Evaluation of fossil fuel power plants with CO 2 recovery

Transcription

1 Evaluation of fossil fuel power plants with CO 2 recovery ADRIAN BADEA, CRISTIAN DINCA, TIBERIU APOSTOL Power Plant Department University POLITEHNICA of Bucharest Splaiul Independetei, 313, Bucharest ROMANIA crisflor75@yahoo.com Abstract: - Fossil fuels supply over 90 % of the energy used by the industrialized nations of Europe to generate electricity, power and heat. At the same time, the production and transmission of these fuels significantly contributes to the greenhouse gas emissions of the exporting and importing nations. It is the contribution made by natural gas to these emissions, in particular the climatic relevance of the natural gas exported by Russia compared with other fossil fuels. In this paper the authors have compared the technology using the natural gas and coal in order to produce the electricity. Key-Words: - GHG, CO 2, MEA, combustion, natural gas, coal 1 Introduction The role of coal and natural gas in the European energy market is increasing. They have the largest share of utility power generation in the UE, accounting for approximately 55 % of all utilityproduced electricity. Therefore, understanding the environmental implications of producing electricity from this fuel is an important component of any plan to reduce total emissions and resource consumption. A life cycle assessment (LCA) on the production of electricity from coal and natural gas was performed in order to examine the environmental aspects of pulverized coal boiler systems with sub-critical and super-critical parameters, integrated gasification combined cycle and natural gas combined-cycle (NGCC). The current paper examines life cycle emissions from three types of fossil-fuel-based power plants, namely supercritical pulverized coal (super-pc), natural gas combined cycle (NGCC) and integrated gasification combined cycle (IGCC). The PC power plants studies (both sub-pc and super-pc) are equipped with NOx, particulates and SO 2 removal processes (i.e. selective catalytic reduction, SCR, electrostatic precipitation, ESP and flue gas desulfurization, FGD). The NGCC power plant on the other hand, is equipped with NOx control. Studies of CO 2 capture and storage (CCS) costs necessarily employ a host of technical and economic assumptions regarding the particular technology or system of interest, including details regarding the capture technology design, the power plant or gas stream treated, and the methods of CO 2 transport and storage. Because the specific assumptions employed can dramatically affect the results of an analysis, published studies are often of limited value to researchers, analysts and industry personnel seeking results for alternative assumptions or plant characteristics. In the present paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and costs of PC, IGCC and NGCC power plants on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed. In particular, the effects on cost comparisons of higher natural gas prices and differential plant utilization rates are highlighted, along with implications of financing and operating assumptions for IGCC plants 2 The life cycle assessment Generally, a life cycle study consists of four steps: goal and scope definition, inventory analysis, impact assessment and improvement assessment [1]. In the first two steps, boundaries of the analysis are defined and impacts of the different processes of the system are calculated. The third and fourth steps examine the actual environmental and human health effects from the use of resources (energy and materials) and environmental releases and give recommendations for reducing these effects. The current study focuses on the first two steps. 2.1 The boundaries of the systems The boundaries for the current analysis are shown in Figs. 1 3 for PC, NGCC and IGCC technologies without CCS. ISSN: ISBN:

2 Figs. 1 3 consists of energy and/or materials as inputs and emissions as output. In addition to accounting for direct emissions from fuel combustion in the power plant, other emissions arising from upstream (e.g. production and transport of limestone, ammonia, catalyst, etc.) and downstream (e.g. waste transport and disposal) processes, as well as emissions from power plant construction and decommissioning, are also included. Extracting the materials used for constructing the power plant is also accounted for. For downstream processes, waste transport and disposal in a near-by landfill are considered. In PC coal power plants, for example, waste is generated by the boiler and ESP process as bottom ash and by the FGD process as gypsum and calcium chloride [2]. Fig. 1. Life cycle boundaries for PC power plant Fig. 2. Life cycle boundaries for NGCC power plant Fig. 3. Life cycle boundaries for IGCC power plant ISSN: ISBN:

3 For coal-based power plants, emissions arising from mining activities such as methane leakage and machinery operation are included. For natural gas fuel cycle systems, on the other hand, upstream emissions include those from gas exploration, extraction, processing and compression as well as from methane leakage during extraction and transport. Emissions from pipeline construction (and associated steel requirements for constructing the pipeline) are also accounted for. Extracting the materials used for constructing the power plant, the capture plant and the CO 2 transport pipeline are also accounted for. For downstream processes, waste transport and disposal in a near-by landfill are considered. In PC coal power plants, for example, waste is generated by the boiler and ESP process as bottom ash and by the FGD process as gypsum and calcium chloride [3]. For CCS systems where the capture process is MEA-based, waste is generated in the re-claimer where NaOH is used to reclaim MEA from salts resulting from MEA oxidation. For coal-based power plants, emissions arising from mining activities such as methane leakage and machinery operation are included. For natural gas fuel cycle systems, on the other hand, upstream emissions include those from gas exploration, extraction, processing and compression as well as from methane leakage during extraction and transport. Emissions from pipeline construction (and associated steel requirements for constructing the pipeline) are also accounted for. 2.2 Life cycle data and methods of GHG analysis Two methods for life cycle GHG assessment of power plants can be employed as shown in Fig. 4. A power plant techno-economic model is used to estimate material and energy requirements and costs. The input parameters for the model are discussed in Section 4. Data of GHG content (kgco 2 /kg material produced) and energy content (MJ/kg material produced) are obtained as described by [5] from process chain analysis (PCA), while data of GHG intensity (kgco 2 / material produced) and energy intensity (MJ/ material produced) are obtained from an input/output analysis (IOA). Process chain analysis is usually based on data obtained from previous studies, from stakeholders or from available software packages. The EcoInvent database of the software SimaPro (by Pre Consultants), which contains data applicable for Western Europe in general, has been used in the current study. Input/output (I/O) analysis is based on data obtained from European Commission study - I/O tables. In order to obtain annual emissions from operation, the results from PCA and IOA are multiplied by the material requirements and costs obtained from the techno-economic model as shown in Fig. 4. Annual emissions are multiplied by the power plant lifetime to obtain total emissions from operation. The procedure is repeated for all GHG gases within a given process and then for all processes within a life cycle system. For emissions from construction, the material requirements (for example kg of steel or concrete) or the total costs of construction ( ) are multiplied by GHG content or GHG intensity as applicable. For emissions from transportation, quantities of transport fuel (e.g. m 3 or kg heavy oil) or costs of transport ( ) are multiplied by available factors in units of kg CO 2 -e/m 3 heavy oil or /m3 heavy oil. Alternatively, factors in the form of kg CO 2 -e/ton.km or kg CO 2 -e/ worth of transport (which can be obtained from I/O tables for different means of transport) can be multiplied by transport distances and amount of material transported. Total emissions from construction and decommissioning are added to total emissions from operation (production, transport and waste disposal) and the sum is divided by the power plant output over its lifetime. Normalized values of total GWP from the two methods showed that the cost-based IOA provides a more complete accounting of emissions incurred during construction thus resulting in larger estimates of emissions. The authors stated that for plant construction, the material-based PCA resulted in emissions that approximate a subset of emissions computed via the cost-based IOA method. For plant operation, however, only emissions due to mining and consumption of coal at the plant are significant, and both methods of analysis give essentially equivalent results. ISSN: ISBN:

4 Process (e.g. steel, limestone production, etc.) Literature data, stakeholder, software databases, etc. Power Plant Techno economic Model I/O tables Process Chain Analysis Input/Output Analysis GHG Content (kg CO 2 e/kg material manufactured) Material Requirements (kg/year) Cost ( /year) GHG Intensity (kg CO 2 -e/ worth of material manufactured) Multiply to obtain annual emissions in kg CO 2 e /year Power plant lifetime Multiply to obtain annual emissions in kg CO 2 e /year Total emissions for process over lifetime of power plant Next process Add from all process Total emissions for all process over lifetime of power plant Power plant Techno economic Model Electrical output (kwh) over lifetime of power plant 2.3 Energy considerations Life cycle efficiency, which has the same definition as the net energy ratio (NER) shown in Table 1, is the energy output throughout the lifetime of the power plant divided by all sources of energy input from the life cycle of the system over the same period of time. The energy input includes energy contained in the fuel in addition to embodied energy added to the power plant (for example the energy used for construction of the power plant, the energy used to produce limestone and transport it to the power plant, etc.). The percentage reduction of life cycle efficiency from actual power plant efficiency Power plant emissions factor (kg/kwh) Fig. 4. Life cycle analysis by two methods: process chain analysis and I/O analysis. (i.e. the efficiency calculated by dividing the electrical output of the power plant by the energy content of the fuel over the life time of the power plant) is an indication of how significant energy use in upstream, downstream and construction processes is. 3. Life cycle assessment assumption For the coal life cycle, it is assumed that coal and other necessary materials (including limestone and ammonia) are produced locally in the Romania and according to local technologies. A transport distance of 100 km was assumed for transport of coal as well ISSN: ISBN:

5 as other materials. The assumption that all coal used by a Romanian power plant is locally mined may not be realistic. A pipeline length of 250 km was assumed between the power plant and the gas field. A diameter of 80 cm, which is typical for natural gas transport, is assumed. Emissions for producing the steel required to construct the pipeline were taken into account. The effect of importing all or a some part of natural gas required by the power station from Russia is investigated in Section 5.3 as part of a sensitivity analysis. However, due to lack of data, emissions from digging and laying the pipeline were ignored. A 1% methane leakage is assumed for the reference case. However, a sensitivity analysis is undertaken in Section 5.3 to investigate the effect of natural gas loss on total GHG emissions. The current analysis assumes that natural gas is transported from the extraction platform where it is sweetened and flared. Onshore processing includes gas compression and delivery to the power plant. In general, the LCA of CCS systems accounts for emissions arising from the construction of the capture plant and CO 2 pipeline, those arising from the production and transport of chemicals necessary for running the capture plant, as well as those arising from the energy requirements for the transport and injection processes. It is assumed that the captured CO 2 is compressed to 13.5 Mpa and transported via a 300-km pipeline where it is injected in gas fields [6]. In addition, the current analysis considers electricity requirements for CO 2 re-compression along the pipeline. An energy requirement of 3 kw of electricity per km of CO 2 pipeline was used based on a calculation from [7]. Due to lack of data, CO 2 leakage from the pipeline and emissions and energy requirements for the injection of CO 2 were roughly estimated based on experience in the natural gas and oil industries. Furthermore, it was assumed that leakage from the reservoir over the lifetime of the power plant is negligible. 4. Description of technologies considered The following technologies are considered for analysis: A reference case (reference), which comprises a non-ccs subcritical PC power plant equipped with pollution control processes including SCR for NOx removal, ESP for particulates removal and FGD for SO 2 removal. The current study compares LCEs and efficiencies from each of the following technologies to this sub-pc reference plant. Two supercritical PC technologies without (Case1a) and with (Case1b) CCS. Both cases are equipped with SCR, ESP and FGD. A third case (Case1c), which consists of a supercritical PC power plant with CCS but without FGD is considered for life cycle assessment. The reason for including this case is to quantify the effect of including or excluding the FGD process on life cycle GHG emissions from the CCS system. While the effect of excluding FGD on the costs of CO 2 capture has been previously reported [5], the effect on LCEs has not been quantified before. The current analysis investigates the effect of removing FGD on LCEs. Two NGCC technologies without (Case2a) and with (Case2b) CCS. Two IGCC technologies without (Case3a) and with (Case3b) CCS. The capture technology considered for PC and NGCC is post-combustion MEA-based absorption. For IGCC, on the other hand, a pre-combustion physical absorption with Selexol solvent is considered. The power generation capacity for all non-ccs cases was kept constant at 500 MW with a 75% load factor. A power plant lifetime of 30 years was considered. For CCS plants, a capture efficiency of 90 % is considered. Other process-specific parameters are based on typical values from the literature. These output parameters are then entered into an Excel spreadsheet (Fig. 6) where they are used in combination with a built-in database of GHG content and GHG intensity data as shown in Fig. 4 under the box I/O analysis to estimate production and transport emissions and, consequently, the GWP (emissions in mass CO 2 -e per kwh of electricity produced) can be determined. The life cycle efficiency defined in Section 2.3 can be calculated by repeating the calculation procedure shown in Fig. 4 with energy content and energy intensity data instead of GHG data. The steam used for regenerating MEA is taken from the main power plant and so no auxiliary natural gas power plant was considered. The calculated emissions per kwh were based on the net power produced from the plant and so the plant with CCS used the same amount of fuel as in the case without CCS. ISSN: ISBN:

6 Table 1. Excel calculation sheet for life cycle GHG emissions from a supercritical PC power plant with CCS Super PC with CCS Output Parameter Life Cycle GHG Emissions Amounts, ton/year Total, g/kwh 255 Amount of coal % g/kwh Ammonia for SCR Direct 43,8 112 Limestone Construction/Decommissioning 1,3 3,4 Waste-Ash Other Operation 54,9 139,9 Waste-FGD *Upstream Waste-MEA re-claimer -Coal Production 50 65,6 SCR catalyst waste -Coal transport 1,4 1,8 Direct CO2 emissions, kg/year Other material production 48,7 63,9 Costs *Downstream 3,4 8,6 Materials, /year Coal cost Net Power, MW Water Power Plant efficiency, % 30 SCR catalyst Life cycle efficiency, % 27,7 MEA/Selexol NaOH Activated Carbon Construction, M Power plant Capture plant Pipeline Results and discussion 5.1 Power plant performance results The net power and corresponding efficiency for each of the technologies is shown in Table 2. For the reference power plant, a 25MW reduction (475 instead of 500MW) is caused by the air blower, coal pulverizes and the steam cycle pumps and cooling system. For the super-critical PC system, additional energy penalties are caused by the SCR (3 MW), ESP (1MW) and FGD (18MW) processes. The addition of CCS to super-pc imposes an energy penalty of 118MW (26%). Corresponding energy penalties for NGCC and IGCC due to CCS are 15% and 7%, respectively. Table 2 reveals that for NGCC systems, life cycle efficiency is much lower than power plant efficiency. This reflects the fact that upstream processes in the natural gas cycle are more energy intensive in comparison to upstream emissions from the coal fuel cycle. Fuel and other material consumption for each of the technologies are shown in Table 3. For all power plants, the inclusion of CCS increases fuel consumption by 15 30% on a g/kwh of electricity-produced basis. The large increase in fuel consumption for PC is an indication of the high energy penalties associated with CCS when used with PC. The increase in limestone consumption shown in Table 3 for PC power plants with CCS is due to the fact that the model increases the SO x removal efficiency from 90% to 98% when CCS is considered [6]. This is necessary in order to avoid significant MEA losses due to the strong reaction of MEA solvent with SO 2. MEA is very reactive with acid gases (SO 2, SO 3, NO 2 and HCl in addition to CO 2 ). As a result, it is seen from Table 3 that MEA consumption is higher for PC than for NGCC because more acid gases are associated with the coal technology. ISSN: ISBN:

7 Table 2. Net power and power plant thermal efficiency Case Net power, Power plant efficiency, LCA efficiency % Reduction in efficiency MW % % Reference ,3 32,9 6,8 1a ,6 36,3 8,3 1b ,7 7,7 2a , ,2 2b ,8 36,5 14,7 3a ,2 35 5,9 3b ,2 5,6 Table 3. Resource consumption Case Fuel a,b Limestone b b NH 3 MEA b Selexol b Reference 329,7 19 0, a 294,9 16,9 0, b 390,1 27,2 0,8 3,6-2a 130,1-0, b 151,9-0,23 1,33-3a 314, ,02 3b 365, ,03 a Fuel consumption as coal for cases 1a, 1b, 3a, 3b and natural gas for cases 2a and 2b b All values in these columns are in units of g/kwh 5.2. Life cycle GHG emissions LCEs for each of the non-ccs and CCS technologies are compared in Table 4. All systems with CCS show a large reduction in life cycle GHG emissions. The highest reductions from the reference case are obtained with IGCC followed by NGCC. The contribution of different sections of the life cycle to GHG emissions is shown in Fig. 5. It is evident that emissions from the construction phase are negligible both for CCS and non-ccs systems when compared with other LCEs. LCEs from supercritical PC power plants without CCS are 10,6 % less than LCEs from the reference subcritical case. This difference is a reflection of the higher efficiency and consequent lower fuel consumption by the supercritical power plant. For IGCC without CCS, LCEs are only 2% lower than LCEs from supercritical PC. Moreover, LCEs from NGCC without CCS are, as expected, 50% less than emissions from the reference case. For NGCC, upstream GHG emissions from gas extraction and transport constitute 26% of all LCEs emissions. For the coal life cycle on the other hand, upstream emissions constitute 6 10% of all GHG emissions (depending on whether the technology is PC or IGCC) For the super-critical PC power plant with CCS, LCEs are 74% less than emissions from the reference case. Emissions attributed to CCS (capture, transport, injection and construction of power plant and CO 2 pipeline) account for 10% of all LCEs. For Case2b (NGCC with CCS), LCEs are 79% lower than the reference case and only 22 % lower than the supercritical PC with CCS case. This is because upstream emissions for the natural-gas fuel cycle are more significant than they are for the coal fuel cycle. Finally, for Case3b (IGCC with CCS), LCEs are 83% less than for the reference case. Emissions from Case 3b are lower than those from Case2b due to the low operations and maintenance costs of the Selexol process in comparison to the MEA process. Moreover, the modeling of the IGCC process does not account for limestone requirements for SO 2 removal because SO 2 removal is performed with a Selexol system instead of an FGD system and so the only requirements for the power plant are those of coal in addition to water. [4,5] reported that IGCC with 90% CO 2 capture exhibits lower life cycle GHG emissions than NGCC, which agrees with results from the current study. An important conclusion can be drawn from Fig. 5 regarding Case1c (super-pc with CCS and without FGD). It is recognized that SO 2 reacts strongly with MEA and so, if FGD is not included upstream of CCS, large quantities of MEA will be needed to remove CO2. Tzimas et al. (2007) state that SO x emissions from coal power plants should be decreased to avoid significant losses of the chemicals that are used to capture CO 2. The present study also reveals that life cycle CO 2 emissions ISSN: ISBN:

8 double if FGD was not included prior to the MEA process. This is caused by the emissions arising from the production (and transport) of chemicals (including MEA) necessary for running the MEA process. Case Table 4. Life cycle emissions (g CO 2 e/kwh) and fuel consumption (MJ/kWh) Life cycle Fuel Comparing with reference case emissions, consumption Reduction of GWP, g CO 2 e/kwh MJ/kWh % Reduction of fossil energy consumption, % Reference 984 8, a 879 8, b a 488 6, ,6 2b 200 7, ,2 3a 861 8, b 167 9, , % Reduction 81 % Reduction g CO2-e/kWh % Reduction Sub-PC Super - PC Super- PC+CCS Super- PC+CCS-No FGD NGCC NGCC+CCS IGCC IGCC+CCS Fig. 5. Comparison of GHG emissions from different technologies with and without CCS. 6. Conclusions The present study shows that life cycle GHG emissions from fossil fuel power stations with CCS can be reduced by 75 84% relative to the reference case: a sub-critical PC power plant. IGCC is found to be favorable with a reduction of GHG emissions to less than 160 g/kwh. For supercritical PC with CCS, it is important to remove SO 2 prior to the capture plant. Failure to do so not only increases O&M costs but also significantly increases GHG life cycle emissions due to the large quantities of MEA that would be required to make up for losses. The CO 2 emission is the main factor that contributes to the GWP indicator. The combustion stage is responsible for at least 50 % of global CO 2. Indeed, the technologies CCS have a big impact on the CO 2 reduction. A sensitivity analysis shows that CO 2 pipeline length have no significant effect on LCEs. For NGCC power plants, on the other hand, the amount of methane leakage from natural gas extraction and transport has a significant effect on life cycle GHG emissions. This study also highlighted and characterized the magnitude of CCS energy requirements, and their impacts on plant-level resource requirements and environmental emissions. While CCS technologies offer some co-benefits for air pollution control via the co-capture of sulfurous air pollutants, the ISSN: ISBN:

9 increases in specific fuel consumption for current CCS systems has significant negative impacts on plant-level consumption of fuel and chemical reagents, as well as on solids wastes and other environmental emissions relative to a similar plant without CCS. Advanced power generation and CCS technologies offering improved efficiency and lower energy requirements are needed to reduce these impacts, and a number of promising options are under development. References: [1] Riahi, K., Rubin, E. S. and L. Schrattenholzer, Prospects for carbon capture and sequestration technologies assuming their technological learning, Proceedings of 6 th International Greenhouse Gas Control Technologies, 1-4 October, 2002, Kyoto, Japan. [2] Chiesa, P. and S. Consonni, Shift reactors and physical absorption for low-co 2 emission IGCCs, Journal of engineering for gas turbine and power, April, 1999, Vol. 121 [3] Gambini, M. and M. Vellini, CO 2 emission abatement from fossil fuel power plants by exhaust gas treatment, in Proceedings of 2000 International Joint Power Generation Conference, Florida, USA [4] Jeremy, D. and H. J. Herzog, The cost of carbon capture. Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, August 2000, Cairns, Australia. [5] Marion, J., Bozzuto, C., Andrus, H., Mccarthy, M., Sundkvist, S.G., and T. Griffin, Controlling fossil fuel power plant CO 2 emissions Near term and long range views, 2 nd Annual Conference on Carbon Sequestration, May 5-9, 2003, Alexandria, VA, USA. [6] Rao, A. B. and E. S. Rubin, A technical, economic, and environmental assessment of amine-based CO 2 capture technology for power plant greenhouse gas control. Environmental Science and Technology, 36, 2002, [7] Simbeck, D., Private communication, April 17, SFA Pacific, Inc., Mountain View, CA. ISSN: ISBN: