Life cycle GHG assessment of fossil fuel power plants with carbon capture and storage

ARTICLE IN PRESS

Energy Policy 36 (2008) 367–380 www.elsevier.com/locate/enpol

Life cycle GHG assessment of fossil fuel power plants with carbon capture and storage Naser A. Odeh, Timothy T. Cockerill School of Construction Management and Engineering, The University of Reading, Whiteknights, P.O. Box 225, Reading, Berkshire RG6 6AY, UK Received 22 June 2007; accepted 17 September 2007 Available online 29 October 2007

Abstract The evaluation of life cycle greenhouse gas emissions from power generation with carbon capture and storage (CCS) is a critical factor in energy and policy analysis. The current paper examines life cycle emissions from three types of fossil-fuel-based power plants, namely supercritical pulverized coal (super-PC), natural gas combined cycle (NGCC) and integrated gasification combined cycle (IGCC), with and without CCS. Results show that, for a 90% CO2 capture efficiency, life cycle GHG emissions are reduced by 75–84% depending on what technology is used. With GHG emissions less than 170 g/kWh, IGCC technology is found to be favorable to NGCC with CCS. Sensitivity analysis reveals that, for coal power plants, varying the CO2 capture efficiency and the coal transport distance has a more pronounced effect on life cycle GHG emissions than changing the length of CO2 transport pipeline. Finally, it is concluded from the current study that while the global warming potential is reduced when MEA-based CO2 capture is employed, the increase in other air pollutants such as NOx and NH3 leads to higher eutrophication and acidification potentials. r 2007 Elsevier Ltd. All rights reserved. Keywords: Carbon capture; GHG analysis; Power plants

1. Introduction Climate mitigation policies place an emphasis on fossilfuel power generation technologies since they are a major contributor to worldwide carbon emissions, making up more than 24% of total greenhouse gas (GHG) emissions (Stern, 2006). Recently, the concept of carbon capture and storage (CCS) as a means for reducing CO2 emissions from power plants has emerged with several projects planned worldwide (IPCC, 2005). The option of capturing CO2 and storing it offers a means of allowing the large reserves of fossil fuels to be utilized while at the same time controlling GHG emissions. Considering that the UK derives more than 90% of its primary energy and generates more than 70% of its electricity from fossil fuels and since the UK has access to a substantial CO2 storage capacity (Marsh, 2003), CCS is considered a viable option for the UK.

Corresponding author. Tel.: +44 118 378 8923; fax: +44 118 931 3856.

E-mail address: [email protected] (N.A. Odeh). 0301-4215/$ - see front matter r 2007 Elsevier Ltd. All rights reserved. doi:10.1016/j.enpol.2007.09.026

CCS is an energy-intensive process, which lowers the overall efficiency of the power plant. In order to compensate for this efficiency loss, more fossil fuel per unit of electrical output must be used thus leading to further emissions. Furthermore, while capturing CO2 from the power plant can reduce direct emissions from the power plant itself, upstream emissions resulting from fuel and material procurement and downstream emissions resulting from waste disposal cannot be captured. These upstream and downstream emissions are small when compared with emissions from combustion. However, when CCS is included, these emissions become dominant and so they must be included in the assessment. In light of these considerations, the current paper investigates the global warming potential (GWP, g CO2-e/kWh) and energy balance of three generation technologies using a life cycle approach. The technologies considered are supercritical pulverized coal (super-PC), natural gas combined cycle (NGCC) and coal-based integrated gasification combined cycle (IGCC). Analysis is conducted for each of the three technologies with and without CCS, and the results are

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N.A. Odeh, T.T. Cockerill / Energy Policy 36 (2008) 367–380

compared with those from a sub-critical PC (sub-PC) power plant. The PC power plants studies (both sub-PC and super-PC) are equipped with NOx, particulates and SO2 removal processes (i.e. selective catalytic reduction, SCR, electrostatic precipitation, ESP and flue gas desulfurization, FGD). The NGCC power plant on the other hand, is equipped with NOx control. Over the past three decades, many studies have been undertaken on life cycle emissions (LCEs) from fossil fuel generation technologies (Lave and Freeburg, 1973; Schaefer and Hagedorn, 1992; Bates, 1995; Proops et al., 1996; Norton, 1999; Hondo, 2005; Kannan et al., 2007), renewable generation technologies (Gagnon and Van de Vate, 1997; Dey and Lenzen, 2000; Pacca and Horvath, 2002; Denholm and Kulcinski, 2004) and nuclear generation technology (Dones et al., 2005). A summary of emissions from different fossil and non-fossil generation technologies is given by Odeh and Cockerill (2007a). As interest in CCS has heightened in recent years, several environmental and LCA studies of CCS systems have been conducted (Livengood et al., 1993; Waku et al., 1995; Spath and Mann, 2004; Viebahn et al., 2007; Tzimas et al., 2007). Table 1 gives a summary of some studies on life cycle assessment of power plants with CCS. A more detailed review is given by Odeh and Cockerill (2007b). Section 2 introduces the boundaries and methodology adopted for the present life cycle assessment. Section 3 outlines the life cycle assumptions, while Section 4 gives a detailed description of the power generation technologies considered. Finally, Sections 5 and 6 give a summary of the results and conclusions for the different CCS and non-CCS systems. The results are given for life cycle GHG emissions, resource consumption and net energy ratio. A sensitivity analysis is then undertaken to investigate the effect of some key parameters on the total GHG emissions for each of the systems. Finally other environmental impacts such as acidification and eutrophication resulting from additional air pollutants (such as NOx, SO2 and NH3) are discussed.

