4

Natural gas power generation systemsWorld average NG 5.8 × 100 5.5 × 10−4 1.2 × 10−6 8.1 × 10−5 8.4 × 10−4 1.9 × 10−4 2.5 × 10−3 1.6 × 10−5 4.2 × 10−5 1.8 × 10−4

NGCC BAT 4.2 × 10−1 4.0 × 10−4 8.8 × 10−7 5.8 × 10−5 6.1 × 10−4 1.4 × 10−4 1.8 × 10−3 1.3 × 10−5 3.1 × 10−5 1.3 × 10−4

NGCC BAT with CCS 1.4 × 10−1 5.1 × 10−4 2.6 × 10−6 7.5 × 10−5 7.1 × 10−4 1.7 × 10−4 3.2 × 10−3 2.3 × 10−5 1.6 × 10−4 2.1 × 10−4

Partial oxidation 4.4 × 10−1 4.2 × 10−4 9.0 × 10−7 6.0 × 10−5 6.1 × 10−4 1.5 × 10−4 1.8 × 10−3 1.2 × 10−5 3.1 × 10−5 1.3 × 10−4

Partial oxidation with CCS 1.6 × 10−1 5.0 × 10−4 1.8 × 10−6 7.1 × 10−5 7.3 × 10−4 1.8 × 10−4 3.0 × 10−3 2.1 × 10−5 6.0 × 10−5 2.0 × 10−4

Oxyfuel with CCS 1.2 × 10−1 4.1 × 10−4 1.8 × 10−6 4.9 × 10−5 5.6 × 10−4 1.4 × 10−4 3.2 × 10−3 2.3 × 10−5 6.3 × 10−5 2.1 × 10−4

Table 3Change in impact for different CCS configurations with respect to system without CCS.

Impacts Coal Natural gas

Post-combustiona Pre-combustionb Oxyfuela Post-combustiona Pre-combustionb Oxyfuela

Global warming % −74 −78 −76 −68 −64 −73Terrestrial acidification % −13 20 13 26 20 2Freshwater eutrophication % 136 120 59 200 94 111Marine eutrophication % 43 20 1 30 18 −15Photochemical oxidant formation % 27 20 −1 17 18 −8Participate matter formation % −7 8 12 23 21 2Human toxicity % 51 40 38 74 62 73Terrestrial ecotoxicity % 114 58 67 76 76 77Fresh water ecotox. % 205 60 46 413 90 103Marine ecotoxicity % 88 80 57 66 50 63

a Reference plant is supercritical BAT for coal and NGCC BAT for natural gas.b Reference plant has IGCC for coal and partial oxidation for natural gas.

Fig. 2. Global warming potential (GWP) from different electricity generation systems.

Table 4Environmental impact scores from transport and storage chain for different CO2 transport distances and amounts sequestered per year.

Impact Unit (kg eq) 200 km 500 km 1000 km

l Mt/y 2 Mt/y l Mt/y 2 Mt/y l Mt/y 2 Mt/y

GWP CO2 2.6 × 106 4.0 × 106 7.1 × 106 1.1 × 107 1.5 × 107 2.3 × 107

TAP SO2 1.0 × 104 1.6 × 104 2.9 × 104 4.5 × 104 5.8 × 104 9.4 × 104

FEP P 7.4 × 102 1.1 × 103 1.9 × 103 2.8 × 103 3.7 × 103 5.6 × 103

MEP N 1.2 × 103 1.8 × 103 3.2 × 103 4.9 × 103 6.4 × 103 1.0 × 104

POFP NMVOC 1.2 × 104 1.8 × 104 3.1 × 104 4.8 × 104 6.3 × 104 9.8 × 104

PMFP PM10 7.2 × 103 1.1 × 104 1.9 × 104 2.9 × 104 3.8 × 104 5.8 × 104

HTP 1,4-DB 7.2 × 105 1.1 × 106 1.8 × 106 2.8 × 106 3.7 × 106 5.6 × 106

TETP 1,4-DB 5.0 × 102 7.6 × 102 1.3 × 103 2.0 × 103 2.6 × 103 4.1 × 103

FETP 1,4-DB 2.1 × 104 3.1 × 104 5.3 × 104 8.0 × 104 1.1 × 105 1.6 × 105

METP 1,4-DB 3.9 × 104 5.8 × 104 9.8 × 104 1.5 × 105 2.0 × 105 2.9 × 105

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pact

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Fig. 3. Contribution analysis for various environmental im

nated by infrastructural requirements for the fuel supply chain.he contribution from the transport and storage chain is relativelymall at only about 2% of the total GWP impact.

