Environmental assessment of IGCC power plants with

Journal of Cleaner Production 158 (2017) 233e244

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Journal of Cleaner Production journal homepage: www.elsevier.com/locate/jclepro

Environmental assessment of IGCC power plants with pre-combustion CO2 capture by chemical & calcium looping methods Letitia Petrescu*, Calin-Cristian Cormos Babes-Bolyai University, Faculty of Chemistry and Chemical Engineering, 11 Arany Janos, RO-400028, Cluj-Napoca, Romania

a r t i c l e i n f o

a b s t r a c t

Article history: Received 20 September 2016 Received in revised form 2 May 2017 Accepted 2 May 2017 Available online 10 May 2017

The environmental impact using Life Cycle Assessment (LCA) of coal-based IGCC power plants with carbon capture based on chemical & calcium looping is evaluated in the present work. The two IGCC carbon capture cases use calcium-based CO2 sorbents and iron-based oxygen carriers and they are compared, in term of technical performance (e.g. net power output, energy efficiency, carbon capture rate, CO2 emissions) and environmental performance, to the benchmark case without CO2 capture. The gasification-based power plants produce 440e610 MWe net power with a carbon capture rate higher than 90%. The system boundaries considered in the LCA are: (i) integrated gasification combined cycle with CO2 capture, (ii) raw materials extraction and transport and (iii) carbon dioxide compression, transport and storage. Several environmental impact categories were calculated and compared within the LCA framework. The most significant environmental indicators were: global warming potential (GWP), acidification potential (AP), eutrophication potential (EP) and abiotic depletion potential (ADP fossil). The best value for GWP, 338.73 kg CO2 equivalents/MWh, was obtained for iron-based chemical looping case. The best value for EP was obtained for the calcium-looping case (1461.97 kg PO3 4 equivalents/MWh). AP and ADPfossil has the lowest impact in the benchmark case (without CCS). © 2017 Elsevier Ltd. All rights reserved.

Keywords: IGCC power plants Carbon Capture and Storage (CCS) Life Cycle Assessment (LCA) Chemical looping Calcium looping

1. Introduction Coal, one of the world’s most abundant fossil fuel sources, currently meets about 23% of the total world primary energy demand, and 38% of global electricity generation (Hammond et al., 2011). More than half of the power generation in Europe is provided by the fossil fuels (Cormos and Cormos, 2014). Furthermore, all projections for the old continent show that fossil fuels will remain the main energy source for electricity generation, at least for a short to medium term (European Commission, 2011). The attractiveness of fossil fuels as a feedstock for power generation depends on the development of energy conversion systems that are efficient, clean and economical (Huang et al., 2008). In the climate change context, the coal-based technologies will have to reduce their environmental impact if coal is to remain a significant energy source (Moioli et al., 2014). Not only the environmental aspect but also the plant efficiency for clean and advanced coal technologies is an important parameter to be

* Corresponding author. E-mail address: [email protected] (L. Petrescu). http://dx.doi.org/10.1016/j.jclepro.2017.05.011 0959-6526/© 2017 Elsevier Ltd. All rights reserved.

considered (Liang et al., 2013). While improved coal technologies produced significant progress in terms of plants efficiency, accelerated technological effort is required to reduce greenhouse gas emissions and to improve the environmental performance (Bhutto and Karim, 2005). Among the coal fired options, IGCC systems have the best environmental performance and are possibly proper candidates for low carbon applications (Huang et al., 2008). In an IGCC power plant, the fuel gas (syngas) from gasification unit is cleaned of sulphur compounds and particulate matter, and is then burned in a gas turbine to generate electricity while in an IGCC plant with carbon capture, the syngas is decarbonised and the hydrogen-rich gas is used in a combined cycle for power generation. IGCC power plants have the potential to meet high energy efficiency and low emission targets for future power generation with CO2 capture (Moioli et al., 2014). In recent years, Carbon Capture and Storage (CCS) technologies have received much attention for their potential to achieve major CO2 reductions in a carbon constrained world (Damen et al., 2007), being a good compromise for decreasing the CO2 emissions while continuing the use of fossil fuels to satisfy increasing energy demand (Singh et al., 2011). CCS can be defined as the separation and capture of CO2 produced at stationary sources, its transportation

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L. Petrescu, C.-C. Cormos / Journal of Cleaner Production 158 (2017) 233e244

