Basic Technological Concepts of a “Capture Ready” Power Plant

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Basic Technological Concepts of a “Capture Ready” Power Plant Henryk Łukowicz* and Marcin Mroncz Institute of Power Engineering and Turbomachinery, Silesian University of Technology, Konarskiego 18, 44-100 Gliwice, Poland ABSTRACT: Recent proposals concerning the European Commission directives introduce stricter conditions on obtaining permits for the construction of new power engineering systems. The CO2 storage site has to be specified, and the possibility of completing the technology with a CO2 capture system has to be documented. The designed system has to be ready for completion as soon as commercial CO2 capture technologies arise (i.e., it has to meet the “capture ready” requirements). CO2 separation is a process that needs a large input of energy (the heat flux necessary for desorption). The integration of the CO2 separation system with the thermal cycle of an existing power unit usually calls for a significant reconstruction of the cycle turbine (the intermediate- and low-pressure parts) and, especially, low-pressure regeneration, as well as an adjustment to the turbine cooling system to meet the new conditions. “Capture ready” technologies are reviewed, and the possibility of the intake of steam from the turbine will be determined on the example of a high-capacity (900 MW) hard-coal- and brown-coal-fired power unit. A preliminary scope of the turbine modernization with the use of the absorption method will be analyzed.

1. INTRODUCTION In recent years, worldwide research was started on the process of carbon dioxide (CO2) separation from power engineering systems based on fossil fuels. In the Polish power sector, the problem gains particular importance because of the dominant role of coal. The fundamental condition for a further development of coal-fired power plants is a substantial increase in the efficiency of the use of the coal chemical energy while meeting the more and more stringent requirements concerning allowable CO2 emissions.1 As a member of the European Union, Poland is obliged to reduce the emissions of greenhouse gases. The restrictions are included in the directives of the European Parliament adopted during the summit in March 2007, which are the basis of the “climate and energy package”. Within the package, Poland is obliged to (1) reduce the greenhouse gas emissions by 20% compared to the year 1990, (2) achieve a 20% share of renewable energy in the total energy consumption in the year 2020, (3) increase power engineering effectiveness by 20% with respect to the forecasts for the year 2020, and (4) increase the share of biofuels in the overall consumption of transport fuels to 10%. The reduction is to be performed, among others, in compliance with Directives (1) 2003/87/EC, which establishes a scheme for greenhouse gas emissions allowance trading to support the reduction in emissions in a cost-effective and economically efficient manner, and (2) 2009/31/EC [the carbon capture and storage (CCS) directive], which contains a clause concerning the construction of new installations as “CCS ready”. Under the CCS directive, a requirement was established for the possibility of introducing CCS facilities in newly built power engineering structures (the “CCS ready” requirement), including the reservation of space for the CO2 capture facilities (the “capture ready” requirement). According to the “capture ready” requirement, power engineering structures with a capacity of at least 300 electrical MW have to be executed as ready to be extended with CO2 capture and compression © 2012 American Chemical Society

systems. At present, there is no commercially available CCS technology. It means that, at present, there are no CO2 capture systems that could be installed in power plants on a commercial scale. The only existing installations operate on a pilot scale. This situation, however, is supposed to have changed by the year 2020. Also, there are no localized potential CO2 storage areas or transport infrastructure. Currently in Poland, within the strategic research program announced by the National Centre of Research and Development, Task 1 “Development of a Technology for Highly Efficient Zero-Emission Coal-Fired Power Units Integrated with CO2 Capture”, works are being carried out with a view to the introduction of commercial technologies for the reduction in CO2 emissions into the atmosphere. To promote CCS, the European Council approved permits for 300 million tons of CO2 emissions, which will be distributed among demo installations of this type (12 demo projects). Financial support for them is to amount to approximately 9 billion euros. Two structures with CCS systems are currently being planned in Poland. At the end of 2010, the European Parliament adopted Directive 2010/75/EU, which lays down the following: (1) rules related to integrated prevention of pollution resulting from industrial activity, (2) rules related to the control of that pollution, and (3) rules designed to prevent the emissions into the air, water, and soil and, should there be no such possibility, aimed at their reduction and prevention of waste generation to reach a high level of environment protection. The directive tightens the existing regulations concerning the emissions of sulfur dioxide, nitrogen oxides, and dust. The reduction in the emissions of these compounds is already under full control. Therefore, it is certain that the existing and newly Special Issue: International Conference on Carbon Reduction Technologies Received: October 27, 2011 Revised: June 19, 2012 Published: June 26, 2012 6475

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designed systems will satisfy the standards stipulated in the directive. The problem of the reduction in CO2 emissions can be solved using one of the following methods (Figure 1): (1) precombustion separation of CO2, (2) post-combustion separation of CO2, and (3) oxygen combustion.

