Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture, transport and storage

International Journal of Greenhouse Gas Control 5 (2011) 457–466

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Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture, transport and storage Bhawna Singh ∗ , Anders H. Strømman, Edgar Hertwich Industrial Ecology Programme and Department of Energy and Process Engineering, Norwegian University of Science and Technology (NTNU), E1, Høgskoleringen 5, Sør-Trøndelag, Trondheim 7491, Norway

a r t i c l e

i n f o

Article history: Received 9 October 2009 Received in revised form 25 January 2010 Accepted 14 March 2010 Available online 10 April 2010 Keywords: Carbon dioxide capture and storage Life cycle assessment Natural gas combined cycle Structural path analysis

a b s t r a c t Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO2 ) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer. Results show that the sequestration of 90% CO2 from the flue gas results in avoiding 70% of CO2 emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NOx from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs. The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories. © 2010 Elsevier Ltd. All rights reserved.

1. Introduction Human activities have greatly increased the concentration of greenhouse gases (GHGs) in atmosphere, resulting in global warming (IPCC, 2001). CO2 , a greenhouse gas released by the combustion of fuels and from certain industrial and resource extraction processes, makes the largest contribution to anthropogenic climate change. A wide portfolio of technological options for reducing anthropogenic emissions of CO2 is available, with carbon capture and storage (CCS) as a significant potential option (Pacala and Socolow, 2004). Furthermore, CCS draws additional attention as it allows continuing the use of fossil fuels required to satisfy the increasing energy demand. The CO2 arising from large point sources like power plants, refineries, iron and steel plants, etc. can be captured and sequestered in some geological storage for thousands of years (IPCC, 2005). Several power plant projects using carbon capture and storage are planned (ZEP, 2009). The European

∗ Corresponding author. Tel.: +47 73598957; fax: +47 73598943. E-mail address: [email protected] (B. Singh). 1750-5836/$ – see front matter © 2010 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2010.03.006

Commission has proposed a directive providing legal framework for environmentally safe capture and geological storage of carbon dioxide (CO2 ) in the European Union (Commission, 2008). CCS is high on the political agenda in Norway, and the Norwegian Government will construct a full scale CCS project in conjunction with a combined heat and power plant (CHP) in Mongstad with the capture facility planned to be operational in 2014 (MPE, 2006). CCS is an energy intensive process, and demands additional energy, chemicals and infrastructure. Furthermore, the capture process has certain direct emissions to air (NH3 , aldehydes, solvent vapor) and generates solid wastes from degradation byproducts (Rao et al., 2004). A trade-off in environmental impacts is expected, and therefore a systematic process of evaluation for all the stages of CCS is needed. Life Cycle Assessment (LCA) is a well-established method of analyzing environmental impacts in a systematic manner. Much work has been published on technical and economic evaluation of CCS, strengthening the idea of CCS being a major potential option for mitigating global warming. However, most environmental assessments so far have focused on coal fired power plants. The studies differ in terms of the technologies assessed, detail in processes modeled, completeness of the life cycle inven-

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Table 1 Scope of environmental assessments of power generation with CCS system—literature review. Study

Fuel C

Doctor et al. (1993) Summerfield et al. (1995) Waku et al. (1995) Audus and Freund (1997) Rao and Rubin (2002) Lombardi (2003) Benetto et al. (2004) Khoo and Tan (2006) Viebahn et al. (2007) Koornneef et al. (2008) Hertwich et al. (2008) Odeh and Cockerill (2008) Pehnt and Henkel (2009) Korre et al. (2009)

X X X X X X X X X X X X X

Capture NG X X X X

X X X

PoC X X X X X X X X X X X X X

Transport PrC

Oxy

X X X X X

X

X X

P X X X

Storage S

X

G

ER

X X X X

LCA method O X X X

X

X

X

X X X X X X

X

X X X

X

X

Ot X X

MEB X X X X X

FG

Emissions F

X X X X X X

X X X

H

X X X X

CO2 X X X X X X X X X X X X X X

GHG

Ot X

X X X X X X X X X X

X X X X X X X X

Fuel: C, coal; NG, natural gas. Capture: PoC, post-combustion; PrC, pre-combustion; Oxy, oxyfuel. Transport: P, pipeline; S, ship. Storage: G, geological; ER, enhanced recovery; O, ocean; Ot, others. LCA method: MEB, mass and energy balance; FG, foreground LCA; F, full LCA; H, hybrid LCA.