and storage in order to avoid the CO2 release into the atmosphere (Damen et al., 2006). Among different CCS technologies, chemical looping has emerged as one of the most promising and costefficient approaches. The Chemical Looping (CL) concept involves oxidation of a fuel via cyclic reduction and oxidation of a solid oxygen carrier (typically metal oxides) avoiding the direct contact between fuel and air. There are two evident benefits deriving from such a technology. The first benefit is that the products are not diluted with nitrogen from air and the second benefit is the elimination of a gas separan and Ramos, 2012). In the tion unit, which is very expensive (Ryde CL technology, after water condensation, almost pure CO2 is obtained (Schwebel et al., 2012). Two technologies, using calciumbased sorbent and iron-based oxygen carrier, have been evaluated in the present work. The usage of inexpensive materials and potential utilization of the spent solid in cement and steel industries are the main reasons for choosing the calcium sorbent and iron-based oxygen carrier (Petrescu et al., 2014). Another aspect which should be pointed up is that both calcium and iron chemical looping cycles are operating at high temperatures, which permit efficient high temperature heat recovery. This aspect has a positive effect on increasing the energy efficiency compared to gas-liquid capture processes (Cormos et al., 2014). As CCS technologies move from R&D to demo plants, the number of studies considering the environmental impacts of those technologies has raised significantly. An overview of the environmental performance across all aspects of the technology life cycle can provide a complete picture of the technology performance and can be obtained by using a life cycle approach. Regarding CCS technologies, one key question is whether CCS is good for the environment, or does the reduction in climate change-related damage outweigh the increase of the other environmental impact indicators. In order to answer the previous question for different impact categories a relevant tool is required. LCA is a widely recognized and used tool for evaluating the potential environmental impact of products, processes and services (Corsten et al., 2013). In a CCS framework, the boundaries of the system cover the whole CCS value chain, from coal mining to CO2 storage (Zhang et al., 2014). When applied to complex, emerging technologies, the results can vary significantly depending on the system boundaries and assumptions used (Sathre et al., 2012). According to Koornneef and co-authors, the overall environmental profile of a power plant changes when CCS is applied (Koornneef et al., 2013). Several studies concerning the life cycle analysis for various power plants in conjunction with CCS technologies can be found in the scientific literature. According to Zapp and co-authors, the intended reduction in GWP by introducing CO2 capture (up to - 85% hard coal oxyfuel, 95% lignite oxyfuel, 80% natural gas postcombustion) is combined with an increase of other environmental effects, regardless of capture technology, time horizon or fuel considered (Zapp et al., 2012). Some conclusions derived from another study, carried out by Corsten and co-authors in the field of environmental evaluation of the power plants, are i) CCS results in a net reduction of the GWP of power plants through their life cycle in the order of 65e84% (pulverised coal (PC)-CCS), 68e87% (IGCCCCS), 47e80% (NGCC-CCS), and 76e97% (oxy-fuel), ii) employing CCS in PC, IGCC and NGCC results in relative increases in eutrophication and acidification when comparing to power plants without CCS (Corsten et al., 2013). Cuellar-Franca and Azpagic performed a comprehensive comparison of environmental impacts of CCS and carbon capture and utilization (CCU) technologies. They have considered 27 studies found in the literature, 11 studies focus on CCS and 16 on CCU. The CCS studies suggest that the GWP from power plants can be reduced by 63e82%, with the greatest reductions achieved by oxy-fuel combustion in pulverised coal and

IGCC plants and the lowest by post-combustion capture in combined cycle gas turbine (CCGT) plants. However, other environmental impacts such as acidification and human toxicity are higher with than without CCS (Cuellar-Franca and Azapagic, 2015). A comparison between various CCS technologies (amine based, calcium looping and chilled ammonia) for medium and large scale power plant was conducted by Hanak and co-authors (Hanak et al., 2016). Process integration of advanced CCS technologies such as calcium-looping process with a natural gas combined cycle power plant for post-combustion CO2 capture was investigated by Hu and Ahn. Their study leads to the conclusion that compared to its application to coal combustion flue gas, calcium looping would incur augmented energy penalty when integrated with a natural gas combined cycle (NGCC) and exhaust gas recirculation would be crucial in decarbonising a NGCC power plant by Ca-looping (Hu and Ahn, 2017). As previously summarized, there are some LCA studies in the literature regarding the IGCC power plant coupled with various CCS technologies, but the comparison from environmental point of view between advanced pre-combustion technologies (such as calcium looping and chemical looping) was not performed up to this moment. The aim of this paper is to evaluate and compare the life cycle impacts of IGCC coupled to pre-combustion carbon capture by chemical & calcium looping methods.

2. Plant configurations, modeling assumptions & key performance indicators The three coal-based power plants investigated in the present paper are: Case 1: IGCC power plant without CCS (benchmark case); Case 2: IGCC power plant with calcium looping for precombustion CCS; Case 3: IGCC power plant with iron-based chemical looping for pre-combustion CCS. The assessed IGCC power plants with and without CCS are detailed below.

2.1. Description of case 1: IGCC power plant without CCS An air separation unit (ASU) is used to separates atmospheric air into its primary components. In the analysis presented in this paper it is assumed that the oxygen purity is 95% O2 (vol.) and the oxygen pressure at the ASU outlet is 2.4 bar. Coal is transported to the gasifier as a dense phase using nitrogen. Subsequently, the coal is mixed with oxygen and steam. From the different gasification technologies available on the market, an entrained-flow gasifier with dry fed and syngas quench (Shell type) was chosen. The main benefits offered by such a gasifier are: i) high energy efficiency; ii) high cold gas efficiency; iii) high carbon conversion as well as iv) clean syngas production (Cormos et al., 2008). The hydrogen sulphide contained in the syngas is removed by the Acid Gas Removal (AGR) unit leading to a desulphurised syngas, which furthermore, can be used in a gas turbine for electricity generation. Honeywell UOP Selexol® technology was considered for AGR. The captured H2S is sent to a Claus plant where the oxidation of hydrogen sulphide to elemental sulphur takes place. The exhaust heat from the gas turbine flue gases is recovered in the heat recovery steam generator (HRSG) to produce steam. The block flow diagram for Case 1 is presented in Fig. 1.


235

Fig. 1. Block diagram for Case 1: IGCC power plant without CCS.

2.2. Description of case 2: IGCC power plant with calcium looping cycle for pre-combustion CO2 capture The first part of this case is similar to the previous case, containing the same units e.g.: gasifier, syngas quench, AGR using Selexol®, Claus plant but beside these units, the IGCC with calciumbased chemical looping case has additional features. After sulphur removal, the syngas is sent to the calcium looping unit, more exactly to the sorbent enhanced water gas shift (SEWGS) reactor. Two important chemical reactions take place here: i) the carbon monoxide conversion to carbon dioxide and hydrogen according to water gas shift reaction: CO þ H2O 4 CO2 þ H2

DH ¼ 41 kJ/mol

(1)

and ii) the calcium carbonate formation from carbon dioxide and calcium oxide: CO2 þ CaO 4 CaCO3

DH ¼ 178.2 kJ/mol

(2)

In the calcination reactor the sorbent (CaO) is regenerated according to: CaCO3 4 CaO þ CO2

(3)