Figure 2. Simplified diagram of IGCC. one or more components from the gas phase and (2) obtaining a particular component in the liquid phase. CO2 sequestration by means of this method is based on reactions that are reversible with heat brought from the outside. A simplified

Figure 1. Methods of CO2 separation.

The paper was written based on studies and tests conducted within the project that is being completed by the authors. A survey of CCS technologies is part of this particular project, but it focuses on post-combustion methods and, more precisely, the absorption method. Other methods are presented briefly. The problems discussed in the paper are limited to the amount of heat needed for the sorbent regeneration, because this is the issue that has a decisive impact on the turbine upgrade after the power plant has been integrated with a capture installation. The CO2 compression and the sorbent pump power capacities were ignored. For the plant under analysis, they are included in the range of 50−65 MW.

Figure 3. Diagram of the absorber−stripper system. diagram of the system is presented in Figure 3. The sorptive liquids (sorbents), which are most often used, are (1) aqueous solutions of amine [e.g., monoethanolamine (MEA) and diethanoloamine (DEA)], (2) aqueous solutions of ammonia (NH3), and (3) alkaline aqueous solutions. MEA belongs to the group of ethanolamines obtained in the reaction of ethylene oxide with NH3. The basic characteristic of ethanolamines is a high absorptive capacity. The flue gases from which CO2 is captured must meet very strict purity requirements: (1) 40 mg N−1 m−3 NOx (6% O2) and (2) 10−30 mg N−1 m−3 SOx (6% O2), so that the sorbent will not undergo chemical degradation, which prevents regeneration and, consequently, causes a higher consumption of MEA. Absorption by means of NH3 proceeds in a way similar to the amine method. The conditions put on purified gases for the use of NH3 are not as hard as those for the use of amines. 2.2.2. Physical Adsorption. In this method, the separation of CO2 from flue gases occurs by means of adsorption on the sorbent at a constant temperature and pressure. Next, through a change in pressure and/or temperature, CO2 is separated in the adsorption process. The process is presented in Figure 4. The adsorption−desorption process is carried out by means of methods, such as (1) temperature swing adsorption (TSA), (2) pressure swing adsorption (PSA), (3) ultrarapid pressure swing adsorption (URPSA), (4) vacuum swing

2. BASIC TECHNOLOGICAL CONCEPTS OF A “CAPTURE READY” POWER PLANT 2.1. Pre-combustion. The pre-combustion separation method prevents CO2 emissions by removing CO2 before burning the fuel. The fuel reacts in the atmosphere of steam or with a reduced content of air, and as a result of this reaction, synthesis gas is obtained (H2 and CO). The gas is subject to reforming, which produces CO2 and H2. CO2 reduction is carried out in steam−gas integrated gasification combined cycles (IGCCs); a simplified diagram of the system is shown in Figure 2. Coal is gasified in gas generators in the temperature of (1) 1300 °C for a unit manufactured by General Electric, (2) 1370 °C for the unit made by Conoco Philips E-Gas, and (3) 1400−1450 °C for the unit made by Shell. 2.2. Post-combustion. The post-combustion separation method consists of the separation of CO2 from flue gases produced in the combustion reaction. CO2 capture occurs via (1) physical or chemical absorption, (2) adsorption, (3) membrane separation, and (4) cryogenic separation. 2.2.1. Chemical Absorption. The method is a process of dissolving gas in a liquid; it is possible when the mass movement coincides with a chemical reaction. It can be divided into two stages:2 (1) separation of 6476

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Figure 4. CO2 separation and compression system4 (B, boiler; C, compressor; HE, heat exchanger; M, membrane; and VP, vacuum pump).

Figure 5. Simplified diagram of the oxygen combustion technology.