.2. Post-combustion capture, transport and storage system

The designed 90% CO2 capture efficiency for post-combustion

oal and natural gas CCS systems resulted in a net reduction of 74%nd 68% GWP, respectively. The coal CCS system shows an overalleduction of 13% in acidification potential (TAP) and 7% in partic-late matter formation (POFP) due to co-capture of SO2, NOx, and

s from different electricity generation systems with CCS.

particulate matter. SO2, NOx emissions from coal combustion andNH3 emission (mainly from the capture process and partly fromDeNOx process of flue gas treatment) cause 42% of the life cycleacidification impact from coal CCS system (Table 2). However, dueto lower pollutant content in the natural gas combustion exhauststream, the co-capture is insufficient to offset the additional impactfrom the natural gas chain, resulting in an overall increase of 26%

in acidification impact and 23% in particulate matter formation.NOx from combustion causes 38% and NH3 emissions causes 6%of the life cycle acidification impact from the natural gas CCSsystem.
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The post-combustion CCS systems show significant increase inreshwater eutrophication, marine eutrophication, and various tox-city potentials. Results show an increase of 136% for the coal CCSystem and 200% for the natural gas CCS system in FEP scoresTable 3). FEP is caused by emissions of phosphorus and phosphateo water. Power plant waste treatment, development of infrastruc-ure for the fuel production chain and transport, and storage arehe main contributing processes to this impact. Analysis of theserocesses reveals that disposal of furnace waste from steel man-facturing (for infrastructure), coal ash disposal (for cases of coaleed stock only), and reclaimer waste disposal are the dominatingontributors to FEP. Marine eutrophication (MEP) is mainly causedy emissions of the nitrogenous compounds (NOx, NH3, organicound nitrogen, etc.). The lower emission factor of NOx due to co-apture in the post-combustion system is offset by the addition ofCS, leading to an increase of 43% with the coal, and 30% increaseith the natural gas system in MEP. Direct emissions from theower plant are the major contributor to this impact, making 36%nd 60% of the overall MEP for coal and natural gas, respectively.EA production contributes about 7–8% to MEP impact, coming

rom production of ethylene and ammonia. Waste treatment makesn important contribution of 17% to the impact from coal post-ombustion CCS system, with major contributions from nitratend ammonia emission in flue gas desulphurization (FGD) andelective catalytic reduction (SCR) processes, respectively, whilehe disposal of reclaimer bottom contributes less than 1% to thempact.

Various toxicity impacts show increases of 51–205% for the coalCS system and 66–413% in the natural gas system. The main con-ribution to toxicity is generally associated with the infrastructureequirements and heavy metal emissions associated with the mate-ial production. Results show that the infrastructure demand foratural gas CCS systems contributes over 85% to human toxicityHTP), terrestrial ecotoxicity (TETP), and marine ecotoxicity (METP)nd 34% to freshwater ecotoxicity impact (FETP), while for the coalCS systems, infrastructure development makes about 27% of HTP,0% of TETP, 19% of FETP, and 36% of METP. Direct emissions fromhe coal systems significantly influence HTP, TETP, and METP scores,

aking a dominant contribution of about 37% to the human toxic-ty impact. Emission of MEA, formaldehyde, and acetaldehyde fromhe capture system causes about 1% of HTP and 2% of TETP for theoal CCS system, and about 1.5% of HTP and TETP for the naturalas CCS system. These capture related emissions causes only �1%o the FETP and METP scores both for coal and gas CCS systems. Theost-combustion CCS has the highest FETP impact (compared to alltudied systems), with a two-fold increase for coal and a four-foldncrease for the natural gas system. In these systems the highestontribution (74% for the coal system and 65% for the natural gasystem) is from the power plant, where the disposal of reclaimerolid wastes alone is responsible for 48% of the FETP score in the coalystem and 62% of the FETP score in the natural gas system whichs caused by leaching from the landfill of incinerator ash from theeclaimer waste to surface- and groundwater. The majority of thearine ecotoxicity impact in the coal CCS system emanates fromaste treatment (19% from coal ash disposal and 9% from reclaimeraste disposal of the total score).