Additional coal is burned in an oxygen rich atmosphere (oxyfuel combustion), in order to provide the heat necessary to regenerate the sorbent. The oxy-fuel combustion provides a high purity CO2 stream at the exit of the calciner (>95% vol. CO2 according to the accepted captured CO2 quality specification (De Visser et al., 2008)). The sorbent is deactivated after a certain number of cycles and, consequently, it should be replaced. Fresh limestone make-up is introduced into the system. The make-up ratio considered in the present study is about 2e5% of total solid inventory (Cormos et al., 2014). The hydrogen-rich gas from the SEWGS reactor is sent to the gas turbine for power generation. The exhaust heat from the flue gases is recovered in the heat recovery steam generator (exhaust-heat boiler) to produce steam, which passes through a steam turbine to generate additional power. The block flow diagram for Case 2 is presented in Fig. 2. 2.3. Description of case 3: IGCC power plant with iron-based chemical looping cycle for pre-combustion CO2 capture The block diagram for Case 3 is presented in Fig. 3. As it can be

noticed, the first part of the power plant (ASU, gasifier, AGR unit using Selexol®, syngas quench and cooling, Claus plant and tail gas treatment) is identical with the previous two cases. After gasification, the syngas is sent to the AGR for desulphurization and, later on, to the fuel (syngas) reactor. The following reaction takes place in the fuel reactor: Fe2O3 þ CO þ 2H2 / 2Fe þ CO2 þ 2H2O

(4)

The reduced metal is re-oxidized to close the redox cycle. Air or steam can be used for oxidation. The application of steam is preferred in this case due to the co-production of hydrogen and power. The steam reactor operates at 500e700 C (Fan, 2010). The chemical reaction taking place in the steam reactor is: 3Fe þ 4H2O / Fe3O4 þ 4H2

(5)

Fe3O4 is oxidized to Fe2O3 in the air reactor according to following reaction: 4Fe3O4 þ O2 / 6Fe2O3

(6)

Reaction 6 takes places in the air reactor which operates at 950e1150 C. A small fraction of the solid flow (1%) is removed from the air reactor due to oxygen carrier deactivation, and fresh ilmenite make-up is introduced into the system. The CO2 obtained is dried and compressed (up to 120 bar) to make it ready for storage. The hydrogen-rich gas from the steam reactor is sent to the combined cycle gas turbine for power generation. The exhaust heat from the flue gases is recovered in the heat recovery steam generator to produce steam, which passes through a steam turbine to generate additional power. 2.4. Design assumptions, process simulation and key technical performance indicators Coal is used as fuel in all three cases under investigation. Coal composition and thermal properties, based on the proximate and ultimate analysis are presented in a previous study (Cormos and Cormos, 2014) and correspond to an international coal trade sort (Douglas Premium). Table 1 is a summary of the design assumptions for the cases under investigation. The above described processes were simulated using ChemCAD process simulator (ChemCAD, 2016). Two thermodynamic methods have been used in the present work: the Soave-Redlich-Kwong (SRK) method was selected for Case 1 and Predictive Soave-

236


Fig. 2. Block diagram for Case 2: IGCC power plant with calcium looping cycle.

Fig. 3. Block diagram for Case 3: IGCC power plant with iron-based chemical looping cycle.

Redlich-Kwong (PSRK) method was used for Case 2 and Case 3. SRK thermodynamic method fits for gas processing very well while PSRK method is easily extended to mixtures containing supercritical compounds. For Case 2 and 3, CO2 is transported at 120 bar and 35 C, parameters which corresponds to the supercritical CO2 region. Key technical performance indicators were calculated based on the mass and energy balance derived from simulation. The main key performance indicators, their definition as well as the correspondent calculation formula, have been previously defined by Cormos (2012). The key technical performance indicators are summarized in Table 2. As can be noticed, the chemical and calcium looping methods have an energy penalty for carbon capture of about 6.3e8.6 net electricity percentage points (the lowest energy penalty being for iron looping case). These energy penalties for CO2 capture are lower than for gas-liquid absorption technology which is in the range of 10 net electricity percentage points. The carbon capture rate is significantly higher for iron-based option (Case 3) than for calcium looping option (Case 2). 3. Life Cycle Assessment (LCA) LCA is a method that quantifies the environmental impacts ska et al., 2016). LCA associated with a product or service (Sliwi n applied to CCS technologies can provide a better understanding of the full environmental benefits and trade-offs of implementing CCS. Although LCA is a powerful tool, there are some limitations when using it for assessing CCS chains (Koornneef et al., 2013). The currently available literature aiming to address the life cycle environmental impacts of CCS focuses on different technologies, time frames and aspects treated (Corsten et al., 2013). Several LCA assessments have been performed, albeit for only a few capture technologies. Generally, there is a lack of information on toxic emissions and waste formation, and the results reported

are often associated with large uncertainties due to a lack of available measurements and due to methodological aspects (e.g. system boundaries, unit of comparison and impact assessment and methodologies). As a result, the environmental performances of power plants equipped with CCS published in the literature show a wide range in outcomes, which give mixed messages with regard to the environmental performance of CCS technologies (Koornneef et al., 2013). The aim of this study is to evaluate and compare the life cycles impact of coal-based IGCC power plants coupled to advanced CCS technologies based on calcium and chemical looping. A “cradle-tograve” approach was assumed (Environmental Protection Agency, 2006). The system boundaries include power generation coupled to calcium and iron-looping technologies, upstream processes as well as downstream processes. From the upstream processes the supply chain of the raw materials (e.g. coal, ilmenite, limestone) are considered, while from the downstream processes the carbon dioxide drying, compression, transport and storage phases are taken into account. The installation, commissioning and decommissioning of the power plant, chemical looping plant, coal mine and CO2 pipelines are also included in the study. The methodological framework ISO14044 was used for the present LCA study (ISO 14044, 2006). The ISO14044 framework includes four phases: Goal and Scope, Life Cycle Inventory (LCI) analysis, Life Cycle Impact Assessment (LCIA) and Interpretation (Korre et al., 2010). Those phases are detailed in the next section. 3.1. Goal and scope, system boundaries, limitations and LCA main assumptions The evaluation of the environmental indicators of power generation from IGCC plants with & without CCS represents the goal of the present study. A detailed calculation for each process phase (e.g.