Table 1 Summary of studies on life cycle analysis of CCS systems Study Livengood et al. (1993)

Assumptions

 IGCC  458 MW plant  CO2 recovery by Selexol

Key results

 Output reduced to 383 MW net

 Efficiency reduced from

process

Waku et al. (1995)

38.8% to 33.1%

 90% capture  500 km CO2 transport  Geological storage

 Emissions reduced from

 Compared IGCC to

 For systems without CCS,

    

liquefied NGCC 600 MW power plants Used MEA process for Liq. NGCC and Selexol process for IGCC 90% CO2 capture Transport by pipeline and ship (100–500 km) Injection depth 2000–3000 m

872 g CO2-e/kWh (without CCS) to 218 g CO2-e /kWh (with CCS)







Spath and Mann (2004)

      

Studied PC and NGCC 600 MW MEA process 90% capture Lost capacity is compensated for by an NGCC plant Transport by pipeline (300–1800 km) Injection to 800 m

 GWP decreased from the



2. Current methodology Generally, a life cycle study consists of four steps: goal and scope definition, inventory analysis, impact assessment and improvement assessment (Khan et al., 2005). In the first two steps, boundaries of the analysis are defined and impacts of the different processes of the system are calculated. The third and fourth steps examine the actual environmental and human health effects from the use of resources (energy and materials) and environmental releases and give recommendations for reducing these effects. The current study focuses on the first two steps.

Viebahn et al. (2007)

The boundaries for the current analysis are shown in Figs. 1–3 for PC, NGCC and IGCC technologies with and without CCS. Each of the process blocks shown in

a

reference case by 71% for both PC (from 847 to 247 g/kWh) and NGCC (from 499 to 245 g/kWh) With CCS, resource consumption increased by 17% for PC and 15% for NGCC (relevant to reference PC technology without CCS)

 Compared PC, NGCC and  GHG emission reduction IGCC

 MEA process for PC and

 

2.1. System boundaries

fuel combustion is the dominant source of emissions (82% NGCC, 91% IGCC) For systems with CCS, NERa for liquefied NGCC is lower than for IGCC because of high energy requirements for gas liquefaction CO2 emissions reduced by 61–69% for liquefied NGCC and 65–76% for IGCC Ship transport is more advantageous (in terms of NER and LCEs) at large transport distances. For short distances, both methods of transport give similar results

NGCC. Physical absorption with Rectisol for IGCC. 88% capture CO2 Transport by pipeline (300 km) to empty natural gas fields in Northern Germany





the technology in the range 65–79% depending on technology (higher value for PC with lignite) GHG emissions with CCS (g CO2-e/kWh): 274 for PC, 200 for NGCC, 240 for IGCC For CCS systems, emissions due to capture and liquefaction of CO2 are more significant than emissions from transport and storage

Net energy ratio (NER) defined as the output energy over the lifetime of the system divided by energy spent on construction, operation and maintenance of the system.

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369

Steel Concrete Aluminum

Material Transport

Power Plant Construction

Iron electricity

Fuel Material / fuel production

Fuel Handling

Air Water Limestone

Material Transport

Power Generation

By-products Gypsum, ash Air emissions: CO 2, H 2 O, SOx, NOx, NH 3 , HCl, Particulates

Waste Transport

Ammonia Pollutant Removal (i.e.SCR, ESP, FGD)

SCR Catalyst Transport Fuel (i.e. light or heavy fuel oil)

Waste water

Solid waste: SCR catalyst, sludge, boiler slag

Waste Disposal: Landfilling / recycling

Power Plant Decommissioning

Steel Concrete Aluminum

Material Transport

Iron

Capture Plant Construction

Power Plant Construction

CO2 Pipeline Construction

Fuel Fuel Handling Air Material / fuel production

Water

electricity Material Transport

Power Generation

By-products: CO 2 captured, Gypsum, ash

Limestone Ammonia SCR Catalyst MEA NaOH

Pollutant Removal (i.e.SCR, ESP, FGD, Sulphur removal, etc.)

Waste Transport

Waste water CO2 Capture (MEA process)

Activated Carbon

Transport Fuel (i.e. light or heavy fuel oil)

Air emissions: CO 2 , H 2 O, SOx, NOx, NH 3 , HCl, Particulates

CO2 Compression

Solid waste: SCR catalyst, sludge, boiler slag, activated carbon, MEA waste

Waste Disposal: Landfilling / recycling

Power/Capture Plant Decommissioning

Fig. 1. (a) Life cycle boundaries for PC power plants without CCS and (b) life cycle boundaries for PC power plants with CCS.