tory and emissions included in the assessment. An overview of the scope of existing LCA studies on electricity generation systems with CCS is presented in Table 1. Doctor et al. (1993), Summerfield et al. (1995), Waku et al. (1995) and Audus and Freund (1997) made some early assessments of different CCS configurations based on mass and energy balance. Waku et al. reported the emission control potential for liquefied natural gas combined cycle power plant and integrated coal gasifier combined cycle power plant (IGCC) in the range of 61–69% and 65–76%, respectively. Summerfield et al. concluded that the majority of the atmospheric emissions comes from fuel processing and transport rather than from the power generation process themselves. Rao and Rubin (2002) used an Integrated Environmental Control Model (IECM) simulation framework to model a complete coal fired power plant with multipollutant environmental controls including CCS and concluded that the CO2 control system generates several new waste products, principally ammonia gas and hazardous reclaimer bottoms, while on the other hand reducing emissions of particulate matter and acid gases such as SO2 , HCl and NO2 . Lombardi (2003) provided a comparative assessment of capture processes for different power plant configurations, focusing on CO2 emission and concluded that IGCC plant gave highest score for greenhouse effect with majority of emissions coming from the maintenance/operation phases. Khoo and Tan (2006) analyzed different capture technologies combined with various sequestration systems for coal fired power plants and concluded that the most promising environmental benefit stems from enhanced coal bed methane production (ECBM) combined with chemical absorption. Viebahn et al. (2007) used an integrated assessment approach for screening-level LCA for CCS and other renewable energies, taking into consideration all relevant technologies and pollutants. For a pulverized hard coal power plant with CCS, the study showed that with a reduction of 65–79% in greenhouse gas emissions as measured by the 100-year global warming potential (GWP). All other environmental impact parameters increase by about 40%. Koornneef et al. (2008) made life cycle assessments of three pulverized coal fired electricity supply chains with and without CCS and concluded that the most notable environmental trade-offs from CCS were human toxicity, ozone layer depletion and fresh water ecotoxicity. Odeh and Cockerill (2008) examined life cycle GHG emissions for fossil fuel power plant with CCS. Hertwich et al. (2008) employed hybrid life cycle assessment method to assess the global warming and acidification impacts over the life cycle of a NGCC combined with CO2 capture for enhanced oil recovery (EOR) and showed a reduction of GHG emissions from power production by 80%. Pehnt and Henkel (2009) presented LCAs for several lignite power plant technologies. Korre et al. (2009)

compared life cycle performance of coal power generation system with and without post-combustion CO2 capture, and also evaluated alternative solvents. Although the latter studies have some focus also on environmental impacts other than global warming, no complete LCA encompassing a broad range of impact categories has been performed yet on generation of electricity by natural gas combined cycle plant with post-combustion CO2 capture, transport and storage. This study compares the life cycle impacts of a natural gas fired electricity supply chain with and without CO2 capture, transport and storage. The assessment is based on hybrid model using detailed physical data for all processes and economic data for infrastructure of the power plant and the CO2 capture facility. The power plant is assumed to be operated in Norway. A detailed CO2 balance gives insight into the overall capture potential and provides the net CO2 credits earned by the CCS chain. This analysis discloses the environmental trade-offs and benefits due to CCS and the results are used to identify the site for potential development in the chain so as to minimize the adverse impacts. Section 2 describes the methodology for the life cycle assessment and Section 3 gives a detailed description of the technology and inventory of the system. Section 4 presents results and discussion for the overall environmental impacts. Further, a sensitivity analysis is made to investigate the variation in potential impacts for the best-case and worst-case of CCS. Section 5 presents the conclusion and outlook for future work. 2. Methods A life cycle study consists of four steps: goal and scope definition, inventory analysis, impact assessment and interpretation. In goal and scope definition the intended application of the study, system boundaries, functional unit and the level of detail is defined. In inventory analysis the raw materials use, energy, products and emissions of the system in relation to the functional unit are determined. Impact assessment examines the environmental pressures of the emissions and resource use quantified in the inventory analysis. Identification of significant issues, conclusions and recommendations are made in interpretation. Several independent studies have found that LCA can suffer from incomplete system boundaries and advocate the combined use economic input–output (IO) and process-based life cycle inventories (LCI), often referred as ‘hybrid life cycle assessment’ to avoid underestimation (Strømman et al., 2006, 2009; Suh et al., 2004; Treloar, 1997). Hybrid LCA offers the advantage of both, the data specificity of process LCA and the system completeness of input–output analy-

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Table 2 Performance parameters for NGCC power plant.

Fig. 1. Foreground system boundaries for the modeled CCS System.

sis. Here, the detailed unit process level information is incorporated into the input–output model of the background economy. A normalized requirements matrix ‘Aij ’, containing a combination of physical and monetary units is defined

 Aij =

Aff A1f A2f

0 A11 A21

0 0 A22



Aff represents the requirements of physical units and describes the interdependency of the foreground processes. A1f and A2f represent the normalized monetary inputs to the foreground process from the domestic production and imports, respectively of the background economy. The economic model of the background economy is disaggregated into A11 and A21 representing the domestic production and imports made from other country, respectively. A22 describes the inter-sectoral requirements in the country, giving inputs to the background economy with no vis-a-vis flows assumed. Flows from foreground to background economies are set to zero, as the product flows associated with the foreground system and the functional unit are negligible compared to the national level flows. Process model data and the Ecoinvent v2 database (Ecoinvent, 2007) are used to generate inter-process matrix and the input–output interindustry matrix is modeled for Norway with all imports assumed to come from Germany (Eurostat, 2000; SSB, 2000). The characteristic procedure for LCA calculations (Heijungs and Suh, 2002) is followed to obtain the output of different processes required by an external demand variable. The characterization factors from ReCiPe 2008 method (ReCiPe, 2009) are used to estimate the potential environmental impacts of the emissions incurred. The factor of 0.24 kg 1,4-DCB-equiv./kg (Veltman et al., 2010) for human toxicity potential of monoethanolamine (MEA) is used. The acidification and eutrophication factors for MEA are assumed to be same as NH3 and a sensitivity analysis is made later to find the dependence of acidification and eutrophication potential on respective MEA characterization factors. A sensitivity analysis is also performed to compare the impact potentials from the possible best and worst CCS cases.