237

Table 1 Design assumptions for Cases 1e3. Unit name

Assumptions

Air Separation Unit (ASU)

Oxygen purity (% vol.) ASU oxygen and nitrogen delivery pressure (bar) Power consumption (kWh/tonne O2) Integration with GT (gas turbine) Steam/coal ratio (kg/kg) Nitrogen/coal ratio (kg/kg) O2 pressure to gasifier (bar) Gasification pressure (bar) Gasification temperature (oC) Carbon conversion (%) Pressure drop (bar) Electric power for gasification aux (% of input fuel LHV) Cooling type Syngas temperature after quench ( C) CO conversion (%) Reactor thermal mode Pressure drop (bar) Number of shift reactors (fixed catalytic bed) Solvent Overall H2S removal yield (%) Delivery pressure (bar) Compressor efficiency (%) Solvent used for drying Oxygen-blown type Tail gas recycled to H2S absorption stage Steam/coal ratio (kg/kg) Carbonation Reactor Temperature ( C) Calcination Reactor Temperature ( C) O2 pressure to CL (bar) Oxygen-carrier removed (%) Steam pressure (bar) Fuel Reactor Temperature ( C) Air Reactor Temperature ( C) Steam Reactor temperature ( C) Oxygen-carrier removed (%) Type: Mitsubishi Hitachi Power Systems (MHPS) Net power output (MW) Electrical efficiency (%) Pressure ratio Turbine outlet temperature ( C) HP steam (bar) MP steam (bar) LP steam (bar) Condensation pressure (bar) Hydraulic efficiency of pumps (%) Steam turbine isentropic efficiency (%) Steam wetness ex. steam turbine (max. %) DT min. ( C) Pressure drop (% of inlet pressure)

Gasifier (Shell)

Syngas quench and conditioning

Acid Gas Removal (AGR) unit CO2 compression and drying

Claus plant and tail gas treatment Calcium-based looping unit (Case 2)

Iron-based looping unit (Case 3)

Gas turbine

Heat Recovery Steam Generator (HRSG)

Heat exchangers

raw materials extraction, electricity production, carbon dioxide processing, transport and storage) is investigated in order to achieve the proposed goal. The energy and material balances available from ChemCAD simulations, for each process phase, is the base of the environmental impact indicators. In the scope of the study some important aspects such as: function of the system, functional unit, system boundaries, main assumptions and limitations should be clearly defined. In the present study the proposed functional unit is one MWh of net energy (in form of power). In a comparative study, the functional unit should be the same for all the compared product systems. The boundaries of the system cover the following sub-systems: i) Coal supply chain (including extraction, transport and preparation) for Cases 1e3; ii) Limestone supply chain (including extraction, preparation and transport) for Case 2; iii) Ilmenite supply chain (including extraction, preparation and transport) for Case 3;

95.00 2.379 225 No 0.118 0.089 48 40 >1450 99.9% 1 0.5 syngas quench ~800 95.00 adiabatic 1 bar/bed 2 Selexol® >98 120 85 TEG yes yes 2.189 550e600 900e1000 31.7 1 34 800 1050 600 0.5 M701G2 334 39.5 21 588 120 34 3 0.041 85 85 10 10 2e3

iv) Power generation based on IGCC technology for Cases 1e3; v) CO2 capture using calcium-looping (Case 2) and iron-looping (Case 3) methods; vi) CO2 transport and storage for Cases 2e3 and vii) Constructions, commissioning/decommissioning of the coal mine, IGCC plant with/without CO2 capture, CO2 pipelines. Regarding the power plant location and associated raw material supply chains, Romania was considered taking into account the coal, iron ore and limestone reserves as well as potential CO2 geological storage sites and Enhanced Oil Recovery (EOR) possibilities. Fig. 4 presents the coal supply chain considered in all cases. In recent years, the mining industry has had to pay increasing amounts of attention to the environmental aspects of their activities, which is mainly an effect of growing requirements imposed by the European Union (Burchart-Korol et al., 2016). Underground mining was used for coal extraction. From a literature review it was found that the electricity requested for underground mining varies in the range of 12e124 kW/tone of coal. An average value for

238


Table 2 Results for key performance indicators for Cases 1e3. Main plant data

Units

Case 1

Case 2

Case 3

Coal flowrate Coal LHV (as received) Feedstock thermal energy (A)

t/h MJ/kg MWth

155.30 25.35 1093.70

236.82

162.33

1667.80

1143.21

Syngas thermal energy (B) Cold gas efficiency (B/A 100) Thermal energy of gas exit AGR (C) Syngas treatment efficiency (C/B 100)

MWth % MWth %

877.01 80.19 872.47 99.48

934.47 80.14 929.78 99.5

912.42 79.81 912.09 99.96

Gas turbine output Steam turbine output Expander power output Gross electric power output (D)

MWe MWe MWe MWe

334.00 235.89 0.72 570.61

334.00 429.11 1.43 764.54

334.00 201.33 0.29 535.62

ASU consumption þ O2 compression Gasification island power consumption CO2 capture, drying & compression Power island power Consumption Total ancillary power consumption (E)

MWe MWe MWe MWe MWe

41.96 7.91 6.49 21.11 77.47

70.02 9.69 56.5 20.52 156.72

43.84 8.55 16.88 23.28 92.55

Net electric power output (F ¼ D-E) Gross electrical efficiency (D/A 100) Net electrical efficiency (F/A 100) Carbon capture rate CO2 specific emissions

MWe % % % kg/MWh

493.13 52.17 45.09 0.00 766.74

607.82 45.84 36.44 91.56 58.87

443.07 46.85 38.76 99.45 3.01

Fig. 4. Coal supply chain (Cases 1e3).