.3. Pre-combustion capture, transport and storage system

Pre-combustion CCS reduces 78% GWP from the coal and 64%rom the natural gas system. However, these systems result in sub-tantially higher freshwater eutrophication impact and all toxicity

mpacts as compared to the systems without CCS. The IGCC technol-gy in itself is a clean coal technology and has lower environmentalmpacts than all other coal technologies (with or without CCS)xcept for global warming impact, which, as expected, is higher

house Gas Control 5 (2011) 911–921

than the coal systems with CCS. The IGCC coal system significantlyreduces the SO2 and NOx content in the flue gas from syngas com-bustion; however, there is no such advantage with partial oxidationfor the natural gas system. SO2 and NOx emissions from power IGCCpower plant still causes about 50% of the total acidification impactfor coal pre-combustion CCS system, while the NOx emission causesover 40% of the TAP score for such natural gas CCS system.

Fresh water eutrophication results show significant increasesof 120% for the coal and 94% for the natural gas CCSsystems. Development of infrastructure for the fuel productionchain and transport and storage systems are the main contribut-ing processes (causing 91% for the coal and 99% for the naturalgas systems) to FEP, mainly due to disposal of solid waste fromsteel manufacturing process. Infrastructure development chainalso makes a major contribution to all toxicity potentials, caus-ing 43% of HTP, 87% of TETP, 63% of FETP, and 64% of the METPscore from the coal CCS system. For the natural gas CCS sys-tem, infrastructure development contributes over 95% to all fourtoxicity impacts, mainly from infrastructure for natural gas produc-tion, except for terrestrial ecotoxicity impact where power plantinfrastructure causes 58% of the overall TETP. Analysis shows thatemissions and disposal of solid wastes from steel manufacturing,well drilling, and copper production are the important processescontributing to various toxicity potentials. For the coal CCS sys-tem, power plant waste treatment contributes about 8% to METPand 13% to FETP score, mainly due to the disposal of residue fromthe cooling tower. Coal production and direct emissions from thepower plant are two other important processes contributing to thetoxicity impacts from the coal CCS systems.

4.4. Oxyfuel capture, transport and storage system

The oxyfuel coal CCS system reduces global warming impact by76%, and the high capture efficiency of 96% with the natural gasoxyfuel CCS system results in a 73% reduction of GWP. The reducedNOx content in the flue gas results in comparable MEP impact assupercritical BAT technology for coal and natural gas, with a netreduction of 15% (compared to NGCC). The NOx reduction alsoresults in a decrease of photochemical oxidant formation poten-tial (POFP). However, the energy requirement of the air separationunit (ASU) and CO2 compression unit in the oxyfuel CCS systemrequires increased fuel combustion per kWh, which increases theoverall impacts through the chain.

Similar to post-combustion and pre-combustion CCS systems,the oxyfuel CCS also shows a considerable increase in freshwatereutrophication and toxicity potentials. FEP scores show increasesof about 60% for the coal system and 110% for the natural gas sys-tem. The power plant waste treatment process (mainly the processof coal ash disposal) is the major contributor to the FEP score forthe coal feedstock, causing about 52% of the total impact. Infras-tructure requirements of the system (power plant, fuel production,and transport and storage) cause 99% and 43% of FEP for the naturalgas and coal systems, respectively. Further, the toxicity potentialsshow increases of 38–67% for the coal system and of 63–103% forthe natural gas system. While the infrastructure development islargely responsible for all toxicity impacts from the natural gasoxyfuel system, for the coal systems, these processes comprise26% of HTP, 79% of TETP, 36% of FETP, and 39% of METP impact.Direct emissions from the coal plant contribute mainly to the HTPscore, and the power plant waste treatment processes (FGD, coalash disposal, etc.) contributes significantly to the METP and FETPscores.