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370

Steel Concrete Aluminum

Material Transport

Power Plant Construction

Iron electricity

Fuel

Material / fuel production

Air Power Generation Water

Material Transport

Air emissions: CO 2, H 2 O, NOx, NH 3

Ammonia Pollutant Removal (i.e.SCR)

SCR Catalyst Transport Fuel (i.e. light or heavy fuel oil)

Waste Transport Waste water

Solid waste: SCR catalys

Waste Disposal: Landfilling / recycling

Power Plant Decommissioning

Steel Concrete Aluminum

Material Transport

Iron

Capture Plant Construction

Power Plant Construction

CO2 Pipeline Construction

Fuel Air electricity Material / fuel production

Power Generation

Water

By-products: CO 2 captured Ammonia

SCR Catalyst

Material Transport

Pollutant Removal (i.e. SCR)

Air emissions: CO 2 , H 2 O, NOx, NH3 Waste Transport

MEA NaOH

CO2 Capture (MEA process)

Waste water

Activated Carbon CO2 Compression Transport Fuel (i.e. light or heavy fuel oil)

Solid waste: SCR catalyst, activated carbon, MEA waste

Waste Disposal: Landfilling / recycling

Power/Capture Plant Decommissioning

Fig. 2. (a) Life cycle boundaries for NGCC power plants without CCS and (b) life cycle boundaries for NGCC power plants with CCS.

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Steel Concrete Aluminum

Material Transport

Power Plant Construction

Iron electricity

Fuel Fuel Handling Material / fuel production

Air

Water

Material Transport

Claus Plant Catalyst for Sulphur removal

Power Generation

Pollutant Removal (Sulphur removal, tail gas treatment)

Transport Fuel (i.e. light or heavy fuel oil)

By-products Ash, Sulphur Air emissions: CO 2, H 2 O, SOx, NOx, NH 3 , HCl, Particulates

Waste Transport

Waste water Solid waste: Claus plant catalyst, sludge, gasifier slag

Waste Disposal: Landfilling / recycling

Power Plant Decommissioning

Steel Concrete Aluminum

Material Transport

Iron

Capture Plant Construction

Power Plant Construction

CO2 Pipeline Construction

Fuel Fuel Handling electricity

Air Material / fuel production

Power Generation

Water

Selexol

Material Transport

Pollutant Removal (i.e.SCR, ESP, FGD, Sulphur removal, etc.)

Claus Plant catalyst

By-products: CO 2, Ash, Sulphur Air emissions: CO 2 , H 2 O, SOx, NOx, NH 3 , HCl, Particulates

Waste Transport

Waste water Waste Disposal: Landfilling / recycling

CO2 Capture (Selexol process) Transport Fuel (i.e. light or heavy fuel oil)

Solid waste: catalyst, Gasifier slag CO2 Compression

Power/Capture Plant Decommissioning

Fig. 3. (a) Life cycle boundaries for IGCC power plants without CCS and (b) life cycle boundaries for IGCC power plants with CCS.

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Figs. 1–3 consists of energy and/or materials as inputs and emissions as output. In addition to accounting for direct emissions from fuel combustion in the power plant, other emissions arising from upstream (e.g. production and transport of limestone, ammonia, catalyst, etc.) and downstream (e.g. waste transport and disposal) processes, as well as emissions from power plant construction and decommissioning, are also included. Extracting the materials used for constructing the power plant, the capture plant and the CO2 transport pipeline are also accounted for. For downstream processes, waste transport and disposal in a near-by landfill are considered. In PC coal power plants, for example, waste is generated by the boiler and ESP process as bottom ash and by the FGD process as gypsum and calcium chloride (Rubin et al., 1991). For CCS systems where the capture process is MEA-based, waste is generated in the re-claimer where NaOH is used to reclaim MEA from salts resulting from MEA oxidation. For coal-based power plants, emissions arising from mining activities such as methane leakage and machinery operation are included. For natural gas fuel cycle systems, on the other hand, upstream emissions include those from gas exploration, extraction, processing and compression as well as from methane leakage during extraction and transport. Emissions from pipeline construction (and associated steel requirements for constructing the pipeline) are also accounted for. 2.2. Life cycle data and methods of GHG analysis Two methods for life cycle GHG assessment of power plants can be employed as shown in Fig. 4. A power plant techno-economic model is used to estimate material and energy requirements and costs. The input parameters for the model are discussed in Section 4. Data of GHG content (kg CO2/kg material produced) and energy content (MJ/kg material produced) are obtained as described by Dey and Lenzen (2000) from process chain analysis (PCA), while data of GHG intensity (kg CO2/£ material produced) and energy intensity (MJ/£ material produced) are obtained from an input/output analysis (IOA). Process chain analysis is usually based on data obtained from previous studies, from stakeholders, or from available software packages. The EcoInvent database of the software SimaPro (by Pre´Consultants), which contains data applicable for Western Europe in general, has been used in the current study. Input/output (I/O) analysis is based on data obtained from UK I/O tables as described by Proops et al. (1996). In order to obtain annual emissions from operation, the results from PCA and IOA are multiplied by the material requirements and costs obtained from the techno-economic model as shown in Fig. 4. Annual emissions are multiplied by the power plant lifetime to obtain total emissions from operation. The procedure is repeated for all GHG gases within a given process and then for all processes within a life cycle system. For emissions from construction, the