Europe is 85 kW/tone of coal. A quantity of 0.79 MJ/tone of raw coal for electricity requirement and 0.17 m3/tone raw coal for water requirement were found for the operations following extraction (e.g. washing, transport). A quantity of 2 105 kW of electricity was found for the transportation of one kg of coal over a distance of one km (Spath et al., 1999). The distance from the coal mine to the coal preparation plant is about 250 km. It is estimated that 0.02% of the coal loaded is lost as dust (emissions), and an equal amount is lost when it is unloaded. It is estimated that 0.05e1% of the coal is lost during transit (0.075% in the present study). The schema presented in Fig. 5 was considered for the limestone supply chain. The amounts of electricity, natural gas, diesel, gasoline necessary to extract one tone of limestone, as well as the quantity of water used in the preparation step are taken from literature (Dolley, 2006). Regarding limestone transportation, it is assumed that the limestone used for CO2 capture is transported by truck over an average distance of 150 km. The supply chain for ilmenite is presented in Fig. 6.

The quantities of raw materials (e.g. water, electricity, diesel, explosives) used to extract and concentrate one tone of ilmenite are available in the specialized literature (Roth et al., 1999). The ilmenite is supposed to be transported by train after extraction and concentration. The transportation distance considered in this case was 200 km. The CO2 supply chain for Cases 2e3 is presented in Fig. 7. The carbon dioxide captured from the power plant having a pressure of 120 bar is transported, using pipelines, over a distance of 800 km. Conventional geological storage in off-shore reservoirs is considered in the present study. Data related to the transport (e.g. lost emissions through the pipeline and compressors, compression and injection powers) are taken from available literature sources (Koornneef et al., 2008). The following aspects have been considered regarding the construction: i) construction of the coal mine; ii) construction of the IGCC plant; iii) construction of the chemical looping; plant; and iv) construction of the CO2 pipelines. Due to the lack of data regarding the chemical looping plant construction (Case 2 and Case

Fig. 5. Limestone supply chain (Case 2).


239

Fig. 6. Ilmenite supply chain (Case 3).

Ozone Depletion Potential (ODP), Abiotic Depletion Potential (ADP), Freshwater Aquatic Ecotoxicity Potential (FATEP), Human Toxicity Potential (HTP), Photochemical Oxidation Potential (PCOP), Terrestrial Ecotoxicity Potential (TEP), Marine Aquatic Ecotoxicity Potential (MAETP). Definition and details about indicators calculae and co-authors (Guine e et al., 2001). tion are presented by Guine

Fig. 7. CO2 supply chain (Cases 2e3).

3) a percentage of 25% of the IGCC construction was considered for the CL plant. 3.2. Life Cycle Inventory (LCI) The LCI for each step was performed based on the material and energy balances derived from the process simulation and on the assumptions presented in Section 3.1. Emissions derived and resources used from extraction, production, distribution, use and disposal phases are included in the life-cycle inventory (LCI). For example, the LCI table containing the inputs and outputs for coal transportation for Case 2 is presented in Table 3. LCI for power generation (Case 2) is presented in Table 4. LCI for IGCC construction was taken from the literature (Skone and James, 2010). For Case 2 the LCI for the construction step is presented in Table 5. Table 6 represents the LCI for the coal mine construction (Cases 1e3). LCI for CO2 transport and storage for Case 2 is also reported (see Table 7). LCI for commissioning/decommissioning of IGCC power plants are taken from the literature (Spath et al., 1999) (see Table 8). The values for each fuel and the emissions released during commissioning were multiplied by 10% to account for decommissioning. The LCI for coal mine operation is reported in Table 9. 3.3. Impact assessment The CML 2001 method implemented in GaBi software version 6 (PE International, 2012) was used for the present LCA. The environmental indicators considered in CML 2001 method are categorized into the following indicators: Global Warming Potential (GWP), Acidification Potential (AP), Eutrophication Potential (EP),

4. Environmental impact results and discussions Eleven environmental impact categories were calculated and reported in Table 10. The GWP for Case 1 (the benchmark process without CCS) is more than double the GWP obtained in Case 2 and Case 3 (e.g. 917.25 kg CO2 equivalents/MWh vs. 373.09 kg CO2 equivalents/MWh for Case 2 and 338.73 kg CO2 equivalents/MWh for Case 3). The total GWP value for Case 1 is 917.25 kg CO2 equivalents/MWh. The contribution of various processes on the environmental impact indicators are reported in Table 11. From Table 11, it can be noticed that, from the total GWP value, 83.66% comes from the power plant operation, 16.09% comes from coal extraction and transportation, minor influence (e.g. less than 0.5% comes from power plant construction and coal mine construction. For Case 2: IGCC with calcium looping cycle for pre-combustion carbon capture, the GWP value is distributed as follows: 49.11% due from coal extraction and transportation, 18.44% due to CO2 transport and storage, 16.19% due to limestone extraction and transportation, 15.49% is due to the power plant operation and the remainder (less than 1%) is due to power plant construction (see Table 11). For Case 3: IGCC with iron-based chemical looping cycle for pre-combustion carbon capture, 50.84% comes from the coal extraction and transportation, 24.47% is due to ilmenite production (extraction, concentration and transportation), 21.52% is due to CO2 transport and storage, 2.31% comes from power plant operation and 0.67% is represented by the power plant and coal mine construction. It can be noticed that Case 3 has lower GWP value than Case 2 (about 10%). The GWP results are in line with the literature data. For instance, the calculated GWP values in this work are in line with the ones reported in the NETL analysis (Skone and James, 2010) (e.g. 917.25 vs. 937.81 kg CO2 equivalents/MWh for the case without CCS). For cases with CCS, the values reported in this work are slightly higher due to a more in depth evaluation (e.g. inclusion of sorbent/oxygen

Table 3 LCI for coal transportation for Case 2. Inputs

Value

Units

Outputs

Value

Coal to be transported Transportation type

390.11 rail

kg/MWh

Coal transported Coal losses - as dust - loading process - losses in transit

389.66

Electricity for coal transportation

Distance

0.00002 or 1185.58 250

kWh/1 kg of coal/1 km kWh for 237,116.36 kg over a distance of 250 km km

Units kg/MWh 2

1.27 10 7.8 102 0.29

kg/MWh kg/MWh kg/MWh

240


Table 4 LCI for power production (Case 2). Inputs

Value

Units

Outputs

Value

Units

Coal Selexol Limestone CaCO3 make-up Air TEG Oxygen to gasifier Nitrogen to gasifier Oxygen to CL Nitrogen to CL Argon to CL HP Steam to CL Boiler Feed Water Fresh Water Cold Water Electricity Oxygen to AGR