Overall, it is found that the reduction of the GWP by CCS tech-nologies has considerable tradeoffs. The significant increases ineutrophication and toxicity potentials render the performance ofCCS systems even lower than the world average technologies for

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hese impact categories. The infrastructure development of theacilities contributes mainly to various toxicity potentials. Fuel pro-uction, direct emission from the power plant, and waste treatmentre major contributors to the other impacts. A closer evaluationf fuel chain with ReCiPe (2009) shows significant contributionsrom fuel transport to per unit of fuel supply. This contribution isypically higher for coal supply (30–60%) as compared to naturalas (15–30%) for most of the impact categories – except for globalarming impact, where transoceanic transport makes about 8% ofWP for coal and pipeline transport makes 38% for natural gas pernit of fuel supply. The MEA production chain also makes a sub-tantial contribution to almost all impacts from post-combustionCS systems. The capture process in itself provides a co-advantagef reducing eutrophication and particulate formation depending onhe technology, but increases various toxicity potentials (for post-ombustion only). Further, the CCS energy requirements increasemissions throughout the value chain.

.5. Sensitivity analysis

A sensitivity analysis is performed for the CO2 transport dis-ance to understand the influence of the transport chain on thempacts. Existing long-distance CO2 pipelines range from about00 km (90 km – Bati Raman, Turkey) to 800 km (808 km – Cortez,SA) (IPCC, 2005). In this study, analysis is made for 200, 500, and000 km pipeline transport systems for sequestering 1 and 2 Mt/yach (1 and 2 Mt/y are the approximate CO2 mass transport ratesrom a 400 MW natural gas and coal power plant, respectively).he infrastructure requirement for pipeline and recompressor sta-ions, and the energy demand for compression, will vary for theases causing changes in impacts with distance. Any recompres-ion needed before injecting CO2 to the storage site is included inhe transport chain so as to have fewer recompression stations inhe CCS chain. It is assumed that CO2 is always maintained wellbove the critical pressure (minimum at 80 bar), which thereforeequires recompression every 300 km. Table 4 presents the abso-ute impact scores from transport for different sensitivity cases.nalysis shows that transport over 200 km requires no recompres-ion during transport; transport over 500 km needs recompressionnce; and transport over 1000 km needs CO2 recompression athree stations. Further, prior to injecting CO2 at the storage site,ecompression is needed for the 200 and 500 km pipeline trans-ort cases, while the energy supplied at the last station for the000 km case is sufficient to inject CO2 without compression. Theesults show increases in all impacts as expected, and it alsohows that the environmental cost per unit mass of CO2 trans-orted for long distance transfer is lower for a system transporting

arger amounts. The majority of the impacts come from transportnfrastructure development (pipeline), with a considerable amountoming from the energy demand as well. The contribution from thenergy requirement to all impacts increases with transport rate andistance.

.6. Uncertainties

For all CCS options in this study, the leakage of CO2 is assumedegligible. Leakage rates between 1% and 0.00001% per year areiscussed in literature, and the lower leakage values are justifiedy the existence of natural underground CO2 deposits of substan-ial age (Holloway, 2005). Monitoring of the transport network andtorage site is also not included in the system.

There is uncertainty about non-CO2 emissions for the future

lant technologies. For the oxyfuel power plant, NOx is assumedo be reduced by 50% due to the absence of thermal NOx andeduction of NO to molecular nitrogen. Literature suggests an evenigher reduction of 80% in the case of a hard coal plant (US DOE,

house Gas Control 5 (2011) 911–921 919

2007 in Pehnt and Henkel, 2009); however, there are also stud-ies that suggest no NOx reduction (Johnsson et al., 2006; Varaganiet al., 2006 in Pehnt and Henkel, 2009). Values for NOx emis-sions affect photochemical oxidant formation, particulate matterformation, acidification, and marine eutrophication impacts. Thephysical solvent (selexol) used in pre-combustion carbon captureis assumed to have no losses to the atmosphere or emission ofsolvent degradation wastes; however, there is no literature foundanalyzing the possible reaction/degradation mechanism for thecompound.

Concerning the power plant technology with CCS, the mostimportant uncertainty is the overall efficiency which is significantlyinfluenced by the energy penalty resulting from solvent regenera-tion and, for oxyfuel, the air separation unit. This study estimatesthe energy penalty based on available literature. Because this isan important economic parameter, it is the major focus of furtherresearch (by modification in solvents, power cycles, process opti-mization, etc.). Any decrease in energy penalty will significantlyreduce the impacts from the fuel chain.