Figure 6. Diagram of the initial cycle (B, boiler; HP, high-pressure part; IP, intermediate-pressure part; LP, low-pressure part; FWH, feedwater heater; and DSH, desuperheater). temperature and pressure, but the steam mass flow extracted from the steam bleed will be greater than for steam with higher parameters. Additionally, the lower its temperature, the worse the conditions for heat exchange in the stripper. For this reason, the temperature must be adequately higher than the flue gas temperature, i.e., the temperature at which the desorption process is carried out.

adsorption (VSA), and (5) pressure temperature swing adsorption (PTSA). To make it possible to integrate the physical adsorption method with the power unit, first the sorbent has to be selected. The sorbent regeneration process needs energy whose source is steam from the turbine bleed. It can be seen from the research presented in ref 3 that the most effective is the use of steam with the lowest possible 6477

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2.2.3. Membrane Separation. In this method, permeation, i.e., CO2 separation, is based on the use of phase membranes whose task is to separate two different phases into the permeate (the part that penetrated through the membrane) and the retentate (the part that remained before the membrane). The operation principle is based on the difference in partial pressures before and after the membrane. It is executed by overpressure on either the feeding side or the permeate side. A simplified diagram of the system is presented in Figure 4. After they have been purified, the boiler (B) flue gases are precompressed in the condenser (C) and, having passed through the heat exchanger (HE1), they arrive at the membrane (M), where they are separated into the permeate and retentate. Using the CO2 capture and compression system, the fall in efficiency is from 14 to 16.5%.4 To reduce the fall, the following can be performed: (1) reduce the permeate temperature at the compressor inlet and (2) use the heat from the cooling of flue gases and the permeate. The latter is of particular importance because the heat can be used in the steam−water cycle of the steam turbine. The amount of heat carried away from the CO2 separation and compression system can be used instead of the system of low-pressure regenerative heaters. A removal of this system results in an increase in the mass flow through the last part of the turbine, which involves a rise in the electric power and an improvement in electricity generation. 2.3. Oxy-combustion. In oxygen combustion, the fuel is burnt at a higher content of oxygen with CO2 recirculation. Nitrogen is removed from the air necessary for combustion, which results in a reduction in the emissions of the so-called air NOx compounds. The flue gases practically contain only CO2 and steam; after the latter has been condensed, the obtained CO2 is ready for compression, transport, and storage. A general diagram is presented in Figure 5.

Table 2. Characteristics of Fuel in the Working State parameter

hard coal (MJ/kg)

brown coal (MJ/kg)

calorific value moisture content ash content C content H content O content N content S content

23 0.090 0.200 0.599 0.038 0.050 0.012 0.010

7.75 0.5140 0.1140 0.2320 0.0192 0.1050 0.0032 0.0126

range of 150−330 m/s, which is adopted for turbine construction. The following definitions of efficiency were adopted in the analysis. Cycle efficiency: Q̇ ηob = 1 − w Q̇ d Q̇ w = Q̇ skr + Q̇ wym + Q̇ r

where Q̇ w is the extracted heat flux, Q̇ skr is the heat flux carried away in the condenser, Q̇ wym is the heat losses in regenerative exchangers, Q̇ r is the heat losses in live and reheated steam pipelines, and Q̇ d is the heat flux in the boiler. Gross electricity generation efficiency:

3. CHARACTERISTICS OF THE INITIAL CYCLE An analysis was made of the possibility to integrate a CO2 capture system with the power unit presented in Figure 6. The basic parameters are listed in Table 1.

ηw en elB =

Table 1. Basic Parameters of the Initial Cycle

Q̇ en ch =

parameter

unit

value

electric power (gross) live steam pressure live steam temperature reheated steam temperature pressure in the condenser feed water temperature efficiency of the boiler fired with hard coal (flue gas waste heat temperature of 120 °C) brown coal (flue gas waste heat temperature of 170 °C)

MW MPa °C °C kPa °C %

900 30.3 653 672 5 310 94.5

%

90.0

NelB Q̇ en ch

NelB = Niηmηg

Q̇ d ηk

where NelB is the gross electric power, Ni is the steam turbine internal power capacity, ηm is the mechanical efficiency, ηg is the generator efficiency, Q̇ en_ch is the fuel chemical energy, and ηk is the boiler efficiency. Net electricity generation efficiency: ηw en elN =

NelB − Npw Q̇ en ch

where Npw is the own needs power capacity (assumed Npw = 0.075NelB). Table 3 presents the indices of the power unit operation. It was assumed that the post-combustion method of chemical absorption would be used to separate CO2. Further analyses concerned the possibility of the integration of the method with the initial cycle.