Parameter

Unit

Process Power output (w/o capture) Power output (w capture) Electrical efficiency (w/o capture) Electrical efficiency (w capture) CO2 emission (w/o capture) CO2 capture Full load hours Lifetime

MW MW % % kg/s % h/year years

400 340 55 47.1 40.7 90 8000 25

Economica , b Capital cost (w/o capture) Capital cost (w capture)

$/kW $/kW

568 998

a b

Value

IPCC (2005). Rubin et al. (2007).

The foreground system consists of fuel combustion in power plant, capture process, transport and storage of CO2 . Other emissions arising from upstream, e.g., the production of natural gas, absorbent, etc. and the emissions from downstream, e.g., waste treatment and disposal are also included in the assessment. Emissions from the background system are accounted using hybrid life cycle assessment approach, combining the use of physical and monetary data. The geographical location of the CCS system is in Norway and the imports required are made from Germany. 3.1. Natural gas power plant with capture unit A simplified process outline is provided here and a detailed description of the process can be found in Peeters et al. (2007). Electricity is produced using a state-of-art natural gas combined cycle power plant and the exhaust is supplied to the capture unit. The flue gas stream is cooled and entered at the bottom of the absorber to flow vertically upwards countercurrent to the absorbent. The MEA sorbent chemically absorbs the CO2 in the flue gas, and the scrubbed gases are washed and vented out to the atmosphere. The sorbent is then regenerated in the stripper section by the application of heat, and the hot sorbent is returned to heat exchanger, where it is cooled and then sent back to the absorber. Some fresh MEA is added to make up for the losses (degradation losses and vapor losses) during the process. The CO2 product is then taken to the drying and compression unit. The modeled 400 MW combined cycle power plant has an efficiency of 55%. Tables 2 and 3 give performance parameters of the power plant and capture unit, respectively. The CO2 capture unit has considerable energy demand and reduces the net electricity supply to grid to 340 MW. The captured CO2 is supplied to the transport chain at 110 bar. The energy requirements for the capture process is for regeneration of solvent, solvent pumps, flue gas blower, cooling water pumps and CO2 compression, resulting in an energy penalty of 7.9% (Peeters et al., 2007). The fractional increase in plant energy (E) required per unit of electricity output can be expressed in terms of plant efficiency (ref ) and energy penalty (EP) by the equation:



ref ref − EP



3. System description

E =

The aim of this study is to provide a detailed life cycle assessment of the CCS system where 90% of CO2 is captured from 400 MW NGCC using MEA as solvent, transported via pipelines and stored indefinitely in an offshore aquifer. Fig. 1 shows the foreground system boundaries of the studied CCS system. 1 kWh of net electricity produced is chosen as the functional unit, as this value can be used for direct comparison with other conventional and non-conventional electricity production.

The CCS energy requirement directly determines the increases in plant-level resource consumption and environmental burdens associated with producing a unit of useful product while capturing CO2 . The CCS energy requirement increases in-plant fuel consumption and other resource requirements (such as water, chemicals and reagents), as well as environmental releases in the form of solid wastes, liquid wastes and air pollutants not captured by the CCS system (IPCC, 2005). The process captures 1.055 MtCO2 /year and this

−1

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B. Singh et al. / International Journal of Greenhouse Gas Control 5 (2011) 457–466 Table 4 Inventory for 500 km pipeline.

Table 3 Performance parameters for CO2 capture. Parameter

Unit

Value

Processa CO2 removal efficiency SO2 removal efficiency NO2 removal efficiency Particulate removal efficiency MEA concentration MEA make-up Caustic use in MEA reclaimer Activated carbon use Water make-up Energy penalty

% % % % wt% kg MEA/tCO2 kg NaOH/tCO2 kg C/tCO2 m3 /tCO2 %

90 99.5 25 50 30 1.5 0.13 0.075 0.8 7.9b

Emissionsc MEA loss via vapor NH3 Formaldehyde Acetaldehyde Degradation products

kg/tCO2 kg/tCO2 g/tCO2 g/tCO2 kg/tCO2

a b c d

0.063 0.035 0.262 0.167 1.68d

Nominal value from Rao and Rubin (2002). Peeters et al. (2007). Estimated from Veltman et al. (2010). Average value from NVE (2007).