material requirements (for example kg of steel or concrete) or the total costs of construction (£) are multiplied by GHG content or GHG intensity as applicable. For emissions from transportation, quantities of transport fuel (e.g. m3 or kg heavy oil) or costs of transport (£) are multiplied by available factors in units of ‘‘kg CO2-e/m3 heavy oil’’ or ‘‘£/m3 heavy oil’’. Alternatively, factors in the form of ‘‘kg CO2-e/ton.km’’ or ‘‘kg CO2-e/£ worth of transport’’ (which can be obtained from I/O tables for different means of transport) can be multiplied by transport distances and amount of material transported. Total emissions from construction and decommissioning are added to total emissions from operation (production, transport and waste disposal) and the sum is divided by the power plant output over its lifetime. A comparison of results from the methods shown in Fig. 4 for two IGCC plants was undertaken by Ruether et al. (2004). Normalized values of total GWP from the two methods showed that the cost-based IOA provides a more complete accounting of emissions incurred during construction thus resulting in larger estimates of emissions. The authors stated that for plant construction, the material-based PCA resulted in emissions that approximate a subset of emissions computed via the cost-based IOA method. For plant operation, however, only emissions due to mining and consumption of coal at the plant are significant, and both methods of analysis give essentially equivalent results. Hondo (2005) used a combined method of process chain analysis and I/O analysis. The CO2 from materials production was estimated by process analysis, while the CO2 from other processes was roughly estimated using an I/O table. Similarly, the current study uses both methods of analysis depending on the availability of data. 2.3. Energy considerations Life cycle efficiency, which has the same definition as the net energy ratio (NER) shown in Table 1, is the energy output throughout the lifetime of the power plant divided by all sources of energy input from the life cycle of the system over the same period of time. The energy input includes energy contained in the fuel in addition to embodied energy added to the power plant (for example the energy used for construction of the power plant, the energy used to produce limestone and transport it to the power plant, etc.). The percentage reduction of life cycle efficiency from actual power plant efficiency (i.e. the efficiency calculated by dividing the electrical output of the power plant by the energy content of the fuel over the life time of the power plant) is an indication of how significant energy use in upstream, downstream and construction processes is. 3. Life cycle assessment assumptions For the coal life cycle, it is assumed that coal and other necessary materials (including limestone, ammonia and

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Process (e.g. steel, limestone production, etc.)

Power Plant Technoeconomic Model

Literature data, stakeholder, software databases, etc.

I/O tables

Process Chain Analysis

GHG Content (kg CO2-e/kg material manufactured)

Input/Output Analysis

Material Requirements (kg / year)

Multiply to obtain annual emissions in kg CO 2-e/year)

Cost (£ / year)

Power plant lifetime

GHG Intensity (kg CO2-e/£ worth of material manufactured)

Multiply to obtain annual emissions in kg CO 2-e/year)

Total emissions for process over lifetime of power plant

Next process

Power Plant Techno-economic Model Add from all processes Total emissions from all processes over lifetime of power plant

Electrical output (kWh) over lifetime of power plant

Power plant emissions factor (kg / kWh)

Fig. 4. Life cycle analysis by two methods: process chain analysis and I/O analysis.

capture plant chemicals) are produced locally in the UK and according to local technologies. Considering coal mining, it is assumed that 60% of UK coal is obtained from deep mining while the rest is obtained by open-cast mining (Mott McDonald, 2004). Typical characteristics of

UK-mined coal are shown in Table 2. A transport distance of 100 km was assumed for transport of coal as well as other materials. The assumption that all coal used by a UK power plant is locally mined may not be realistic. Due to diminishing

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Table 2 Coal and natural gas characteristics Category

Coal

Type and source Composition (Berry et al., 1998)

UK bituminous coal Ash Moisture Carbon Hydrogen Oxygen Sulfur Nitrogen

LHV, MJ/kg

coal production rates in the UK, a large amount of coal used in power stations is nowadays imported. Recently, for example, interest in Russian coal has grown due to its low sulfur content. More than 7 million tons of coal were imported from Russia between January and April 2005 (CoalTrans International, 2006). The effect of importing all coal required by the power station from Russia is investigated in Section 5.3 as part of a sensitivity analysis. It is assumed that natural gas (Table 2) is extracted from the southern basin of the North Sea. A pipeline length of 300 km was assumed between the power plant and the gas field. A diameter of 75 cm, which is typical for natural gas transport, is assumed. Emissions for producing the steel required to construct the pipeline were taken into account. However, due to lack of data, emissions from digging and laying the pipeline were ignored. A 1% methane leakage is assumed for the reference case. However, a sensitivity analysis is undertaken in Section 5.3 to investigate the effect of natural gas loss on total GHG emissions. The current analysis assumes that natural gas is transported from the extraction platform where it is sweetened and flared. Onshore processing includes gas compression and delivery to the power plant. In general, the LCA of CCS systems accounts for emissions arising from the construction of the capture plant and CO2 pipeline, those arising from the production and transport of chemicals necessary for running the capture plant, as well as those arising from the energy requirements for the transport and injection processes. It is assumed that the captured CO2 is compressed to 13.5 MPa and transported via a 300-km pipeline to the Southern North Sea where it is injected in gas fields (Bentham, 2006). In addition, the current analysis considers electricity requirements for CO2 re-compression along the pipeline. An energy requirement of 3 kW of electricity per km of CO2 pipeline was used based on a calculation from Spath and Mann (2004). Due to lack of data, CO2 leakage from the pipeline and emissions and energy requirements for the injection of CO2 were roughly estimated based on experience in the natural gas and oil industries. Furthermore, it was assumed that leakage from the reservoir over the lifetime of the power plant is negligible.

Natural gas

15.0% 12.0% 60.0% 3.9% 6.0% 1.6% 1.5% 24.5

North Sea Southern basin Methane Ethane Heavier alkanes Nitrogen CO2

93.0% 3.0% 1.0% 2.7% 0.3%

49.2

Coal mine gas field 300 km gas pipeline Power Plant

300 km pipeline

Depleted Gas fields for CO2 storage

Fig. 5. Location of power plant, coal mine, gas field and CO2 storage site.