The US input–output economic model is used to calculate theimpacts from the infrastructure development of power plant facil-ities. This model has extensive economic data on 500 industrialsectors and is linked to data on many environmental interventions.The US is a mixed economy fuelled primarily by fossil energy. Thisis taken as a possible proxy of the global economy which is alsofuelled mainly by oil and coal; however, a more accurate calcu-lation needs a global input–output model with detailed data onemissions, which is currently not yet available.

Making a globally applicable assessment is complex and nearlyimpossible due to differences in technologies, production pro-cess efficiencies, and waste treatment techniques world-wide, etc.However, this study attempts to provide a generic comparativeanalysis of different CCS options. In this study coal is assumed tocome from Central Europe and natural gas from the North Searegion, considering that regions having availability of particularfuel type are likely to have same fuel based CCS options. Other mate-rial production is based on average European technology. Transportof materials/fuel to other specific sites will incur additional envi-ronmental impacts. Thus, each CCS case implementation will haveregional influence from raw material production, coal/natural gasproduction or import, transport of materials to the site, coal or gasbased economy, etc.

5. Conclusion

The goal of this study was to compare the life cycle environ-mental impacts of electricity generation from possible CCS optionswith coal and natural gas. The results of the study reveal thatthe CCS systems achieve a significant reduction of greenhousegas emissions but have multiple environmental trade-offs depend-ing on the technology. The implementation of CCS reduces thegreenhouse gas emissions by 74%, 78%, and 76% from coal sys-tems with post-combustion, pre-combustion, and oxyfuel capture,respectively. For natural gas CCS systems, the reduction in GHGs is68%, 64%, and 73% for post-combustion, pre-combustion, and oxy-fuel capture, respectively. For cases with CCS, a major portion ofGWP (52–73%) for natural gas emanates from the fuel productionchain, and 17–42% from the power plant. The CO2 transport andstorage chain contributes only about 2% to the total GWP impact.For coal CCS systems, fuel combustion is still the major source ofGWP (52–56%). There is a net increase in all other environmen-

tal impact categories (except some reduction (7–15%) in TAP andPMFP for post-combustion coal CCS system and in MEP and POFPfor oxyfuel CCS system with natural gas), mainly due to the energypenalty (from capture process, air separation units, and other
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rocesses in value chain) of infrastructure development, directmissions, and wastes, from the capture process. Human toxic-ty impact increases by 40–75%, terrestrial ecotoxicity by 60–120%,nd freshwater eutrophication by 60–200% for the different tech-ologies. Much of this increase is due to disposal of wastes frometal manufacturing and solid waste treatment at power plants. It

hould be emphasized that high trade-offs are the result of emis-ions given specific emissions intensities of fuel production, wastereatment and manufacturing in our data sources. More favorableesults can certainly be obtained reducing emissions through bet-er technologies and better management practices along the lifeycle.

The GWP reduction over the complete life cycle of 64–78% forarious CCS systems agrees with the findings of 60–80% GHG con-rol in the referenced literature (Koornneef et al., 2008; Odeh andockerill, 2008; Pehnt and Henkel, 2009; Viebahn et al., 2007). Odehnd Cockerill qualitatively suggested increases in eutrophication,cidification, toxicity, and photo-oxidant formation with CCS, andoornneef et al., Pehnt and Henkel, and Viebahn et al. quantified

hese impacts for all/selective coal CCS systems. This study confirmsnd quantifies these impacts for the possible CCS configurationsith both coal and natural gas fuel.

Although the technologies assessed are not at the same levelf maturity, this comparative study underlines the concern for theype and magnitude of possible impacts. This study also identifieshe key areas to reduce trade-offs, and it is also found that technicalevelopments to reduce energy penalty, degradation products, andolid waste management from disposal processes are required toeduce the negative environmental impacts.

cknowledgements

This study has been financed by a PhD stipend from Norwe-ian University of Science and Technology. We thank Ryan Matthewright for reviewing the language of this manuscript.

ppendix A. Supplementary data

Supplementary data associated with this article can be found, inhe online version, at doi:10.1016/j.ijggc.2011.03.012.

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