is credited as negative emission to power plant. The capture system also generates some credits for removal of SO2 , NO2 and particulates. A solvent make-up of 1.5 kg MEA/tCO2 is needed due to its loss via vapors and formation of degradation products (Veltman et al., 2010). Besides chemical solvent, the capture process also requires caustic to reclaim the amine from the heat stable salt and activated carbon to remove degradation products. Air emissions and degradation waste from capture process may cause considerable toxic effects (Aarrestad and Gjershaug, 2009; Knudsen et al., 2009; Thitakamol et al., 2007). These MEA-based emissions are quantified in Veltman et al. (2010) and NVE (2007). Degradation reclaimer waste contains corrosion inhibitors (Thitakamol et al., 2007; Veltman et al., 2010) making it hazardous to landfill and the waste is assumed to be incinerated. The LCI data for fuel production and combustion is derived from the Ecoinvent v2 database (Ecoinvent, 2007). Infrastructure for power plant and capture unit is accounted in economic values attributed to various sectors in Norway I/O 2000 database (SSB, 2000). The upstream processes for the power plant include gas field exploration, natural gas production, natural gas purification, long distance transport, regional distribution and combustion in boilers and power plant. The inventory of the capture operation is based on process modeling data while the inventory for the infrastructure is obtained from the input–output model based on the investment costs for the system. The amount of chemicals consumed and emissions per functional unit is calculated using the performance parameters. Emissions related to production of chemicals used in the capture process are also extracted from Ecoinvent database (Ecoinvent, 2007). 3.2. Pipeline transport Transport mainly requires construction, maintenance, dismantling and monitoring of the pipeline. Some additional energy is also required for recompression of CO2 , to avoid two-phase flow. CO2 compressed to 110 bar at power plant is supplied to pipeline and transported over 500 km, which is a comparable length for any power plant to be situated at north Norway or mainland Europe. The mass flow rate of CO2 is given by 90% capture from power plant system, and is 36.6 kg/s transporting 1.055 Mt/year. The optimum economic pipe diameter (Peters et al., 2003; Zhang et al., 2006) and pipe diameter from IEA (2008) is estimated about 200 mm. The LCI data for pipeline is taken as 1/3 of an offshore natural

Steel Gravel Cement Aluminium Zinc Copper Diesel Electricity

101 113 20 555 29 35 423 16

kt kt kt t t kg MJ GWh

Table 5 Inventory for single well to aquifer. Steel Barite Bentonite Chemicals inorganic Portland cement Lubricating oil Diesel

168 216 16 41 160 48 14.4

t t t t t t GJ

gas pipeline in North Sea with a diameter of 1000 m and 25 mm thickness from ecoinvent v2. This assumption is comparable with the existing Weyburn pipeline (305–356 mm diameter) that carries 1.8 MtCO2 /year (IPCC, 2005). This conservative approach will likely result in overestimation of material requirement. In practice bigger diameter pipelines, with higher mass flow rate are expected to be used, reducing the material use and cost per ton CO2 transported. Additional energy is required for recompression of CO2 , due to the pressure drop. The main factors influencing the pressure drop are the roughness of the pipe, the mass flow and the diameter of the pipe (Wildbolz, 2007). A pressure drop of 10 bar per 100 km (Spath and Mann, 2004; Wildbolz, 2007) demands a recompression station after 300 km to maintain the pressure, well above the critical pressure. LCI data for the pipeline is taken as offshore, long distance natural gas pipeline from ecoinvent v2. The energy required for recompression for a pressure drop of 30 bar and an assumed gas turbine efficiency of 85% is 275 kW. Table 4 gives material and energy required for production of pipeline infrastructure. 3.3. Geological storage Storage mainly requires well drilling, CO2 injection and monitoring. CO2 is to be stored above supercritical pressure, therefore some additional energy is required to introduce CO2 into storage formation at a pressure higher than reservoir fluid pressure. An Utsira-like saline aquifer is assumed as the geological storage site for this study. The Utsira formation is a 200–250 m thick and very permeable sandstone about 800 m below the sea floor. A single well is assumed with injection rate of 36.6 kg/s, vis-a-vis Sleipner project injecting 1 MtCO2 /year. LCI data for the well is taken as offshore drilling well from ecoinvent v2. The energy required for injection is 77 kW, assuming reservoir at hydrostatic pressure of 78.4 bar (Wildbolz, 2007) and overpressure of 20 bar (Wildbolz, 2007; Zweigel and Heill, 2003). Material and energy required for drilling of a single well is given in Table 5. Monitoring of the storage site is not included in this study, and leakage of the injected CO2 is assumed to be negligible. 4. Results and discussion 4.1. CO2 accounting Electricity generation from the NGCC power plant without CO2 capture implies emission of 425 gCO2 /kWh, with over 86% direct emission from fuel combustion, 11% from natural gas production and 3% from infrastructure development. In case of NGCC power

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system with 90% capture efficiency has a net benefit of avoiding 70% of total CO2 emission. 4.2. Environmental impacts

Fig. 2. CO2 accounting.

plant coupled with carbon capture and storage system, this emission intensity is reduced to 125 gCO2 /kWh. Fig. 2 illustrates the CO2 account and compares the emission sources for both the cases, with and without CCS. The capture process at the power plant facility captures 90% CO2 from the flue gas. However, additional CO2 is generated from fuel combustion because of the energy penalty as well as operational inputs and infrastructure required for capture, transport and storage and its operation. The increased CO2 production results in a larger amount of ‘CO2 generated per unit of product’ (508 gCO2 /kWh). Total CO2 captured in production of electricity with CCS system is about 383gCO2 /kWh, reducing the CO2 capture efficiency over the complete life cycle to 75%. More relevant term to understand the net benefit of CCS is the ‘amount of CO2 avoided’. This value reflects the amount of CO2 prevented from being emitted, by putting CCS system in place, and is calculated by comparing the CO2 emissions caused from production of same amount of useful product as a reference plant without CCS CO2 avoided = CO2 emittedw/oCCS − CO2 emittedwCCS = Xa − [Xˇ − X˛f (1 + E)cap ] where X␣ is total CO2 generated over life cycle per unit (kWh) from plant without CCS, X␤ is total CO2 generated over life cycle per unit (kWh) from plant with CCS, f is fraction of direct emission from combustion (0.86), E is capture energy requirement per unit of product (w/ocap /wcap − 1) and cap is the capture efficiency (90%). CO2 avoided in this case amounts to 299 gCO2 /kWh, thus a capture