4. Description of technologies considered The following technologies are considered for analysis





A reference case (reference), which comprises a nonCCS subcritical PC power plant equipped with pollution control processes including SCR for NOx removal, ESP for particulates removal and FGD for SO2 removal. The current study compares LCEs and efficiencies from each of the following technologies to this sub-PC reference plant. Two supercritical PC technologies without (Case1a) and with (Case1b) CCS. Both cases are equipped with SCR, ESP and FGD. A third case (Case1c), which consists of

ARTICLE IN PRESS N.A. Odeh, T.T. Cockerill / Energy Policy 36 (2008) 367–380 Table 3 Model parameters for the PC power plants Parameter Main power plant parameters Steam cycle heating rate, MJ/kWh

Excess air, % Temperature of flue gas exiting boiler, 1C ID fan efficiency, % Percentage of ash in fly ash, % NO2 emission factor, g NO2/kg fuel NO emission as % of NOx SO2 emission as % of SOx CO emission as % of carbon oxides SCR NOx removal efficiency, % Temperature, 1C Activation energy of NH3–NOx reaction, kJ/mol Ammonia slip, ppm Pressure drop across SCR, kPa Number of catalyst layers Catalyst replacement interval, 000 h Catalyst activity at replacement, % Steam ratio for ammonia injection, mol steam/ mol ammonia ESP Particulate removal efficiency, % SO3 removal efficiency, % (typically some SO3 is removed in ESP) FGD SO2 removal efficiency, % SO3 removal efficiency, % Temperature, 1C Pressure drop across FGD, kPa Temperature of flue gas exiting, 1C Limestone to sulphur ratio, mol Ca/mol S Limestone purity, %

Table 5 Model parameters for the MEA-based CO2 capture process Value

8.3 (for Sub-PC) 7.4 (for SuperPC) 20 370 85 80 8 95 99 2 75 370 33.2 2 1.5 1 25 85 15

99.5 50

90 50 150 2.5 55 1.03 92

Table 4 Model parameters for the NGCC power plant Parameter

Value

Gas turbines

Two GE 9FA turbines 8.0 180 10 15.7 70 28 1330 85 98

Steam cycle heating rate, MJ/kWh Excess air, % NOx emissions rate, ppm Air compressor ratio Compressor efficiency, % Pressure loss across combustor, kPa Temperature of flue gas entering turbine, 1C Turbine isentropic efficiency, % Mechanical and generator efficiencies, %

375

a supercritical PC power plant with CCS but without FGD is considered for life cycle assessment. The reason for including this case is to quantify the effect of including or excluding the FGD process on life cycle GHG emissions from the CCS system. While the effect of excluding FGD on the costs of CO2 capture has been previously reported (Rao and Rubin, 2002), the effect

Parameter

Value

CO2 removal efficiency, % SO2 removal efficiency in capture plant, % SO2 removal efficiency in FGD, % (increased from 90% to 98%) SO3 removal efficiency in capture plant, % HCl removal efficiency in FGD, % NO2 removal efficiency in capture plant, % Ash removal efficiency in FGD, % MEA concentration, %w/w Lean CO2 loading, mol CO2/mol MEA Blower efficiency, % Pressure across blower, kPa Temperature increase across blower, 1C Sorbent pump efficiency, % Pressure across pump, kPa Compressor efficiency, % CO2 outlet pressure, MPa

90 99 98 99 95 25 50 30 0.2 75 15 7 75 200 80 13.5

Table 6 Model parameters for the IGCC power plant including the Selexol capture process Parameter

Value

Type and number of gasifiers

Two oxygen-blown GE (Texaco) quench gasifiers 1250 6 0.45 1 4 95:4:1 50

Gasifier temperature, 1C Gasifier pressure, MPa Steam input to gasifier, mol H2O/mol C Carbon loss, % Oxidant pressure (at outlet of ASU), MPa Oxidant composition, %O2:%Ar:%N2 Particulate removal efficiency from syngas, % Sulphur removal system COS to H2S conversion efficiency, % H2S removal efficiency, % COS removal efficiency, % CO to CO2 conversion efficiency, % Sulfur recovery system Sulfur recovery efficiency, % Steam added to shift reactor, mol H2O/ mol CO converted CO2 removal efficiency, % Gas turbines Steam cycle heating rate, MJ/kWh

 

Hydrolyser and Selexol system 98 98 40 95 Claus plant and BeavonStretford tail gas unit 95 1 90 2 GE 9FA 8.0

on LCEs has not been quantified before. The current analysis investigates the effect of removing FGD on LCEs. Two NGCC technologies without (Case2a) and with (Case2b) CCS. Two IGCC technologies without (Case3a) and with (Case3b) CCS.