0.39 2.86 0.98 9.84 103 4.15 0.20 0.23 0.36 0.24 4.15 103 9.2 103 0.26 2.32 0.06 99.54 0.26 9.46 103

t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh MWh/MWh t/MWh

Electricity Selexol recycled CO2 to storage Recycled limestone Spent solids on landfill Silicon dioxide Ferric oxide Calcium oxide Calcium carbonate Aluminium oxide Sulphur TEG Slag Silicon Dioxide Ferric oxide Calcium oxide Aluminium oxide Vent Carbon dioxide Water Tryglicol Sulphur dioxide Stack Oxygen Nitrogen Carbon dioxide Carbon monoxide Water Hydrogen Argon Hydrogen sulfide Hydrogen chloride Condensate Boiler feed water Cold water Recycled water Steam to CL Process water

1.26 2.86 0.89 0.98 9.84 103 1.76 104 1.71 105 8.08 103 1.47 103 9.21 105 1.63 103 0.20 0.03 0.02 1.93 103 2.51 103 0.01 4.77 103 1.14 103 3.6 103 1.3 105 2.63 105 0.13 1.65 105 0.03 0.04 7.85 103 1.08 106 0.04 8.52 103 3.29 106 5.43 104 0.08 1.26 99.54 1.26 0.26 0.84

MWh/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh t/MWh

Table 5 LCI for IGCC power plant construction (Cases 1e3). Inputs

Value

Units

Outputs

Value

Concrete Aluminum sheet Steel pipe welded Steel plate Cast Iron Power grid Coal thermal energy

1.2459 5.19 103 2.17 102 1.578 101 2.94 103 6.69 103 1.705 103

kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh MJ/MWh MJ/MWh

Electricity Emissions to air Ammonia Carbon dioxide Carbon monoxide Dust Lead Mercury Methane Methane (biotic) Nitrogen oxides Nitrous oxide Sulphur dioxide Sulphur hexafluoride VOC (unspecified)

1.00

carrier production and transport). The value of the GWP indicator reported by Pehnt and Henkel in their work is around 900 kg CO2 equivalents/MWh (Pehnt and Henkel, 2009). Regarding AP, the best value is obtained in Case 1 (0.49 kg SO2 equivalents/MWh). The major influence on Case 1 is given by coal extraction and transportation process (about 89.85%). The remaining percentages are distributed as follows: 8.52% from the total AP comes from the power plant operation, 1.42% comes from power plant construction and 0.21% is due to the coal mine construction. For Case 2, the total value of AP is 1.47 kg SO2 equivalents/

1.55 7.71 2.97 8.32 5.29 3.31 5.83 9.13 1.61 1.76 2.76 9.06 6.08

Units MWh

6

10 101 103 104 107 108 104 106 103 105 103 1012 105

kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh

MWh. The main contributions of various steps to the AP value is as follows: 39.06% is due to the CO2 transport and storage step, 34.76% corresponds to the coal extraction and transportation, 20.52% to the limestone extraction and transportation processes and 2.37% comes from the power production process and small influence are attributed to the power plant construction and coal mine construction (less than 0.5%). The highest value for AP indicator is obtained in Case 3 (e.g. 1.75 kg SO2 equivalents/MWh). 34.80% from this value is represented by CO2 transport and storage step, 34.57% is due to ilmenite extraction & transportation, 29.59% is due to coal


241

Table 6 LCI for coal mine construction (Cases 1e3). Inputs

Value

Rolled steel Galvanized steel Rubber Steel plate Concrete Rebar Poly-vinyl-chloride Stainless steel 316 Stainless steel 431 Cast iron Copper mix Asphalt

1.4704807 1.5194872 4.4476729 1.8025590 6.0562609 1.4088365 1.2992707 6.7669300 6.7669300 3.3834650 8.1127506 1.1053860

Units

105 106 107 104 105 106 107 108 108 107 109 103

kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg

coal coal coal coal coal coal coal coal coal coal coal coal

Outputs

Value

Units

Coal Emissions to air Ammonia Carbon dioxide Carbon monoxide Dust Lead Mercury Methane Methane (biotic) Nitrogen oxides Nitrous oxide Sulphur dioxide Sulphur hexafluoride VOC (unspecified)

1.00

kg/kg coal

7.36 2.79 2.10 9.52 4.77 2.70 3.94 3.82 5.22 1.17 6.92 1.34 3.25

1010 104 106 108 1010 1011 1010 1010 107 108 107 1013 108

kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg

coal coal coal coal coal coal coal coal coal coal coal coal coal

Table 7 LCI for CO2 transport and storage (Case 2). Inputs

Value

Units

Outputs

Value

Units

CO2 from power plant Electricity for compressors

888.69 400 or 0.1111 7 or 25.2 120 0.06 800 100 8 2

kg/MWh MJ/t CO2 MWh/t CO2

CO2 stored CO2 losses pipeline

887.09 0.407

kg/MWh kg CO2/MWh (calculated from 2.32 t CO2/km/year over a distance of 800 km)

kWh/t CO2 MJ/t CO2

CO2 losses compressors

0.305

kg CO2/MWh (calculated from 23.2CO2/MW/year considering a period of 7500 h for operation)

bar bar/km km km

CO2 losses injection

0.888

kg CO2/MWh

Electricity for injection

Injection pressure Pressure drop Pipeline distance Distance between compression stations No of compressor (booster) stations Storage depth