In addition to CO2 emissions, there are various other direct and indirect emissions throughout all the processes, from raw material extraction for fuel, infrastructure and other materials required to the waste treatment and disposal. Fig. 3 compares the absolute scores after characterization for with CCS and without CCS systems. The result shows that there is an increase in all environmental impacts except the global warming potential (GWP). These scores give the magnitude of impact emanating from the whole life cycle of electricity generation. The impacts are unevenly distributed over various processes, e.g., natural gas exploration, transport, combustion at the power plant, CO2 capture, infrastructure, solvent production, as well as locations, e.g., offshore natural gas production facility, chemical manufacturing sites, power plant facility, dispersed transportation, iron and steel industry, mining sites, etc. Direct emissions at the power plant facility consist of various substances as NOx , SOx , NH3 , MEA vapors, acetaldehyde, formaldehyde and hazardous reclaimer wastes (Veltman et al., 2010). The capture process while capturing CO2 also reduces NOx , SO2 and particulate emission, however their net removal efficiency per kWh electricity generation is lower than the designed performance parameter, due to increased combustion of natural gas to meet the energy requirement of the capture process. The energy penalty also results in increased emission of CH4 , CO and other pollutants which are not captured by the process. Further, there is emission of NH3 , MEA vapor, formaldehyde and acetaldehyde during the capture due to degradation of MEA and vapor loss. These compounds have potential for causing various environmental impacts. Table 6 compares impacts due to direct emissions from the facility and its contribution to total impact, quantifying the immediate hazards from capture technology. Table 7 gives the contribution of NH3 , MEA, formaldehyde and acetaldehyde firstly, to the impact from direct emission at plant facility and then, to the impact over the complete life cycle. Structural path analysis of various impacts is performed to locate the site of impacts within the supply chain, giving detail of the impact from individual processes on the system. SPA Algorithm

Fig. 3. Absolute impact scores after characterization.

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Table 6 Analysis of absolute characterization scores due to direct emission from power plant facility. Impacts

Climate change Acidification Marine eutrophication Photochemical oxidant formation Particulate matter formation Human toxicity Terrestrial ecotoxicity Freshwater ecotoxicity Marine ecotoxicity

kg CO2 equiv. kg SO2 equiv. kg N equiv. kg NMVOC kg PM10 equiv. kg 1,4-DB equiv. kg 1,4-DB equiv. kg 1,4-DB equiv. kg 1,4-DB equiv.

Total impact (/kWh)

Direct impact (/kWh)

w/o CCS

w CCS

w/o CCS

w CCS

change (%)

w/o CCS

Direct/Total impact (%) w CCS

4.59E−01 4.53E−04 6.57E−05 7.01E−04 1.74E−04 1.39E−03 8.72E−07 4.96E−06 9.44E−06

1.67E−01 6.48E−04 8.85E−05 8.51E−04 2.31E−04 3.11E−03 2.12E−06 1.32E−05 2.36E−05

3.70E−01 1.86E−04 4.19E−05 3.47E−04 7.59E−05 1.34E−04 8.40E−08 1.31E−08 1.21E−07

4.72E−02 2.94E−04 5.05E−05 3.85E−04 8.57E−05 1.73E−04 4.48E−07 1.39E−07 1.49E−07

−87 58 21 11 13 29 434 961 23

81 41 64 50 44 10 10 <1 1

28 45 57 45 37 6 21 1 1

Table 7 Relative contribution of air emissions from capture process to various impact categories. Emissions

Impact due to direct emission at plant facility AP

Ammonia Monoethanolamine Formaldehyde Acetaldehyde

% % % %

11 20 0 0

Impact over complete life cycle

MEP

HTP

FETP

METP

TETP

POFP

AP

MEP

HTP

FETP

METP

TETP

POFP

3 5 0 0

0 3 23 <1

0 88 4 <1

0 5 1 <1

0 77 4 <1

0 0 <1 <1

5 9 0 0

2 3 0 0

0 <1 1 <1

0 1 <1 <1

0 <1 <1 <1

0 16 1 <1

0 0 <1 <1

(Peters and Hertwich, 2006; Strømman and Solli, 2008) is used to define various pathways with significant impact. Fig. 4 shows a comparative structural path analysis of global warming potential for production of 1 kWh electricity without CCS and with CCS. Here, the foreground processes are presented as nodes, and the total GWP is distributed along various paths. Table 8 presents a contribution analysis of the process nodes identified using structural path analysis for different impacts. Global warming potential (GWP) result shows a significant reduction of 64% in CO2 equivalents. Structural path analysis in Fig. 4 elaborates the net CO2 equiv. emitted from various chains for both the cases. GWP due to direct emission from electricity generation is given in tier 1, and GWPs from induced background processes

are given in tier 2 and tier 3. Direct emission from power plant without capture and power plant with capture are 370 gCO2 equiv. and 46.9 gCO2 equiv., respectively, per kWh electricity produced. The remaining CO2 equiv. in CCS chain are mainly emitted in the natural gas supply chain. Net reduction of 64% in CO2 equiv. is substantially lower than the total CO2 reduction of 70%. This is due to emission of other GHG substances such as methane (CH4 ), carbon monoxide (CO) and nitrous oxide (N2 O). For without CCS case CO2 emission accounts to 92% of total CO2 equiv., while with CCS case CH4 makes a substantial 22% of the remaining CO2 equiv. 75% of CO2 equiv. in CCS case is still due to emission of CO2 . The contribution from transport and storage chain is relatively small at only about 3% of the total GWP impact.