All power plants considered, including the reference case, are located on the east coast of the UK (Fig. 5). The

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Super-PC-All-CCS Output Parameter Amounts, ton/year Amount of coal Ammonia for SCR Limestone Waste-Ash Waste-FGD Waste-MEA reclaimer SCR catalyst waste Direct CO2 emissions, kg/year Costs Materials, £/year Coal cost Water SCR Catalyst MEA/Selexol NaOH Activated Carbon Construction, M£ Power plant Capture plant Pipeline

Life Cycle GHG Emissions 1176836 Total, g/kWh 2419 82121 Direct 85830 Construction/Decommissioning 161434 Other Operation 15430 * Upstream 10000 - Coal Production 321552810 - Coal transport - Other material production * Downstream 19900000 1259788 Net Power, MW 2500000 Power Plant efficiency, % 6500000 Life cycle efficiency, % 120000 150000

255 % 43.8 1.3 54.9 51.5 50.0 1.4 48.7 3.4

g / kWh 112 3.4 139.9 131.3 65.6 1.8 63.9 8.6

335.0 30.0 27.7

395000000 118000000 8000000

Fig. 6. Excel calculation sheet for life cycle GHG emissions from a supercritical PC power plant with SCR, ESP, FGD and CCS.

capture technology considered for PC and NGCC is postcombustion MEA-based absorption. For IGCC, on the other hand, a pre-combustion physical absorption with Selexol solvent is considered. The power generation capacity for all non-CCS cases was kept constant at 500 MW with a 75% load factor. A power plant lifetime of 30 years was considered. For CCS plants, a capture efficiency of 90% is considered. Other process-specific parameters are outlined in Tables 3–6. These parameters are based on typical values from the literature. The material and energy flows resulting from power plant operations are calculated using a model developed at the University of Reading for technoeconomic analysis of fossil-fuel power generation with and without CCS. The model uses the input parameters outlined in Tables 3–6 to determine material flows and energy requirements for each of the processes (i.e. SCR, ESP, CO2 capture including sorbent regeneration) and equipments (i.e. pumps, fans, CO2 compressor, etc.) associated with operating the power plant (see Fig. 4). It also estimates costs associated with adding CCS (based on a cost database included within the model). These output parameters are then entered into an Excel spreadsheet (Fig. 6) where they are used in combination with a built-in database of GHG content and GHG intensity data as shown in Fig. 4 under the box I/O analysis to estimate production and transport emissions and, consequently, the GWP (emissions in mass CO2-e per kWh of electricity produced) can be determined. The life cycle efficiency defined in Section 2.3 can be calculated by repeating the calculation procedure shown in Fig. 4 with energy content and energy intensity data instead of GHG data. For the MEA process, the parameters considered for modeling the performance were based on the Fluor Daniels

Table 7 Net power and power plant thermal efficiency based on model calculations Case

Net power, MW

Power plant LCA % Reduction efficiency, % efficiency, % in efficiency

Reference 1a 1b 2a 2b 3a 3b

475 453 335 500 432 500 471

35.3 39.6 30.0 50.1 42.8 37.2 32.0

32.9 36.3 27.7 41.0 36.5 35.0 30.2

6.8 8.3 7.7 18.2 14.7 5.9 5.6

Econamine FG process (Sander and Mariz, 1992). The steam used for regenerating MEA is taken from the main power plant and so no auxiliary natural gas power plant was considered. The calculated emissions per kWh were based on the net power produced from the plant and so the plant with CCS used the same amount of fuel as in the case without CCS. 5. Results and discussion 5.1. Power plant performance results The net power and corresponding efficiency for each of the technologies is shown in Table 7. For the reference power plant, a 25 MW reduction (475 instead of 500 MW) is caused by the air blower, coal pulverizes and the steam cycle pumps and cooling system. For the super-critical PC system, additional energy penalties are caused by the SCR (3 MW), ESP (1 MW) and FGD (18 MW) processes. The addition of CCS to super-PC imposes an energy penalty of 118 MW (26%). Corresponding energy penalties for

ARTICLE IN PRESS N.A. Odeh, T.T. Cockerill / Energy Policy 36 (2008) 367–380 Table 8 Resource consumption Case

Fuela,b

Limestoneb

NH3b

MEAb

Selexolb

Waterc

Reference 1a 1b 2a 2b 3a 3b

329.7 294.9 390.1 130.1 151.9 314.9 365.9

19.0 16.9 27.2 – – – –

0.68 0.61 0.80 0.20 0.23 – –

– – 3.6 – 1.33 – –

– – – – – 0.02 0.03

3.1 3.1 4.1 nad nad 0.6 0.9

a

Fuel consumption as coal for cases 1a, 1b, 3a and 3b and natural gas for cases 2a and 2b. b All figures in these columns are in units of g/kWh. c Consumption of water is in in units of l/kWh. d Data for water consumption by NGCC are not calculated by model.

Table 9 Summary of life cycle emissions (g CO2-e/kWh) and fuel consumption (MJ/kWh) of the different technologies Case

Fuel Change for reference sub-PC Life cycle consumption, system emissions, g CO2-e/kWh MJ/kWh Change in Change in GWP, % fossil energy consumption, %

Reference 1a 1b 2a 2b 3a 3b

984 879 255 488 200 861 167

8.4 8.4 10.0 6.4 7.8 8.2 9.5

NA 11 74 50 79 13 83

NA 0.0 19.0 -24.6 7.2 3.0 12.1

NGCC and IGCC due to CCS are 15% and 7%, respectively. Table 7 reveals that for NGCC systems, life cycle efficiency is much lower than power plant efficiency. This reflects the fact that upstream processes in the natural gas cycle are more energy intensive in comparison to upstream emissions from the coal fuel cycle. Fuel and other material consumption for each of the technologies are shown in Table 8. For all power plants, the inclusion of CCS increases fuel consumption by 15–30% on a g/kWh of electricity-produced basis. The large increase in fuel consumption for PC is an indication of the high energy penalties associated with CCS when used with PC. The increase in limestone consumption shown in Table 8 for PC power plants with CCS is due to the fact that the model increases the SOx removal efficiency from 90% to 98% when CCS is considered (Rao et al., 2004). This is necessary in order to avoid significant MEA losses due to the strong reaction of MEA solvent with SO2. MEA is very reactive with acid gases (SO2, SO3, NO2 and HCl in addition to CO2). As a result, it is seen from Table 8 that MEA consumption is higher for PC than for