km

extraction and transportation and coal mine operation and the rest is coming from power plant operation (about 0.4%), power plant construction (about 0.4%) (see Table 11). Comparing Case 3 and Case 1 in terms of AP, the value is about three and half times higher, due to the introduction of a CO2 transport and storage and the ilmenite production, steps that are not present in the benchmark case. The EP environmental impact category has the highest value in Case 3. The entire impact is due to the power plant process (valid for all cases). Other impact categories, such as ODP and ADPelements, have low values in all three cases. The major influence on the ODP impact indicator, more than 50%, is given by the CO2 transport and storage

step (e.g. 58.03% in Case 2 and 50.36% in Case 3) Raw-material extraction and transportation (e.g. coal, limestone, ilmenite) (see Table 11) bring also significant contribution to the total ODP. The construction of the power plant represents almost half of the total ODP value for Case 1. Lower impacts have been registered for power plant construction for the CCS cases (e.g. 7.55% for Case 2 and 6.19% for Case 3). The influence of the power plant operation represents less than 2% of the total ODP value. For the ADPelements impact indicator the lowest value is obtained in the case without CCS (e.g. 6.31 106 kg Sb equivalents/MWh vs. 3.02 105 kg Sb equivalents/MWh in Case 2, respectively 5.93 105 kg Sb equivalents/MWh in Case 3). As it can be noticed from Table 11, coal extraction and transportation process is an

Table 8 LCI for commissioning/decommissioning of the IGCC power plant (Cases 1e3). Inputs

Value

Units

Outputs

Value

Units

Diesel

5.1796 102

kg/MWh

Emissions to air Ammonia Carbon dioxide Carbon monoxide Dust Lead Mercury Methane Methane (biotic) Nitrogen oxides Nitrous oxide Sulphur dioxide Sulphur hexafluoride VOC (unspecified)

1.81 106 4.87 102 2.02 103 3.35 107 2.56 1010 2.38 1011 6.13 105 0 7.41 104 1.21 106 4.1 105 2.16 1014 1.92 104

kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh kg/MWh

242


Table 9 LCI for coal mine operation (Cases 1e3). Inputs

Value

Units

Outputs

Value

Units

Diesel Power grid

2.6245 104 3.3069 102

kg/kg coal MJ/kg coal

Emissions to air Ammonia Carbon dioxide Carbon monoxide Dust Lead Mercury Methane Methane (biotic) Nitrogen oxides Nitrous oxide Sulphur dioxide Sulphur hexafluoride VOC (unspecified)

6.6 108 7.45 103 7.29 106 7.07 107 3.29 1010 9.18 1011 7.57 103 0 1.35 105 1.09 107 3.74 105 4.48 1014 2.39 107

kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg kg/kg

important contributor to the total ADPelements especially for Case 1, where coal extraction and transportation represents 65.18% of the total indicator value. Limestone extraction and transportation process, for Case 2, contribute with 50.78% to the total ADPelements, while ilmenite extraction and transportation contributes with 74.29%. Significant influence on the total ADPelements is due also to the carbon dioxide transport and storage (see Table 11). ADPfossil impact indicator has higher values for the cases with CCS (e.g. 1.36 104 MJ/MWh in Case 2 and 1.25 104 MJ/MWh in Case 3) where higher quantities of coal are used (see Table 2). Almost all of this value, more exactly 99.73%, is due to the coal extraction and transportation process in Case 1 The same process represents 83.97% in Case 2 and 85.56% in Case 3 of the total ADPfossil. For the CCS cases, the extraction of the other rawmaterials represents 10.38% for Case 2, respectively 7.83% for Case 3. The carbon dioxide transport and storage step contributes about 5.44% in Case 2, respectively 6.24% for Case 3. As it can be noticed from Table 10, the lowest value for this impact indicator is obtained in the case without CCS, Case 1, (e.g. 9.21 103 MJ/MWh). A lower quantity of coal is used in this case, leading to a lower impact of the ADPfossil. PCOP impact category has almost the same value for Case 2 and Case 3 (e.g. 0.11 kg ethylene equivalents/MWh and 0.14 kg ethylene equivalents/MWh), these values are two times higher than the base case (e.g. 0.05 kg ethylene equivalents/MWh) (see Table 10). The highest values for this impact indicator in the CCS cases are due to the coal extraction and transportation (e.g. 98.27% in Case 1, 63.06% in Case 2 and 48.15% in Case 3). The percentage of the limestone extraction and transportation process from the total PCOP, for Case 2, is about 9.91% while the percentage of the ilmenite extraction and transportation process from the total PCOP, for Case 3, is about 28.15%. CO2 transport and storage operation represents 25.23% in Case 2 and 21.48% in Case 3. Minor influence on this impact

coal coal coal coal coal coal coal coal coal coal coal coal coal

indicator, less than 3%, is due to the power plant operation and power plant construction (see Table 11). The best values of the four impact indicators linked to the lethal concentration LC50, FAETP, HTP, TEP, MAETP is obtained in Case 1. Table 10 shows a higher human toxicity for the cases where CO2 is captured compared to the benchmark. The distribution of various processes on the FAETP, HTP, TEP, MAETP indicators, for all three cases under study is also presented in Table 11. The major contributors on these indicators are: coal, limestone, ilmenite extraction and transportation and CO2 transport and storage processes. 5. Conclusions This paper investigates two coal-based IGCC power plants with chemical & calcium looping methods used for CO2 capture. The two coal-based IGCC power plants with CCS were evaluated and compared to conventional IGCC without CCS in terms of technical and environmental performances. The evaluated plant concepts generate 440e610 MWe net power. The carbon capture rate was almost 100% (99.45%) in Case 3 (IGCC with iron-based chemical looping cycle), whereas a capture rate of 91.56% was calculated for Case 2 (IGCC power plant with calcium looping cycle). The main focus of the work was concentrated on the environmental evaluation of the three cases, evaluation performed using the LCA methodology. A “cradle-to-grave” approach considering the following system boundary: 1) power production from coal using CL-based CO2 capture technologies; 2) upstream processes such as the extraction, processing and transport of coal, limestone and ilmenite and 3) downstream processes such as CO2 compression, transport and storage, was used in the study. The installation, commissioning and decommissioning of the power plant, chemical looping plant, coal mine and CO2 pipelines were also included in the study. Eleven environmental impact categories were defined,