Fig. 4. Structure path analysis of global warming impact from 1 kWh electricity.

<1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 <1 4 5 4 4 4 4 9 10 26 50 <1 <1 7 15 11 24 <1 <1 <1 <1 <1 <1 <1 <1 3 1 84 82 47 42 2 <1 <1 <1 <1 <1 <1 <1 <1 <1 1 <1 <1 <1 <1 <1 1 <1 1 – 7 – 1 – 1 – 3 – 6 – 9 – 7 – 40 50 25 29 40 42 32 36 4 7 7 16 6 12 13 26 9 5 7 3 10 5 22 10 58 33 1 1 31 29 45 40 <1 – <1 – <1 – <1 – <1 – <1 – <1 – <1 – 12 – 2 – −2 – −1 – 1 – 1 – <1 – 17 – Terrestrial ecotoxicity

Marine ecotoxicity

Freshwater ecotoxicity

Participate matter Formation Human toxicity

Photochemical oxidant formation

Marine eutrophication

Acidification

w CCS w/o CCS w CCS w/o CCS w CCS w/o CCS w CCS w/o CCS w CCS w/o CCS w CCS w/o CCS w CCS w/o CCS w CCS w/o CCS

(%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%)

33 41 55 64 47 50 38 44 5 10 <1 <1 1 1 5 10

NG infrastructure Primary infrastructure Transport and storage Capture unit Power plant

Tier 1 Impacts

Table 8 Contribution analysis for various environmental impacts from NGCC electricity generation.

Tier 2

NG production

MEA production

Other supplies

Waste treatment

Tier 3

Other infrastructure

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Acidification potential (AP) and marine eutrophication potential (MEP) results show increases of 43% and 35%, respectively in the total score. The capture process significantly lowers the direct emissions of SO2 and NO2 , but this removal is not sufficient to offset the effect of increased emissions in the chain. Contribution analysis in Table 8 shows that the direct emissions at plant facility are responsible for 45% and 57% of the total acidification and marine eutrophication, respectively over the complete chain. Table 6 shows increase of 58% and 21% in the direct acidification and marine eutrophication impact, where the direct impact is the impact due to emission of pollutants to air from combustion and capture processes at the power plant facility. NOx emitted from fuel combustion is largely responsible for the above direct impacts (69% and 92%, respectively). Table 7 gives the relative contribution of emissions from capture process to different impacts and it shows that NH3 and MEA vapor emitted from absorber causes 11% and 20%, respectively of direct acidification impact and 3% and 5%, respectively of direct eutrophication impact. A second major contributor to acidification and marine eutrophication is natural gas production accounting for 40% and 25% of the total impact, respectively. Photochemical oxidant formation potential (POFP) is increased by 21% in the CCS system. Though the capture process reduces the score due to SO2 and NO2 removal, however the reduction is insignificant to the impact from increased emission of NOx . Direct emissions from plant facility makes 45% of the total life cycle POFP score. NOx emission from fuel combustion is the main contributor to this impact (94% of the direct impact). Second major source (40%) of the impact is due to emission of CH4 and SO2 in natural gas production chain and about 14% of the impact is from the infrastructure demand. Particulate matter formation potential (PMFP) result shows an increase of 33% in the total score from the life cycle. 37% of the total PMFP impact is attributed to the direct emissions from the plant facility with the NOx emission from fuel combustion being the largest contributor (93%). Natural gas production implies 32% of the impact and 31% is from the infrastructure demand. Human toxicity potential (HTP) shows a significant increase of 124% in the case with CCS system. The main contribution to toxicity is generally associated with the infrastructure requirements and heavy metal emissions associated with the material production. Results show that infrastructure demand causes 84% of the total HTP. The capture system increases the removal efficiency of SO2 and NOx implying a decrease in HTP, however the assumed emission of MEA, formaldehyde and acetaldehyde from the capture system results in net increase of 29% in the direct human toxicity impact from direct air emission at plant facility. Table 7 gives the contribution of these toxic pollutants to the HTP score and shows that the formaldehyde emission causes 23% of the direct HTP score and 1% of the life cycle HTP score. Direct emission of MEA vapor from absorber contributes about 0.19% to total HTP from the complete life cycle. A contribution of 3% is from the waste treatment of power plant and capture unit wastes, with 89% of the fraction coming from the reclaimer bottoms disposal chain. Freshwater ecotoxicity potential (FETP) shows an increase of 167% with the highest contribution of 84% from the waste treatment process (includes disposal of wastes from power plant and capture unit). The disposal of reclaimer solid wastes alone is responsible for 49% of the total FETP score in the CCS system, and is caused by leaching from the landfill for incinerator ash from the reclaimer waste to surface water and ground water. At the power plant facility, a 10-fold increase in FETP is caused by the direct emission of MEA and formaldehyde in the capture process. This steep on-site increase contributes only about 1% to the total score in complete life cycle of the system with CCS. The MEA production chain accounts

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for 6% of FETP score coming mainly from ammonia and ethylene oxide production. Marine ecotoxicity potential (METP) shows an increase of 150% with nearly 47% score from the waste treatment process (with 27% of total METP score from reclaimer waste disposal chain). For the system with CCS, 38% of this impact over complete life cycle is from the infrastructure, and a substantial 9% of the impact is from MEA production, emanating primarily from the ammonia production. Terrestrial ecotoxicity potential (TETP) shows an increase of 143% for the system with CCS. 56% of the impact over the complete life cycle is from the infrastructure development. 22% of the total TETP score is caused by the direct emission from the plant facility, causing fourfold increase in the direct impact. This increase is primarily due to MEA emission contributing 77% and 16% to the direct TETP score and total TETP score, respectively. Overall it is found that the reduction of the GWP has considerable trade-offs. The direct emission of NH3 , MEA vapors, formaldehyde and acetaldehyde contributes significantly to acidification, and various toxicity potentials, and leachate from the treated hazardous reclaimer waste dominates the freshwater and marine ecotoxicity. Many-fold increases in the direct impact scores for FETP and TETP indicates toxic regional hazards. Natural gas production mainly influences photochemical oxidation, particulate matter formation, acidification and eutrophication. The construction of the facilities contributes mainly to various toxicity potentials. Thus, decrease in the energy penalty, reduction in MEA vapor loss and degradation to NH3 and intermediate compounds like acetaldehyde and formaldehyde will likely reduce the adverse impacts of CCS technology. Given the overall importance of the infrastructure (produced by the background economy) and the natural gas value chain indicated in Table 8, results will depend on emissions intensities in the background economy and the gas production. Manufacturing of the facilities in a more emissionsintensive economy (like the United States or China) or sourcing of gas from Russia would increase impacts substantially. 4.3. Sensitivity analysis 4.3.1. Best-case and worst-case A sensitivity analysis is performed for the best-case and worstcase CCS systems to understand the impact behavior with the

Fig. 5. Impacts of electricity generation from NGCC with best-case, worst-case and typical CCS system, relative to a without CCS case.

variation in system performance. The two scenarios are generated by varying the important parameters to their respective high and low values, as given in different literature sources. Table 9 presents the parameters and their respective values selected for this sensitivity analysis. The impacts from the three cases, namely the studied typical CCS system, best-case and worst-case are then compared to electricity generating NGCC system without CCS. Fig. 5 presents the relative impact of electricity generation from NGCC with CCS for the best-case, worst-case and for a typical CCS case. The result shows a decrease of 68–58% in GWP for the two extreme cases, and an increase in all other impacts for all the cases. Toxicity potentials show very large range of variation for the two extreme scenarios. Much of this difference is due to the variation in the energy penalty and emissions from the capture process and waste treatment process. Acidification and marine eutrophication potentials for the best-case CCS system show increases of 20% and 17%, respectively, while for the worst-case CCS system the increases are 99% and 74%. These increases are mainly influenced by the emission of NH3 and MEA in the capture process. A difference of over 230% points in the terrestrial ecotoxicity score for the best-case and worst-case is dominated by the MEA emission during the capture process. A fourfold increase in FETP and METP scores for the worst-case is primarily due to reclaimer waste disposal. The relative score for human toxicity for best-case is 145% and for worst-case is 297%, with MEA emission and energy penalty being the main parameters for this variation in the impact. Thus, the analysis shows that

Table 9 Parameters for best-case and worst-case CCS system. Parameters

Case

Valuea

Unit

Source

Energy penalty

b w b w b w b w b w

5.56 11.4 0.7 3.1 50 25 355 550 10 25

% % kg/tCO2 kg/tCO2 years years $/kW $/kW bar/km bar/km

Lombardi (2003) Riemer and Ormerod (1995) Mimura and Simoyoshi (1997) Chakma (1995) Practical lifetime No lower value IPCC (2005) IPCC (2005) Spath and Mann (2004) Bock et al. (2001)

b w b w b w b w b w

0.04 0.16 6.27 100 0.167 158 0.262 0.262 1.1 3.2

kg/tCO2 kg/tCO2 mg/kgCO2 mg/kgCO2 mg/kgCO2 mg/kgCO2 mg/kgCO2 mg/kgCO2 kg/tCO2 kg/tCO2

NVE (2007) NVE (2007) Harmelen et al. (2008) NVE (2007) No lower value NVE (2007) No lower value No higher value IEA GHG (2006) IEA GHG (2006)

MEA consumption Plant lifetime Capital cost (capture unit) Pressure drop in pipeline Emissions MEA NH3 Acetaldehyde Formaldehyde Degradation products

b, best-case; w, worst-case. a Estimated from the source where not directly provided.

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Fig. 6. Sensitivity of acidification and eutrophication with respect to the MEA characterization factor.

a decrease in solvent (MEA) consumption and energy requirement for the capture process together with a decrease in emission of MEA, acetaldehyde and formaldehyde during capture will significantly control all the trade-offs. 4.3.2. MEA characterization Characterization factor refers to the extent of the impact caused by a unit emission of a certain compound and is defined by modeling the cause-effect chain. MEA may have a certain potential for acidification and eutrophication, however characterization factors for these impacts are not available for MEA. In this study, the characterization factors for acidification and marine eutrophication potentials of MEA are assumed to be same as for NH3 . A sensitivity analysis is then performed to understand the dependence of these impacts on the characterization factors of MEA. Relative impacts are calculated for a ±100% range of the respective characterization factors and are presented in Fig. 6. The result shows that there is an increase of 26% and 8% in the acidification and marine eutrophication impacts, respectively for ±100% range of characterization factors, indicating that the absolute characterization values for MEA will significantly affect these impact potentials. Further, the result shows that the dependence of acidification potential on the characterization factor is higher than that of eutrophication. As the acidification and eutrophication potential also depend on the direct emission of MEA, there is a need to model its fate in the environment and develop the accurate characterization values. 5. Conclusion The goal of this study was to compare the environmental impacts of electricity generation from NGCC with post-combustion CO2 capture using monoethanolamine as solvent, pipeline transport of CO2 and its sequestration, with a NGCC system without CCS. The results of the comparison reveal that the CCS system achieves a significant reduction of greenhouse gas emissions but has multiple environmental trade-offs. The capture process designed to capture 90% of the CO2 in the flue gas captures only 75% of the life cycle CO2 emissions and avoids 70% of total CO2 emission over the life cycle. The implementation of CCS reduces the greenhouse gas emissions by 64%, from 459 gCO2 equiv./kWh to 167 gCO2 equiv./kWh. This figure is lower than 70% net reduction of CO2 due to emission of other GHG substances (CH4 , CO, N2 O). With CCS, a major portion of the GWP (53%) emanates from the fuel production chain and 28% from the power plant. The transport and storage chain contributes only about 3% to the total GWP impact. However, there is a net increase in all other environmental impact categories, mainly due to the energy penalty, infrastructure development and direct emission from the capture process. CCS causes an increase of 21–167% for other impact categories, with a relatively high increase in all the toxicity potentials (124% in HTP, 143% in TETP, 150% in METP, 167%

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in FETP). Emission of MEA from capture process is largely responsible for the steep increase in on-site direct FETP and TETP scores (88% to direct FETP and 77% to direct TETP). Also, the direct MEA emission contributes a significant 16% to the terrestrial ecotoxicity, and only <1% to human toxicity. NOx emission from fuel combustion is largely responsible for increase in most direct impacts other than toxicity potentials and GWP, contributing 69% to direct AP, 92% to direct MEP, 94% to direct POFP and 93% to direct PMFP. Increased infrastructure requirements contribute most to the increase in human toxicity and terrestrial toxicity. Leaching of the incinerated solid reclaimer wastes causes significant fresh water and marine ecotoxicity. The scenario study of best-case and worst-case CCS shows a decrease of 68–58% in GWP, respectively with significant increases in toxicity impacts. The CO2 and GHG emission control over the complete life cycle of 70% and 64%, respectively from this study is also asserted by the findings of 61–72% CO2 control and 59–65% GHG control in the referred literature (Odeh and Cockerill, 2008; Viebahn et al., 2007; Waku et al., 1995). Odeh and Cockerill, 2008 and Viebahn et al. (2007) also qualitatively suggested increase in eutrophication, acidification, toxicity and photo-oxidant formation in NGCC with CCS. Aarrestad and Gjershaug (2009), Knudsen et al. (2009) and Thitakamol et al. (2007), elaborated the possible toxic impacts of amines and other degradation products from capture. This study confirms and quantifies these impacts. The input–output model of Norway having imports from Germany is used to calculate stressors from infrastructure development of power plant and capture unit. This model has data on selected emissions only, which in turn could influence the impact potentials (the limited emission data causes truncation of scores, in particular for the toxicity potentials). The ongoing work on input–output database ‘EXIOPOL’, will present the extensive stressor dataset, and when used in a hybrid model will refine the scores. It is emphasized that the scenario analysis refers to Norway and therefore the background impacts of infrastructure development will vary depending on the economic structure of the geographic location. Further, in this study the MEA characterization factors for acidification and eutrophication are assumed the same as for NH3 , due to their non-availability in any characterization method. Sensitivity of these impacts with the respective MEA factors is calculated and the significant dependence stresses the need to develop its fate model and absolute impact potentials. Assessment of electricity production from NGCC with the current technology for post-combustion CO2 capture and transport indicates that there are considerable adverse environmental interventions of CCS, besides the benefit of reduced global warming potential. The study identifies the key areas to reduce the adverse impacts and it is found that technical developments to reduce energy penalty, and degradation of MEA in capture process are required to reduce the negative impacts. Efficient treating and monitoring of reclaimer wastes will control the toxic impact to the aquatic environment. Acknowledgements This study has been financed by PhD stipend from NTNU. We thank Karin Veltman for calculations on the direct emissions from the power plant, and Olav Bolland for his valuable comments. References Aarrestad, P.R., Gjershaug, J.O., 2009. Effects on terrestrial vegetation, soil and fauna of amines and possible degradation products relevant for CO2 capture. NILU, OR 3/2009. Audus, H., Freund, P., 1997. The costs and benefits of mitigation: a full-fuel-cycle examination of technologies for reducing greenhouse gas emissions. Energy Conversion and Management 38, 595–600.

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