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NGCC because more acid gases are associated with the coal technology. Further discussion of the results in Table 8 is reported by Odeh and Cockerill (2007b). 5.2. Life cycle GHG emissions LCEs for each of the non-CCS and CCS technologies are compared in Table 9. All systems with CCS show a large reduction in life cycle GHG emissions. The highest reductions from the reference case are obtained with IGCC followed by NGCC. The contribution of different sections of the life cycle to GHG emissions is shown in Fig. 7. It is evident that emissions from the construction phase are negligible both for CCS and non-CCS systems when compared with other LCEs. LCEs from super-critical PC power plants without CCS are 10.6% less than LCEs from the reference subcritical case. This difference is a reflection of the higher efficiency and consequent lower fuel consumption by the supercritical power plant. For IGCC without CCS, LCEs are only 2% lower than LCEs from supercritical PC. Moreover, LCEs from NGCC without CCS are, as expected, 50% less than emissions from the reference case. For NGCC, upstream GHG emissions from gas extraction and transport constitute 26% of all LCEs emissions. For the coal life cycle on the other hand, upstream emissions constitute 6–10% of all GHG emissions (depending on whether the technology is PC or IGCC) For the super-critical PC power plant with CCS, LCEs are 74% less than emissions from the reference case. Emissions attributed to CCS (capture, transport, injection and construction of power plant and CO2 pipeline) account for 10% of all LCEs. For Case2b (NGCC with CCS), LCEs are 79% lower than the reference case and only 18% lower than the reference case. This is because upstream emissions for the natural-gas fuel cycle are more significant than they are for the coal fuel cycle. Finally, for Case3b (IGCC with CCS), LCEs are 83% less than for the reference case. Emissions from Case3b are lower than those from Case2b due to the low operations and maintenance costs of the Selexol process in comparison to the MEA process. Moreover, the modeling of the IGCC process does not account for limestone requirements for SO2 removal because SO2 removal is performed with a Selexol system instead of an FGD system and so the only requirements for the power plant are those of coal in addition to water. Ruether et al. (2004) reported that IGCC with 90% CO2 capture exhibits lower life cycle GHG emissions than NGCC, which agrees with results from the current study. An important conclusion can be drawn from Fig. 7 regarding Case1c (super-PC with CCS and without FGD). It is recognized that SO2 reacts strongly with MEA and so, if FGD is not included upstream of CCS, large quantities of MEA will be needed to remove CO2. Tzimas et al. (2007) state that SOx emissions from coal power plants should be decreased to avoid significant losses of the chemicals that are used to capture CO2. In fact, modeling reveals that in

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378

Construction CCS-Capture, transport & injection Power Plant - indirect emissions Direct - Combustion

1000 900 800

72 % reduction

g CO2-e/kWh

700

81 % reduction

If FGD is not included before CCS, significant emissions result from the capture process due to using large amounts of MEA

600 500

59 % reduction

400 300 200 100 0 Sub-PC

Super-PC

Super-PC + Super-PC + CCS CCS - No FGD

NGCC

NGCC + CCS

IGCC

IGCC + CCS

Technology Fig. 7. Comparison of GHG emission from different technologies with and without CCS.

5.3. Sensitivity analysis of GHG emissions

Table 10 GHG emissions sensitivity analysis results (%) Case

A

B

C

D

E

Reference Case1a Case1b Case2a Case2b Case3a Case3b

+3.5 +3.5 +16.9 NA NA +3.3 +24.4

NA NA NA +10.9 +33.2 NA NA

0.09 0.09 0.50 NA NA 0.06 0.4

NA NA +0.05 NA +0.07 NA +0.08

NA NA +14.8 NA +11.3 NA +25.6

Notes: (1) Percentage differences are relative to reference system. (2) NA: not applicable. Sensitivity cases: A: All coal imported from Russia instead of locally mined (same coal composition but varying coal transport distance only). B: Natural gas losses increase from 1% to 3% (most commonly cited CH4 leakage rates, Kirchgessner, 1997). C: 50% of waste (ash and FGD) recovered and used in construction materials. D: CO2 pipeline length increases by 100 km. E: Capture efficiency decreases by 5 percentage points.

the absence of FGD, annual operational costs can increase significantly and can even exceed total capital expenditure due to the relatively high costs of MEA. In addition to the higher costs, the present study also reveals that life cycle CO2 emissions double if FGD was not included prior to the MEA process. This is caused by the emissions arising from the production (and transport) of chemicals (including MEA) necessary for running the MEA process.