Table 10 LCA results (Cases 1e3) according to CML 2001. KPI

Units

Case 1

Case 2

Case 3

GWP AP EP ODP ADP elements ADP fossil FAETP HTP PCOP TEP MAETP

kg CO2 equivalents/MWh kg SO2 equivalents/MWh kg PO3 4 equivalents/MWh kg R11 equivalents/MWh kg Sb equivalents/MWh MJ/MWh kg 1,4 DCB equivalents/MWh kg 1,4 DCB equivalents/MWh kg ethylene equivalents/MWh kg 1,4 DCB equivalents/MWh kg 1,4 DCB equivalents/MWh

917.25 0.49 1898.12 3.98 109 6.31 106 9.21 103 0.26 3.25 0.05 0.06 6.40 103

373.09 1.47 1461.97 3.11 108 3.02 105 1.36 104 0.75 12.40 0.11 0.29 1.99 104

338.73 1.75 1949.12 3.79 108 5.93 105 1.25 104 0.64 13.72 0.14 0.91 2.55 104

Case 3

CET-coal extraction and transportation, LET-limestone extraction and transportation, IET-ilmenite extraction and transportation, PPO-power plant operation, CTS- CO2 transport and storage, PPC-power plant construction, CMCcoal mine construction, OP-other process.

0.16 2.6 e 0.01 0.1 0.13 0.53 1.05 e e 0.02

Case 2 Case 1

0.01 e e 0.06 0.52 0.05 0.75 1.32 e 1.55 0.51

Case 3

0.09 0.06 e 1.69 0.24 e e 0.12 e e 0.12

Case 2

0.08 0.07 e 2.18 0.5 e e 0.14 e e 0.17

Case 1

0.03 0.21 e 13.77 1.87 e e e e 1.57 e

Case 3

0.58 0.40 e 6.19 2.94 e 0.31 3.44 0.75 0.26 1.08 0.53 0.62 e 7.55 7.23 e 0.27 3.05 0.9 1.72 1.38

Case 2 Case 1

0.21 1.42 e 47.21 27.62 0.11 0.77 11.63 1.73 6.25 3.43 21.52 34.80 e 50.36 12.42 6.24 15.46 33.96 21.48 8.87 27.06

Case 3 Case 2

18.44 39.06 e 58.03 23.08 5.44 12.57 35.53 25.23 26.21 32.88 2.31 0.40 100 0.82 1.18 0.14 2.03 0.68 0.74 2.63 1.69

Case 3 Case 2

15.49 2.37 100 0.48 1.36 0.08 0.94 0.64 0.90 5.86 1.28 83.66 8.52 100 1.38 4.81 0.11 1.92 2.34 e 26.56 2.92

Case 1 Case 3 Case 2

16.19 20.52 e 25.78 50.78 10.38 43.85 32.00 9.91 48.28 26.95 50.84 29.59 e 4.58 8.09 85.65 46.11 23.45 48.15 5.37 27.30 GWP AP EP ODP ADPelements ADPfossil FAETP HTP PCOP TEP MAETP

Case 3 Case 2

49.11 34.76 e 5.97 16.95 83.97 41.84 27.59 63.06 17.93 37.32

Case 1

16.09 89.85 e 37.58 65.18 99.73 96.56 84.71 98.27 64.07 93.14

24.47 34.57 e 36.33 74.29 7.83 35.47 38.08 28.15 82.58 42.74

OP CMC PPC CTS PPO IET LET CET

Contribution of various processes on the environmental impact indicators (%)

Table 11 Contributors of various processes on different environmental impact indicators.

0.19 0.18 e 0.85 0.84 0.14 0.62 0.27 0.73 0.29 0.13


243

calculated and compared among various evaluated IGCC power plant concepts with and without carbon capture. Discussions about all indicators are reported in the paper. The most significant environmental impact categories are the GWP, AP, EP and ADPfossil. As the results show the hydrogen-based power generation has significant environmental benefits in term of reducing GHG emissions but other environmental indicators (e.g. acidification potential, photochemical oxidation potential and the indicators related to the lethal dose) show some important increase. The increase is due to the introduction of some additional up-stream processes (e.g. limestone and ilmenite production and transportation) as well as on the downstream processes, (e.g. CO2 transport and storage step), steps that are not present in the benchmark case. Acknowledgements This work was supported by the Romanian National Authority for Scientific Research, CNCS e UEFISCDI, project no. PN-II-IDPCE-2011-3-0028: “Innovative methods for chemical looping carbon dioxide capture applied to energy conversion processes for decarbonised energy vectors poly-generation”. Nomenclature ADP AGR AP ASU CL CCS CMC CTS CET EP FAETP GWP HRSG HTP IGCC IET LCA LET LCI MAETP NGCC ODP OP PC PCOP PPC PPO PSRK R&D SRK SEWGS TEG TETP

Abiotic Depletion Potential Acid Gas Removal Acidification Potential Air Separation Unit Chemical Looping Carbon Capture and Storage coal mine construction CO2 transport and storage coal extraction and transportation Eutrophication Potential Freshwater Aquatic Ecotoxicity Potential Global Warming Potential Heat Recovery Steam Generator Human Toxicity Potential Integrated Gasification Combined Cycle ilmenite extraction and transportation Life Cycle Analysis limestone extraction and transportation Life Cycle Inventory Marine Aquatic Ecotoxicity Potential Natural Gas Combined Cycle Ozone Layer Depletion Potential other processes Pulverised Coal Photochemical Ozone Creation Potential power plant construction power plant operation Predictive Soave-Redlich-Kwong Research and Development Soave Redlich Kwong Sorbent Enhanced Water Gas Shift Tri-ethylene-glycol Terrestrial Ecotoxicity Potential

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