The parameter characteristics of the boiler were given by the boiler manufacturer RAFAKO S.A., which is a co-contractor of the strategic research program, Task 1.5 The cycle is equipped with four low-pressure and three high-pressure regenerative exchangers, as well as a steam attemperator. The boiler feed pumps are driven by electric motors (the option with pumps driven by the steam turbine was also considered). Parallel cooling of condensers was adopted. The cycle calculations were carried out for two typical kinds of fuel; gram content values are listed in Table 2. The number of steam outlets from the turbine was determined on the basis of the outlet velocity from the last stage of the LP part. For four outlets (two double-flow LP parts) with cross-sections used in modern turbines, the velocity will be approximately 250 m/s. The value is included in the

4. HEAT NEEDED FOR THE CO2 SEPARATION SYSTEM The process of CO2 chemical absorption or desorption, to be precise, is very energy-consuming. In the studies gathered in ref 6, the amount of heat necessary to separate 1 kg of CO2, which is 4.7 MJ/kg of CO2 for MEA and 2.45 MJ/kg of CO2 for NH3, was determined. Research is now being conducted to reduce these values. New sorbents that are mixtures of amines are being researched, and the absorber−stripper system is being optimized. It is stated in ref 7 that the amount of heat can be reduced to 2.83 MJ/kg of CO2 for MEA. The research 6478

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Table 3. Indices of the 900 MW Power Unit Operation value parameter

unit

electric power (gross) internal power of the feedwater pump internal power of all condensate pumps cycle efficiency electricity generation efficiency (gross) electricity generation efficiency (net) unit heat consumption unit consumption of the fuel chemical energy outlet velocity from the last stage of the LP part flue gas mass flow CO2 mass flow in flue gas

MW MW MW % % % kJ/kWh kJ/kWh

hard coal

900.19 28.75 1.18 50.92 49.06 46.32 45.38 42.85 6927.30 7337.40 7771.50

m/s kg/s kg/s

brown coal

251.24 833.36 176.34

Figure 8. Chart of saturation temperature dependence upon pressure at bleeds 4−8.

1104.53 217.70

Table 4. Indices of the Power Unit Operation with the Use of MEA as the Sorbent

conducted at the Research Institute of Innovative Technology for the Earth (RITE) assumes the reduction in the heat to 2 MJ/kg of CO2 for MEA and a development of synthetic amines for which the heat is definitely lower.8 The amount of heat that has to be generated for desorption to capture 1 kg of CO2 is presented in Figure 7 for different sorbents. Figure 8 shows the saturation temperature for pressure at five bleeds 4−8 (Figure 6). They indicate the possible places of steam extraction from the turbine for the sorbent regeneration. It was assumed that the amount of heat that had to be brought into the CO2 capture system was (1) 4.7 MJ/kg of CO2 for MEA and (2) 2.45 MJ/kg of CO2 for NH3. Tables 4 and 5 present the indices of the power unit operation for the sorbents used in the CO2 separation system.

value parameter

unit

hard coal

brown coal

CO2 mass flow heat flux needed to separate 100% CO2 total heat flux in outlet steam from the IP part steam mass flow directed to the LP part of the turbine steam mass flow needed to separate 100% CO2 content of steam directed to the CO2 separation system

kg/s MW MW kg/s

176.3 217.7 828.8 1023.2 1064.0 437.0

kg/s %

340.4 77.9

420.3 96.2

For the cycle configuration under consideration, the steam parameters after the IP part are a bit too low to heat the NH3 sorbent. Therefore, the last stage in this part of the turbine should be removed. Consequently, the power capacity of the IP part of the turbine will decrease by the power capacity of the removed stage.

5. TURBINE RECONSTRUCTION One of the turbine reconstruction methods presented in ref 9 was analyzed. To maintain for a given sorbent the temperature value of the steam brought to heat it, it is necessary to install an adjustment flap before the LP part of the turbine (Figure 9).

Figure 7. Heat amount needed for sorbent regeneration.6−8 6479

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Table 5. Indices of the Power Unit Operation with the Use of NH3 as the Sorbent value parameter

unit

hard coal

brown coal

CO2 mass flow heat flux needed to separate 100% CO2 heat flux directed to the CO2 separation system steam mass flow directed to the LP part of the turbine steam mass flow needed to separate 100% CO2 content of steam directed to the CO2 separation system

kg/s MW MW kg/s

176.3 217.7 432.0 533.4 1064.0 437.0

kg/s %

177.5 40.6

219.1 50.1

Figure 10. Diagram of the turbine with one LP part removed.

desorption process requires a large input of energy (the heat flux needed for the sorbent regeneration). For a hard-coal-fired power unit integrated with a capture system where MEA is the sorbent, the heat flux needed to separate 100% CO2 is 829 MW, and for a hard-coal-fired power unit integrated with a capture system where NH3 is the sorbent, the heat flux needed to separate 100% CO2 is 432 MW. For brown coal and MEA, the heat flux is 1023 MW, and brown coal and NH3, the heat flux is 533 MW. The integration of the CO2 separation system with the thermal cycle of a 900 MW power unit calls for a significant reconstruction of the turbine (the IP and LP parts) and, especially, the low-pressure regeneration, as well as an adjustment to the turbine cooling system to meet the new conditions. The reconstruction of the turbine could consist of adding stages in the IP part, removing stages in the IP and LP parts, or removing one or even two LP parts. These actions will result in changes in the turbine efficiency and, consequently, in the efficiency of the power unit.

Figure 9. Diagram of the turbine with an adjustment flap.

If the amine sorbent is used, the parameters of the steam from the IP outlet are too high. The scope of the turbine modernization would then entail extending the IP part with additional stages in the IP part and removing the initial stages in the LP part of the turbine. If it is impossible to add stages in the IP part, an additional decompression turbine can be installed. The intake of steam for the CO2 separation system will also cause a change in the operating conditions of the LP part of the turbine, because of the substantially reduced steam mass flow. This is the reason for the decrease in the efficiency of this part of the turbine. To reduce the fall, in the case of the amine sorbent, the LP part configuration should be changed (one LP part would have to be removed; Figure 10), which will increase the steam mass flow in the second part. For hard coal, the mass flow will amount to 45% of the nominal mass flow, whereas for a brown-coal-fired unit, it is only 8%. In the latter case, the operation of the LP part with such a small mass flow is not possible; two LP parts would have to be removed, and the use of the remaining steam mass flow would have to be considered. If NH3 is the sorbent, the steam mass flow needed for its regeneration will be smaller than for the amine sorbent. Because the amount of this steam is smaller than the nominal mass flow feeding one LP part, operation of each LP part could be considered with a 60% load for hard coal; for brown coal, one LP part would have to be removed.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The results presented in this paper were obtained from research work co-financed by the National Centre of Research and Development in the framework of Contract SP/E/1/67484/10, Strategic Research Programme (Advanced Technologies for Energy Generation: Development of a Technology for Highly Efficient Zero-Emission Coal-Fired Power Units Integrated with CO2 Capture).

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REFERENCES

(1) Łukowicz, H.; Chmielniak, T.; Mroncz, M. Badanie wpływu sorbentu (amina, amoniak) na zakres modernizacji turbiny zintegrowanej z instalacją separacji CO2. Proceedings of the Research and Development in Power Engineering 2009; Warsaw, Poland, Dec 8−11, 2009; pp 113−122.

6. CONCLUSION It results from the conducted analysis of the “capture ready” technology that, to separate CO2 from the boiler flue gases, the method of chemical absorption has the biggest chance. The 6480

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(2) Ramm, W. M. Procesy Absorpcyjne w Przemys ́le Chemicznym; PWT: Warsaw, Poland, 1954. (3) Sztekler, K.; Panowski, M.; Klajny, R. Analiza rozwiaz̨ ań konfiguracyjnych integracji technologii wychwytu CO2 z konwencjonalną siłownią cieplna.̨ Prace Naukowe PW Konferencje; Warsaw, Poland, 2009; Book 26, OWPW, pp 317−324. (4) Kotowicz, J.; Szymańska, K. The thermodynamic and economic analysis of the supercritical coal fired power plant with CCS installation. Proceedings of the 6th International Scientific and Technical Conference and Exposition: Diesel and Gas Turbine ’09; Mied̨ zyzdroje, Poland−Copenhagen, Denmark, April 26−30, 2009. (5) Strategic Research Programme. Advanced Technologies for Energy Generation: Development of a Technology for Highly Efficient ZeroEmission Coal-Fired Power Units Integrated with CO2 Capture; http:// energetyka.projektstrategiczny.pl. (6) Wójcik, K. Modeling processes of CO2 absorption from flue gas of high capacity power plants. Ph.D. Dissertation, Institute of Power Engineering and Turbomachinery, Silesian University of Technology, Gliwice, Poland, 2010. (7) Duan, L.; Zhao, M.; Xu, G.; Yang, Y. Integration and optimization on the coal fired power plant with CO2 capture using MEA. Proceedings of the 24th International Conference ECOS 2011; Nowy Sad, Serbia, July 4−7, 2011; pp 582−593. (8) Chowdhury, F. A.; Okabe, H.; Yamada, H.; Onoda, M.; Fujioka, Y. Synthesis and selection of hindered new amine absorbents for CO2 capture. Energy Procedia 2011, 4, 201−208. (9) Irons, R.; Sekkapan, G.; Panesar, R.; Gibbins, J.; Lucquiaud, M. CO2 Capture Ready Plants; IEA Greenhouse Gas R&D Programme: London, U.K., 2007.

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