A sensitivity analysis was undertaken to determine the effect of several parameters on the total life cycle GHG emissions. The parameters considered in the sensitivity analysis and their corresponding effects are shown in Table 10. It is concluded from Table 10 that for CCS systems the length of CO2 pipeline has a negligible effect in comparison with the effect of capture efficiency. Furthermore, the source of coal has a more significant impact than the length of CO2 transport pipeline. Scenario C compares collecting 50% of the ash and FGD waste (gypsum) and selling it to the construction industry as opposed to landfilling it. For this scenario, emission credits are given for the recycled materials. It is seen that recycling ash and FGD waste does not greatly influence life cycle GHG emissions because of the relatively small amounts of waste produced. For natural gas power plants, the amount of methane leakage from natural gas extraction and transport has a significant effect on life cycle GHG emissions. As expected, this effect is more pronounced with the CCS system because the energy consumption increases. 5.4. Other environmental impacts In addition to GHG emissions, other air pollutants from the coal-fuel cycle include NOx, SO2, particulates and ammonia slipping from the SCR process. IGCC is a cleaner technology than PC and so fewer such emissions

ARTICLE IN PRESS N.A. Odeh, T.T. Cockerill / Energy Policy 36 (2008) 367–380 Table 11 Additional air pollutants Technology

NOx (as NO), SO2, g/ Particulates, g/ NH3, g/kWh g/kWh kWh kWh

Case1a Case1b Case2a Case2b Case3a Case3b

0.410 0.590 0.140 0.160 0.120 0.100

a

1.250 0.009 – – 0.300 0.330

0.058 0.030 – – 0.004 0.004

0.005 0.470 naa naa – –

Data for water consumption by NGCC are not calculated by model.

are expected. From the natural gas life cycle, additional emissions include NOx and ammonia. A comparison of these emissions for CCS and non-CCS systems is shown in Table 11. For Case1, the reduction in SO2 production rate means that the MEA process is a big consumer of SO2 because SO2 reacts extensively with MEA. As mentioned above, the absence of FGD leads to high operational costs of the capture process. Tzimas et al. (2007) explained that for 80% CO2 capture efficiency, SOx emissions are reduced by 99%. The same authors showed that, in the presence of CCS, NOx emissions increase by 5% only. The increase in ammonia production rate (from 0.005 to 0.47) for PC is due to the fact that the oxidation of MEA to organic acids also produces ammonia. Based on data from the Fluor Daniels Econamine FG process, the model assumes that each mole of MEA oxidized produces one mole of ammonia as suggested by Rao et al. (2004). NOx and SOx emissions lead to the formation of acid gases, which can lead to acidification, eutrophication and smog formation (IEA GHG, 2006). The results in Table 11 point out that the reduction of CO2 emissions is achieved at the expense of increasing other emissions like NOx and NH3. As a result, when CCS is included, while the global warming potential is reduced, the eutrophication potential is expected to increase. Based on the data available, the eutrophication potential of PC power plant due to the inclusion of CCS can double. Furthermore, acidification potential (due to acid rain caused by NOx and SOx emissions) is also expected to increase as a result of increasing NOx concentrations. Finally, in the presence of the MEA-based process, human toxicology potential is also expected to increase due to increased emissions of heavy metals in water and due to the MEA hazardous waste. 6. Conclusions and future work The present study shows that life cycle GHG emissions from UK fossil fuel power stations with CCS can be reduced by 75–84% relative to the reference case: a subcritical PC power plant. IGCC is found to be favorable with a reduction of GHG emissions to less than 160 g/kWh. This confirms conclusions regarding low GHG emissions

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from IGCC with CCS that have been reported by previous studies. For supercritical PC with CCS, it is important to remove SO2 prior to the capture plant. Failure to do so not only increases O&M costs but also significantly increases GHG life cycle emissions due to the large quantities of MEA that would be required to make up for losses. For coal power plants, a sensitivity analysis shows that for CCS systems the scenario of importing coal (say from Russia) can have a significant effect on GHG life cycle. This considerable increase is due to the large increase in coal transport distances. Other factors considered here, such as CO2 pipeline length have no significant effect on LCEs. For NGCC power plants, on the other hand, the amount of methane leakage from natural gas extraction and transport has a significant effect on life cycle GHG emissions. The current study shows that while CCS has the potential of decreasing life cycle GHG emissions and consequently the global warming potential, the eutrophication, human toxicology and acidification potentials can significantly increase due to increase in the concentrations of other pollutants. The adoption and operation of CO2 capture technologies may cause significant changes in the environmental assessment and so negative and positive effects of CCS have to be weighed and compared carefully. In addition to the three technologies considered here, future work will also consider oxyfuel combustion and biomass co-firing. Furthermore, the effects of future developments in CO2 capture technologies on reducing GHG emissions (for example due to efficiency improvements) will also be investigated. In this respect, several scenarios (for example making the power plant captureready by 2015 and retrofitting by 2025 as opposed to building the power plant with full capture facilities in 2025) can be compared. Acknowledgments The authors gratefully acknowledge the support for this work provided by the Natural Environment Research Council (NERC) through the UK Carbon Capture and Storage Consortium (UKCCSC). The authors would also like to thank anonymous referees for their valuable comments. References Bates, J., 1995. Full life cycle atmospheric emissions and global warming impacts from UK electricity generation. Technical Report ETSU-R88, Harwell, HMSO, London. Bentham, M., 2006. An assessment of carbon sequestration potential in the UK—Southern North Sea case study. Working Paper 85, The Tyndall Centre for Climate Change Research, UK. Berry, J.E., et al., 1998. Power generation and the environment—a UK perspective. Report number AEAT3776, ExternE Project, AEA Technology Environment, Abingdon, Oxfordshire, UK.

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