Clean Techn Environ Policy DOI 10.1007/s10098-015-0936-7
ORIGINAL PAPER
Comparative analysis of four gas-fired, carbon capture-enabled power plant layouts R. J. Basavaraja1 • S. Jayanti1
Received: 3 November 2014 / Accepted: 7 March 2015 Springer-Verlag Berlin Heidelberg 2015
Abstract Emission of carbon dioxide from fossil fuelfired thermal power plants is a major concern for energy providers all around the world. In this context, carbon capture from thermal power plants and the energy penalty incurred in the process are important issues. The present work reports on a detailed analysis of gas-fired power plant layouts with in-built carbon capture, i.e. the flue gas from these power plants contains mainly carbon dioxide and water vapour. Four layouts, two of which are based on pressurized oxyfuel combustion and two on chemical looping combustion (CLC), have been considered. Based on detailed mass balance, energy and thermodynamic analyses of the power plant layouts, the net efficiencies for each plant have been computed. After accounting for thermodynamic irreversibilities and CO2 compression to 110 bar, these have been found to vary between 31 and 52 % for the four plants. Despite the technological maturity of oxyfuel combustion, it is concluded that CLC-based plants would be future-ready in the sense that they can readily accommodate CCS with only 2 % loss in overall thermal efficiency for CO2 capture.
CC SMOC CLCSC HRSG LP MP HP AR FR MAirin MDepair
Keywords Carbon capture Fossil fuels Chemical looping combustion Oxyfuel combustion Combined cycle power plant First law analysis
QDepletedair QMeOx
MMeOx MMeOx1 MFuelin MExhaust T QAirin
QMe Abbreviations ASU Air separation unit CLC Chemical looping combustion
QOx QExtract
& S. Jayanti
[email protected]
QFuelin
1
QRed
Department of Chemical Engineering, IIT Madras, Chennai 600036, India
Combined cycle Steam-moderated oxyfuel combustion Chemical looping combustion steam cycle Heat recovery steam generator Low pressure Medium pressure High pressure Air reactor Fuel reactor Mass of air entering air reactor per unit time, kg/s Mass of depleted air leaving air reactor per unit time, kg/s Mass of oxygenated metal oxide per unit time, kg/s Mass of reduced metal/metal oxide per unit time, kg/s Mass of fuel entering fuel reactor per unit time, kg/s Mass of exhaust leaving fuel reactor per unit time, kg/s Temperature at any point, C Thermal energy flow in air entering the air reactor, kW Thermal energy flow in oxygen-depleted air, kW Thermal energy flow in oxygenated metal oxide, kW Thermal energy flow in reduced form of metal oxide, kW Thermal energy produced by metal oxidation reaction, kW Thermal energy extracted from air reactor by cooling fluid, kW Thermal energy flow in fuel entering the air reactor, kW Heat produced by metal reduction reaction, kW
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R. J. Basavaraja, S. Jayanti
Subscripts MeO Oxygenated metal oxide Me Reduced form of metal oxide e Electrical (related to power, as in MWe) Ox Oxidation Red Reduction x, x - 1 Oxidized and reduced states of O2 carrier, respectively th Thermal (related to power, as in MWth)
Introduction The emission of carbon dioxide from thermal power plants is a matter of considerable concern for policy makers and energy providers all over the world (IPCC 2013). At present, combustion of fossil fuels accounts for around 82 % of primary energy production and for more than a third of the anthropogenic CO2 emissions (IEA 2013). The 2012 concentration of CO2 is 394 ppm which is about 40 % higher when compared to mid-1800 s (IPCC 2013). Despite these grave concerns, the outlook on CO2 emissions is rather bleak. There are several advantages with fossil fuels from a power generation point of view, and while efforts are being made to make power generation less CO2-intensive (for example, by increasing efficiency and by shifting from coal to natural gas), it is expected that dependence on fossil fuels is set to continue and countries such as India will continue to depend significantly on coalbased power generation for the next few decades (Jayanti et al. 2012). In view of this prospect of sustained CO2 emissions for power and industrial sectors, there has been tremendous interest in recent years on means of carbon capture and sequestration (CCS) with special focus on capture of combustion-related CO2 emissions (IPCC 2013). A number of ways of pre- and post-combustion capture techniques have been proposed; a recent review of these has been provided by Wall (2007) and Davidson and Thambimuthu (2009). Though some of these such as oxyfuel combustion are technically mature and may even permit retrofitting (Mousavian and Mansouri 2011; Jayanti et al. 2012), these technologies involve significant energy penalty for gas separation, purification and compression (Finkenrath 2011; Jenni et al. 2013). Additional cost will be incurred for sequestration; this will depend on the technology used as well as on a number of geophysical/ political/economic factors. Implementing CCS will thus have an impact on the cost for the electricity production. A number of recent studies have been reported on process integration for better efficiency and integration with other power sources (Hetland 2009). Ng et al. (2012) discussed the promotion of coal-based decarbonized energy system with CO2 utilization and polygeneration. Wang et al.
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(2013) described a framework for integration of solid oxide fuel cells with process utilities. Gutie´rrez-Arriaga et al. (2013) discussed multi-objective optimization of steam power plants. Faizal et al. (2014) presented a 3-E (energy, economic and environmental) analysis of a flat-plate solar collector operator with a high thermal conductivity fluid. A methodology for criticality analysis of integrated energy systems was discussed by Benjamin et al. (2014), while Theodors et al. (2014) approached the problem of optimum synthesis of a solvent-based post-combustion capture system using a generalized modelling framework. Taking the coal-fired power industry of Shenzhen, China as a case study, Huang et al. (2014) assessed various short-term and long-term technology investment strategies and found that integrated gasification combined cycle plants offered the best scope. Of late, biofuels have been attracting considerable attention for both power generation and as a source to produce reformate fuels for internal combustion engines (Prabhakar and Elder 2009; Costa and Sodre´ 2010). Their performance in internal combustion engines has been reviewed by Sadeghinezhad et al. (2013), the costs involved by Sadeghinezhad et al. (2014a) and the issues related to sustainability and environmental impact by Sadeghinezhad et al. (2014b). Among carbon capture technologies, chemical looping combustion (CLC) has received wide attention in recent years as an efficient process of power generation from fossil fuels with comparatively low penalty for CO2 capture. As shown in a seminal paper by Ishida et al. (1987) through analysis, CLC results in significantly reduced exergy loss compared to conventional or oxyfuel combustion, which raises the prospect of lesser thermal efficiency penalty for carbon capture. The basic parameters of CLC systems, such as useful oxygen carriers and their operating characteristics for various gaseous fuels, are now well understood, and a number of studies are being conducted to investigate optimal reactor configurations. A comprehensive review of the current status of CLC is given by Adanez et al. (2012). Another CO2 capture technology that has been receiving significant attention due to its technical maturity—several demonstration plants are being constructed or are on the anvil (Gra¨bner et al. 2010), is oxyfuel combustion (Buhre et al. 2005) where conventional fossil fuels are combusted in nitrogen-free environment so as to produce a flue gas which is rich in CO2. Several variants of oxyfuel combustion are possible (Sivaji and Jayanti 2010; Seepana and Jayanti 2012); estimates of Rankine cyclebased oxyfuel combustion plants (Kanniche et al. 2010; Seepana and Jayanti 2012; Jayanti et al. 2012) show an energy penalty for carbon capture in the range of 10–12 %. Similar studies for CLC (Naqvi 2006; Basavaraja and Jayanti 2015) show this to be lesser for CLC. The overall thermal efficiency also depends on the type of fuel; for
Comparative analysis of four gas-fired, carbon capture-enabled power plant layouts
example, recent estimates (Basavaraja and Jayanti, 2015) show that the higher CO2 content of syngas leads to a few percentage points drop in thermal efficiency compared to natural gas. Higher thermal efficiencies are possible with pressurized combustion (Kvamsdal et al. 2007), and, lately, there has been interest in pressurized combustion with both modes of CO2 capture (Siefert and Litster 2013). The kinetics of pressurized oxyfuel combustion with coal (Tan et al. 2006) and gaseous fuels (Ditaranto and Hals 2006; Maruta et al. 2007) as well as on NOx production (Sivaji and Jayanti 2009) have been well-studied in the literature. Jin and Ishida (2001), Adanez et al. (2006) and Abad et al. (2007) studied the kinetics of pressurized CLC for several oxygen carriers using thermogravimetric analysis (TGA) techniques. While these results cannot be extrapolated to reactor conditions, these show that pressurized CLC is feasible and that the kinetics of CLC reactions in the pressure range of 1–15 bar are not significantly altered. These studies give rise to the possibility of achieving higher thermal efficiency and reduced capture penalty by using a combined cycle operation. While studies of oxyfuel-based integrated gasification combined cycle (IGCC) (Gra¨bner et al. 2010; Sivaji and Jayanti 2010; Seepana and Jayanti 2012; Lee et al. 2014) and CLC-based combined cycle operation (Wolf 2004; Naqvi 2006) have been reported in the literature, detailed power plant layouts have not been discussed. Against this background, the purpose of the present work is to make a detailed and comparative assessment of gas-fired power plant layouts incorporating carbon capture in four ways with a view to understanding where and how heat is generated and how it can be used to generate electrical power (using a gas or steam turbine) while still ensuring capture of CO2 in the stack. Gaseous fuels have advantages over solid fuels from a combustion point of view, and in a future scenario with tight environmental regulations, gasification of low-grade solid fuels followed by gas cleaning as necessary may be the best way of using solid fuels (Huang et al. 2014). Gasification may also enable safe usage of several opportunity solid fuels such as biomass, by-products from process industry with significant calorific value, municipal waste and agro-industry waste, etc. Gasification of the fuel in some of these cases can also be seen as a safe and economic means of waste disposal. Each of these solid fuels will have their spectrum of harmful by-products that need to be eliminated through gas cleaning through source-specific solutions. We therefore envisage a future scenario in which combustible, precleaned gases are produced and these are available for power generation with only carbon dioxide as the primary pollutant to be removed. It is assumed that ultra-low NOx burners will be used so that removal of NOx will not be a problem. Further, carbon dioxide capture is not mandatory
at present, and the technological and commercial framework for safe utilization/disposal through storage of CO2 is not yet in place. However, given that the lifetime of a thermal power plant is typically in excess of 50 years, it is likely some requirement to this effect will arise within the lifetime of power stations that are soon to be built. Thus, we look for a gas-based power plant with in-built carbon capture as the primary electricity provider of the future. In the present study, we consider three such gas-fired power plants and develop a detailed process flow diagram for each so that their suitability for future power generation can be assessed with specific reference to the extent of retrofitting and reconfiguration that would be necessary when it would have to be run with carbon capture. The choice of the power plant configurations considered in the present study is based on three factors: • • •
The maturity of the technology, in terms of readiness for deployment within the next one or two decades, The energy penalty for CO2 capture and The possibility of introducing known measures for efficiency improvement such as reheating, supercritical boiler operation, etc.
Considering these factors, the following four power plant configurations have been chosen for detailed study: (a) a power plant operating on CLC at atmospheric pressure using a Rankine cycle for power generation, (b) a power plant operating on pressurized CLC using a combined cycle for power generation, (c) a power plant operating on pressurized oxyfuel combustion with exhaust gas recycling using a combined cycle for power generation, and (d) pressurized steam-moderated oxyfuel combustion (Sivaji and Jayanti 2010) which offers significant benefits in combined cycle mode. In what follows, a detailed process flow diagram is developed for each plant; these are used to assess their suitability as a power plant of the future. For the sake of comparison, all the four are assumed to be fired by natural gas, although similar calculations can also be done for syngas.
Outline of the calculation Atmospheric chemical looping combustion The principle of CLC is illustrated in Fig. 1. Here, the combustion of a hydrocarbon fuel is carried out in two stages. Firstly, a metal (or a metal oxide in which the metal is in a low oxidation state) is brought into contact with air so that a metal oxide or a higher oxide is formed by selective reaction with oxygen contained in air as per reaction 1. In the second stage, the metal oxide reacts with the hydrocarbon fuel and gives up its oxygen (partly or fully)
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R. J. Basavaraja, S. Jayanti Metal oxidation (exothermic) N2 + unreacted O2 Heat Air
MeOx Oxidised metal particle
Metal reduction (either exothermic or endothermic) Fuel
MeOx-1 Reduced metal particle
Sequestration H2O + CO2
Fig. 1 Principle of chemical looping combustion
to oxidize the carbon in the fuel to carbon dioxide and the hydrogen to water vapour as per reaction 2. MeOx1 ðs) þ Air(g) ! MeOx ðs) þ N2 ðg) þ unreacted O2 ðg)
ð1Þ
MeOx ðsÞ þ Cm H2n ðgÞ or ðsÞ ! MeOx1 þ mCO2 ðg) þ nH2 O(g)
ð2Þ
Here, terms MeOx - 1 and MeOx represent, respectively, the reduced and the oxygenated states of oxygen carrier. The two-stage combustion of the hydrocarbon fuel eliminates the need for oxygen separation from air and prevents the contamination of the product gas of the fuel reactor with nitrogen. The exhaust from the fuel reactor will thus primarily be CO2 and water vapour; the latter can be easily separated through condensation leaving a nearly pure stream of CO2, which can therefore be sent directly for compression for eventual storage. The oxidation and reduction reactions are carried out typically at high temperatures in separate air and fuel reactors, respectively, of a circulating fluidized bed reactor system. The hot product gases from the reactors are taken through separate streams for heat recovery and sequestration/disposal as applicable. For a gaseous fuel, the bed material consists of the metal/metal oxide which is circulated between the oxidation (air) reactor and the reduction (fuel) reactor. In order to withstand the high mechanical and thermal stresses associated with the circulation in a fluidized bed/pneumatic conveying mode, the catalyst particles are usually embedded or sintered on to a ceramic support. Considerable research work, running into thousands of research articles, has been reported on CLC, and several aspects of CLC have been understood satisfactorily. Several pilot plants studies are also being undertaken in various laboratories (Adanez et al. 2012). Based on these, a nickel-based oxygen carrier, specifically, NiO supported on NiAl2O4 in the weight ratio of 60:40, which has been shown to achieve [99 % conversion for both natural gas and syngas (Johansson et al. 2006), is used in the present study. We further assume that the fuel and the air reactors operate under isothermal conditions at temperature of 900 and 1000 C, respectively. The calculation of NiO flow rate is based on 25 % excess oxygen supply in the fuel reactor, and therefore, 80 % by mass of the NiO entering
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the fuel reactor gets converted to Ni. An excess oxygen supply of 5 % is assumed in the air reactor. These assumptions enable the calculation of the air and the oxygen carrier flow rates for a given thermal power rating of the plant. The heat release rates at stoichiometric conditions, with methane as the fuel and Ni/NiO as the metal/metal oxide (Adanez et al. 2012), are given by the following reactions: 4NiO þ CH4 ! 4Ni þ 2H2 O þ CO2 DH900 C ¼ 133:6 kJ=mol CH4
ð3Þ
2Ni þ O2 ! 2NiO
ð4Þ
DH1000 C ¼ 468:5 kJ=mol O2
As can be seen, the reaction in the fuel reactor (between CH4 and NiO) is endothermic while that in the air reactor is exothermic. The net heat release by the entire system is the same as in air or oxyfuel combustion of CH4 and is given by reaction (5): CH4 þ 2O2 ! 2H2 O þ CO2 DH1000 C ¼ 803:4 kJ=mol CH4
ð5Þ
Similar stoichiometric reactions can be used for the other components of natural gas to arrive at the overall oxygen requirement and heat release. A typical energy balance model can be written as follows. With reference to Fig. 2 for the atmospheric CLC case in which there would be an in-bed heat exchanger in air reactor, the heat balance for the air and the fuel reactors is expressed by Eqs. (6) and (7), respectively: QAirin þ QMe þQOx ¼ QDepair þ QMeO þ QExtract
ð6Þ
QFuelin þ QMeO þ QRed ¼ QExhaust þQMe
ð7Þ
Here, terms QMeO, QMe, QAirin and QDepair are the thermal power flow associated with the oxygenated metal, reduced metal, air entering and oxygen-depleted air leaving the air reactor. Term QExtract is the heat extracted in air reactor by the steam side. Terms QOx and QRed are the heats of oxidation and reduction in the air and the fuel reactors and are calculated by multiplying mass of the reactive gas stream (O2 or fuel) with the heat of reaction at reactor temperature. QFuelin and QExhaust are the thermal power associated with the flow of the fuel stream and of the CO2-rich exhaust gases of the fuel reactor. The enthalpy of various gas streams can be calculated using temperaturedependent correlations for the heat capacities of the individual components (Nayef and Redhoune 2010) while those for the metal/metal oxide and the ceramic support can be obtained using correlations given by Knacke et al. (1991) and Barin (1989), respectively. In the present work, mass and energy balances have been used on all the major equipment on the furnace side (the reactors and the preheaters). These are then linked to the steam side calculation, which is based on a supercritical
Comparative analysis of four gas-fired, carbon capture-enabled power plant layouts Fig. 2 Mass and heat balance for atmospheric CLC a air reactor with in-bed heat exchanger and b fuel reactor Air reactor
(a) Rankine cycle with two reheats, as illustrated in Fig. 3. The two sides are coupled together by the heat transfer to the steam side through the in-bed heat exchanger in the air reactor as well as by the energy used for feedwater heating. Therefore, the furnace and the steam side calculations have been performed together to arrive at the process flow diagram for the atmospheric CLC plant. A similar approach of developing the process flow diagram for a power plant layout has been used previously by the present authors (Seepana and Jayanti 2012; Prabu and Jayanti 2012; Basavaraj and Jayanti 2015). Full details of the coupled calculations for the atmospheric CLC system can be found in Basavaraj and Jayanti (2015).
Fig. 3 T–s diagram of supercritical, double reheat 240 bar/600/600/ 600 C steam cycle
Fuel reactor
(b)
Pressurized chemical looping combustion Pressurized operation of the combustor enables combined cycle operation in which Brayton and Rankine cycles can be used to generate with an increased overall thermal efficiency of the power plant (Kehlhofer 1999; El-Wakil 2010). Of late, pressurized CLC has been receiving attention from the point of view of kinetics, carbon conversion and reactor configurations (Abad et al. 2007; Xiao et al. 2010, 2012; Zheng et al. 2014). Studies of Garcia-Labiano et al. (2006) show that while the reactivity of Ni-based oxygen carriers is reduced at high pressures, the extent of conversion is relatively unaffected and remains at nearly 100 % for typical gaseous fuels, namely, CH4, CO, H2 as well as for oxygen. The slowing down of the reaction kinetics is significantly high at high pressures (in the range of 15–30 bar). Therefore, the highest gas pressure is taken to be 13 bar for the combined cycle. The same oxygen carrier as for atmospheric CLC is also used for pressurized CLC. Since the slowing down of the kinetics is not likely to alter the conversion efficiency significantly at this pressure, the fuel conversion is assumed to be 100 %. Studies in pilot plants (Erlach et al. 2011) also showed that Ni-based oxygen carriers could operate successfully with no agglomeration and attrition at temperatures up to 1300 C. Since high temperatures are required for efficient operation of a gas turbine engine, the pressure and temperature of the air reactor are fixed at 13 bar and 1200 C, respectively. The fuel reactor requires heat input to sustain the endothermic metal reduction reaction. This is sought to be brought in by the metal oxide coming in from the air reactor. Also, from reactivity considerations, the air reactor is operated in a fast fluidization mode, while the fuel reactor is operated in a bubbling fluidized bed mode. The pressure drop across the latter is expected to be high. In view of these factors, the fuel reactor is assumed to operate at a slightly lower pressure and temperature of 11.5 bar and 1150 C. These conditions are broadly in alignment with
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R. J. Basavaraja, S. Jayanti Fig. 4 Schematic of power cycle configuration for combined cycle CLC
Air Turbine
Compressor
Air Reactor
Exhaust Turbine
Fuel Reactor Air Recuperator 2 Recuperator 1
Fuel
Power Steam Turbine Cooled depleted air to atmosphere
Condenser CO2 + H2O
Air Exhaust (CO2 + H2O) Steam/water Pump
CO2 for sequestration Exhaust from fuel reactor
literature practice (Brandvoll and Bolland 2004; Naqvi 2006). The oxidation reaction is exothermic and produces net excess heat; however, this is not extracted through an in-bed heat exchanger as in the case of atmospheric CLC. Instead, the high temperature gas, composed of oxygendepleted nitrogen, is sent through an air turbine and is expanded to 1 bar. At this point, considerable amount of sensible heat is still present; this is partly used to heat the incoming air and partly to preheat the feedwater for the bottoming Rankine cycle and is finally let out through the chimney. The hot gases from the fuel reactor, consisting of CO2 and H2O at a pressure of 11.5 bar, are expanded through another turbine to 1 bar, are then sent through a heat recovery system used to generate steam for the bottom cycle as well as to preheat the fuel and are finally sent through a flue gas conditioner where the steam is condensed and separated. The nearly pure CO2 from the flue gas conditioner is then compressed to a pressure of 110 bar for transportation to the CO2 sequestration site. Thus, the principal differences between atmospheric CLC and pressurized CLC are in (a) the operating conditions of the air and the fuel reactors, (b) the way in which electrical power (primarily through gas turbines in pressurized CLC) is extracted and (c) the way heat is
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Water
distributed among the gas turbines, steam generation and preheating of the gaseous reactants. A schematic diagram of the pressurized CLC is shown in Fig. 4. Pressurized oxyfuel combustion This shares some similarities with pressurized CLC in the way in which thermal energy is converted to electrical power. However, on the furnace side, there are considerable differences. An air separation unit (ASU) is used to separate oxygen which is then compressed to a pressure of 13 bar and fed to the furnace where it burns directly with gaseous fuel in the presence of a moderating gas (Sivaji and Jayanti 2010) or recirculated exhaust gas (Seepana and Jayanti 2012) to produce a gaseous exhaust at a pressure of 13 bar and 1200 C. This is first sent to a gas turbine and then to a heat recovery system where it powers a Rankine cycle. It is finally sent through a flue gas conditioner where steam is condensed. The condensed water in the case of steam-moderated oxyfuel combustion or the enriched CO2 in the case of CO2-moderated oxyfuel combustion is compressed and fed to the furnace to moderate the gas temperature. The non-condensed gases from the flue gas conditioner, consisting mostly of CO2, are sent for
Comparative analysis of four gas-fired, carbon capture-enabled power plant layouts Fig. 5 Schematic diagram of an oxyfuel combined cycle power plant
SMOC
Combined cycle CO2 gas recycle based oxyfuel combustion
N2 ASU
Air
Fuel Combustor
O2
Combined cycle steam moderated oxyfuel combustion
Compressor Gas turbine CO2 rich gas Recycle
CO2 (80-93 %) for storage
HRSG Water pump Flue gas (CO2+H2O)
CO2 compression
Recycle water
compression to 110 bar for eventual sequestration. A schematic arrangement of an oxyfuel combustion based combined cycle power plant is given in Fig. 5. It can be seen that most of the components such as the ASU, high-pressure combustion, gas turbines and exhaust gas recirculation have large scale commercial units in operation. Thus, pressurized oxyfuel combustion can be considered as a mature technology unlike CLC where pilot plant scale setups of only 1 MWth with coal as fuel (*500 kW) are just being commissioned (Stro¨hle et al. 2014) and oxygen carrier development and reactor development are still in progress. In what follows, a detailed analysis of the power plant layout is described for the three configurations using mass and energy balances on the various units.
Results and discussion For comparative purposes, the thermal input for each power plant is assumed to be the same at 761 MWth, supplied in the form of fixed flow rate of natural gas, the molar composition of which is taken to be 89.51 % CH4, 5.92 % C2H6, 2.36 % C3H8, 0.40 % isobutene, 0.56 % nbutane, 0.13 % isopentane, 0.08 % n-pentane, 0.06 % C6H12, 0.28 % N2 and 0.70 CO2. In each case, a detailed thermodynamic analysis has been carried out on the furnace side as well as on the steam side using mass and energy balances on each major equipment such as the fuel reactor, the air reactor (the combustor in case of oxyfuel combustion), and the gas-preheaters and steam generators on the furnace side and various compressors, feed water
Steam turbine
Flue gas conditioner Water
heaters and steam/air/CO2-rich exhaust gas turbines which appear in the Rankine and Brayton cycles. The thermodynamic irreversibilities occurring during the thermal/mechanical energy to electrical energy conversion and vice versa in the turbines, compressors and pumps have been treated by assuming an isentropic efficiency as listed in Table 1, which also lists some other parameters associated with the calculations, namely, turbine inlet temperatures and pressure ratios and the Rankine steam cycle parameters, etc. The results from these calculations are discussed below. Layout of the atmospheric CLC power plant The layout of the atmospheric CLC power plant with natural gas firing is similar to that already reported by the present authors (Basavaraj and Jayanti 2015) for syngas of the same thermal input where details of the calculation procedure can also be found. Since the composition and calorific value of the two fuels are different, the values of the parameters, such as the operating temperatures, flow rates, etc., are different. In the present case, the air reactor and the fuel reactor operate at 1000 and 900 C, respectively. Air from the atmosphere is preheated to 550 C and is then fed into the air reactor where it reacts with the oxygen carrier (containing 51.96 % by weight of Ni, 45.67 % of NiAl2O4 as support and 2.37 % of NiO) to form the metal oxide which is then fed back to the fuel reactor for reduction. The heat released by the exothermic reaction in the air reactor is 873.88 MW. The metal oxide stream carries away 471.12 MW, while the metal stream from the fuel reactor brings in 421.39 MW. The oxygen-depleted air
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R. J. Basavaraja, S. Jayanti Table 1 Major assumptions for power plant design
Component/system
Value with unit
Ambient conditions: pressure, temperature
1.013 bar/30 C
Isentropic efficiency of water pump
75 %
Isentropic efficiency of compressor
85 %
Isentropic efficiency of gas turbines
92 %
Isentropic efficiency of steam turbines
90 %
Turbine inlet temperature
*1200 C
Turbine inlet pressure for the exhaust from the air reactor
13 bar
Turbine inlet pressure for the exhaust from the fuel reactor
11.5 bar
Turbine inlet pressure for the oxyfuel combustor
13 bar
Steam cycles Pressure and temperature for the atmospheric CLC plant
HP: 240 bar/600 C MP: 55 bar/600 C LP: 14 bar/600 C
Pressure and temperature for the pressurized CLC plant
HP: 150 bar/450 C MP: 20 bar/470 C LP: 1.7 bar/190 C
Pressure and temperature for the pressurized oxyfuel plant
HP: 110 bar/450 C MP: 20 bar/470 C LP: 1.7 bar/180 C
Condenser pressure
0.069 bar
CO2 capture: pressure, temperature
110 bar/35 C
from the air reactor gives up part of its 227.85 MW of thermal energy to preheat air from 30 to 550 C. The exhaust gas from the fuel reactor gives up part of its 96.94 MW of thermal energy to preheat natural gas from 30 to 500 C. With these heat exchanges, there is 605.10 MW of thermal energy for steam generation to drive the steam turbine. The remaining thermal energy from the exhaust streams of the two preheaters is also available for utilization on the steam side and these serve as economizers in the sense that they provide the heat required to preheat the boiler feed water. The heat generation and utilization in the atmospheric CLC power plant are summarized in Fig. 6. The steam side of the power plant is made to mimic the Rankine cycle-based supercritical steam cycle (operating at 240 bar/600/600/600 C (El-Wakil 2010) of a conventional boiler in terms of operating temperatures and pressures. The high-pressure steam for the boiler is expanded in three turbines with two reheats down to a pressure of 0.069 bar and a temperature of 39 C. The steam is condensed and the condensate is pumped back to the boiler via two boiler feed water heaters, the first one heated by exhaust gases from the fuel reactor and later by the exhaust gas (oxygen-depleted air) from the air reactor. The exhaust from the air reactor is finally let out into the chimney. The exhaust gas stream from the fuel reactor exits the condensate (boiler feed water) heater at 128 C after which it goes through a flue gas conditioner where the steam is condensed. Nearly pure CO2 stream from the flue
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gas conditioner is compressed in a four-stage compressor unit to 110 bar and is sent for storage. Layout of the pressurized CLC power plant The power extraction system for the pressurized CLC plant is significantly different from that of the atmospheric CLC plant and is shown schematically in Fig. 4. It consists of an air compressor, two combustors (the air and the fuel reactors), three turbines and several heat exchangers in the form of recuperators (gas-to-gas heat exchangers) and heat recovery steam generators (HRSG). For heat balancing on the furnace side, five subsystems have been considered. These are the air reactor (operating at 13 bar and 1200 C), the fuel reactor (operating at the lower pressure of 11.6 bar due to higher pressure losses in the bubbling fluidized bed and at a temperature of 1150 C fixed so that the metal oxide brings in the heat required for the endothermic reduction reaction in the fuel reactor), the air and the fuel preheaters and coolant air flow. Mass and energy (heat) balances have been made for a natural gas-fuelled combined cycle CLC system of 761 MWth fuel input; the resulting heat and mass flow rates into these subsystems are shown in Fig. 7. Compressed air (13.5 bar at 177 C) is divided into two streams; a coolant air stream (7.2 % by weight of the total flow rate) which is used to cool the air turbine (bringing the effective turbine inlet temperature to 1132 C) and a process air stream which is preheated to
Comparative analysis of four gas-fired, carbon capture-enabled power plant layouts Fig. 6 Furnace side mass and energy balances for a 761 MWth atmospheric CLC power plant
Depleted Air [N2 = 207 kg/s; O2 = 3 kg/s] Q = 227.85 MW Temperature (°C) = 1000 Depleted air flow rate (kg/s) = 210
Exhaust [CO2 = 41.1 kg/s; H2O = 34 kg/s Q = 96.94 MW Temperature (°C) = 900 Exhaust gas flow rate (kg/s) = 75.1
MeOx : oxidised state QMeO= 471.12 MW Temperature (°C) = 1000 MeO flow rate (kg/s) = 481.08 60 % NiO 40 % NiAl2O4
Air reactor
Fuel Reactor
T = 1000°C QOx = 873.88 MW
Q Extract = 605.10 MW
H = -ve
T = 900°C QRed = 113.12 MW H = +ve
MeOx-1 : reduced state QMe = 282.41 MW Preheated Air T = 550°C Q = 147.78 MW
Temperature (°C) = 900 Reduced carrier flow rate (kg/s) = 421.39 51.96 % Ni 45.67 % NiAl2O4 02.37 % NiO
Preheated Fuel T = 500°C Q = 21.35 MW
Fuel-preheater
Air-preheater Q = 75.60 MW Temperature (°C) = 730 Exhaust gas flow rate (kg/s) = 75.1 Air Temperature (°C) = 30 Air flow rate (kg/s) = 270 Depleted Air Q = 80 MW Temperature (°C) = 390 Depleted air flow rate (kg/s) = 210
420 C in the recuperator and fed to the air reactor where oxygen selectively reacts with the reduced metal stream to form the metal oxide stream. In the fuel reactor, 80 % of NiO is assumed to be converted to Ni, giving an excess oxygen concentration of 25 %. On the air side, 68.3 % excess air is required to maintain the air reactor exit temperature at 1200 C. The gas turbine details are shown in the energy balance. Due primarily to the smaller specific heat capacity ratio of 1.226 for the fuel reactor exhaust compared to 1.345 for the nitrogen-rich exhaust from the air reactor (see also Wolf 2004; Naqvi 2006), the fuel reactor exhaust expands to the relatively high temperature of 666 C compared to 497 C for the air turbine. These exhaust gases are then sent through their respective
Natural gas Temperature (°C) = 30 Fuel flow rate (kg/s) = 15.47
recuperators for preheating the reactant gases and are finally available at 463 and 241 C, respectively, for lowpressure steam generation. While the fuel reactor exhaust is finally sent through a flue gas conditioner for steam separation and then for compression to 110 bar, the air reactor exhaust is sent to the chimney. Layout of the pressurized oxyfuel power plant For the sake of comparison, the turbine inlet pressure in the case of pressurized oxyfuel combustion is taken to be 13 bar. Excess O2 of 7 % is used for combustion of the fuel, and the recycle exhaust gas flow rate is fixed such that the combustor exit temperature is 1258 C. When mixed
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R. J. Basavaraja, S. Jayanti Depleted Air [N2 = 623 kg/s; O2 = 128.99 kg/s] Q = 985.18 MW Temperature (°C) = 1200 Pressure (bar) = 13 Depleted air flow rate (kg/s) = 751.99 MeOx: oxidised state QMeO= 719.25 MW
Coolant air Air turbine exit Q = 398.43 MW Mass flow (kg/s) = 810.43 Temperature (°C) = 497 Pressure (bar) = 1
Air Reactor
Temperature (°C) = 1200 Flow rate (kg/s) = 580.52 60 % NiO 40 % NiAl2O4
Coolant air Q = 8.73 MW Temperature (°C) = 177 Pressure (bar) = 13.5 Air flow rate (kg/s) = 58.44
Fuel Reactor
H = +ve
H = -ve
Depleted air Air-preheater Q= 175.82 MW Temperature (°C) = 241 Depleted air flow rate (kg/s) = 810.43
Exhaust turbine exit Q = 67.56 MW Temperature (°C) = 666 Pressure (bar) = 1
QRed = 112.88 MW
QOx = 873.88 MW
Preheated Air Q = 328.54 MW T = 420 °C
Exhaust [CO2 = 41.1 kg/s; H2O = 34 kg/s] Q = 129.23 MW Temperature (°C) = 1150 Pressure (bar) = 11.6 Exhaust gas flow rate (kg/s) = 75.1
MeOx-1: Reduced state QMe = 502.00 MW Temperature (°C) = 1150 Flow rate (kg/s) = 520.83 44.58 % Ni 42.04 % NiAl2O4 13.38 % NiO Fuel-preheater Compressed air Q = 121.24 MW Temperature (°C) = 177 Pressure (bar) = 13.5 Air flow rate (kg/s) = 811.68
Preheated Fuel T = 555 °C Q = 24.86 MW
Exhaust Q = 42.67 MW Temperature (°C) = 463 Exhaust gas flow rate (kg/s) = 75.1 Natural gas (pressurised) Temperature (°C) = 30 Fuel flow rate (kg/s) = 15.47 Pressure (bar) = 13
Air Temperature (°C) = 30 Pressure (bar) = 1 Air flow rate (kg/s) = 870.12
Fig. 7 Energy balance for 761 MWth Natural gas-fired combined cycle CLC
with turbine coolant (12 % of the recycle flow rate), the turbine inlet temperature is 1168 C. After expansion in the gas turbine to atmospheric pressure, the CO2-rich flue gases with a specific heat ratio of 1.206 cool down to 688 C. The heat from the flue gases is recovered by heat recovery steam generators. The gas exiting the HRSG is further cooled in a condenser where the condensate is separated and 91.7 % of the dry flue gas is recirculated to the combustor; the rest, containing 83.5 % by mass of CO2, 8.49 % O2, 6.79 % Ar and 1.22 % N2, is then compressed to 110 bar and sent for sequestration/storage. The relatively low concentration of CO2 (of 83.5 %) is due to the use of 7 % excess O2 with only 95 % purity. It can be increased to 90 % by using 2–3 % excess oxygen of 98–99 % purity. The steam cycle operates at a high-pressure turbine inlet condition of 110 bar/450 C followed by two reheats, one at 20 bar/325 C and the other at 1.7 bar/180 C. The exit stream from the medium pressure turbine is reheated and then expanded to 0.069 bar at 39 C in the low-pressure turbine. For pressurized oxyfuel combustion, the recycle exhaust gas and oxygen need to be compressed to 13 bar to
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be fed to the combustor. While the compression of oxygen is inevitable, the compression of recycle exhaust gas can be avoided by using steam-moderated oxyfuel combustion (SMOC) in which steam, rather than CO2-rich exhaust gas, is used to moderate the flame temperature. In this case, the condensate water from the flue gas conditioner is pumped back to the combustor through heat exchangers where it gets converted to steam into the combustor. The flow rate of recirculated water is determined by fixing the steam at combustor inlet to be at a pressure of 20 bar and at a temperature of 300 C and fixing the combustor exit gas temperature to be 1200 C at a pressure of 13 bar. The composition of the flue gas at combustor exit is very different in this case and consists of 87.30 % by mass of H2O, 10.61 % of CO2, 1.08 % of O2, 0.85 % of Ar and 0.15 % of N2. It expands down to a pressure and temperature of 1 bar and 672 C in the gas turbine (at specific heat capacity ratio of 1.238). There are marginal changes in the turbine outputs (flue gas properties such as density and specific heat are different because the composition is different); however, the steam side parameters are the same.
Comparative analysis of four gas-fired, carbon capture-enabled power plant layouts Table 2 Overall energy analysis for natural gas-fired clean combustion plants Parameter
Oxyfuel power plant
CLC power plant
Variants
CC CO2 recycle
CC SMOC
Atmospheric
Gas turbine inlet temperature (C) at 13 bar
1168
1200
–
Pressurized AR: 1132 FR: 1150
Gas turbine exit temperature (C) at pressure 1 bar
688
672
–
AR: 497
Gas composition (wt%) in the turbine
H2O: 5.99
H2O: 87.30
–
Air reactor:
CO2: 78.50 O2: 7.98
CO2: 10.61 O2: 1.08
Ar: 6.38
Ar: 0.86
H2O: 45.32
N2: 1.15
N2: 0.15
CO2: 54.68
83.5
83.5
[99 %
[99 %
Gas turbine (kWe)
385,175
398,280
–
AR: 596,064
Steam turbine (kWe)
54,073
45,723
347,805
27,976
ASU: 51,892
ASU: 51,892
–
Air reactor: 275,716
O2: 18,989
O2: 18,989
FR: 666 N2: 82.85
CO2 purity (wt%) for CCS
O2: 17.15 Fuel reactor:
Power produced FR: 61,674 Compression and pumping cost Gas compression (kWe)
CO2: 114,065 CO2 compression to 110 bar (kWe)
18,613
18,613
14,721
14,721
Water circulation (kWe)
304
98
4993
10
Available power
(1–110 bar) 235,385
(1–20 bar) 354,411
(1–243.1 bar) 328,092
(1–1.7 bar) 395,267
Thermal input (kWe)
761,000
761,000
761,000
761,000
Net efficiency (%)
30.93
46.57
43.11
51.94
Comparative analysis The comparative analysis of the four power plant layouts is focussed on three issues: (i) the energy penalty incurred in CO2 capture, (ii) the maturity of technology and (iii) the future-readiness of the layout. These aspects are discussed below. Energy penalty for CO2 capture Mass and energy balances of the various layouts enable a direct comparison of these in terms of where power is generated and where it is lost. This comparison is summarized in Table 2 where the power produced from steam or gas or air turbines is given for the four layouts. The turbine entry conditions, in terms of the gas composition, temperature and pressure, have been indicated for each case. Also shown in the table are the major power consuming equipments, such as for gas compression and liquid pumping, for which power is drawn from the turbine output and is therefore not available for external consumption.
Finally, the composition of the gas sent for storage/sequestration is also indicated. In order to allow direct comparison, all the four configurations have the same thermal input of 761 MWth in the form of natural gas (which is assumed to be available at the combustor inlet pressure of 13.3 bar for pressurized cycles), and all configurations are expected to deliver flue gas at 110 bar for sequestration. One can see from the table that the overall thermal efficiency varies widely. Compared to an atmospheric oxyfuel combustion efficiency of about 28 % (Jayanti et al. 2012), pressurized oxyfuel combustion with recirculation of the CO2-rich exhaust gas gives a marginally higher efficiency of 30.9 %. This low efficiency can be attributed to the high cost of compression of the exhaust gas for recirculation. When this is avoided using SMOC, the efficiency increases to about 46.5 %. Atmospheric CLC has an overall efficiency of 41.5 %; this can be improved to nearly 52 % for pressurized CLC, which is a significant improvement over pressurized oxyfuel combustion. Another noteworthy factor is the purity of the exhaust gas sent for
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R. J. Basavaraja, S. Jayanti
sequestration. The exhaust gas from CLC contains no impurities, and the concentration of CO2 is more than of 99 %. In comparison, the exhaust gas in the case of pressurized oxyfuel combustion has a CO2 content of only 83.5 % by weight. Another stage of further purification (using amines or adsorption) may be required to achieve high purities. The energy penalty associated with this is, however, not included in the present study. Maturity of technology Another important aspect of a future-ready power plant is the maturity of technology required for carbon capture. While there are no large scale power plants commercially in operation with CO2 capture, the state of readiness for the above power plants layouts is significantly different. Oxyfuel combustion has three new elements compared to an air combustion power plant; these are air separation for the production of oxygen, enhanced oxygen combustion and exhaust gas recirculation. From the mass and energy balances, one can see that for a 761 MWth natural gas-fired power plant, oxygen flow rate of 67.8 kg/s [5780 tonnes per day (t/d)] requires an air flow rate of 275.3 kg/s (23,785 t/d) through the air separation unit. ASUs of this capacity are already commercially in operation; for example, the website of Linde (www.linde-engineering.com/ internet.global.lindeengineering.global) quotes that a 30,000 t/d ASU was installed for a gas-to-liquid fuel production plant in Qatar in the year 2006. Similarly, Air Liquide Group claims a capability to produce oxygen up to 7000 t/d through their energy consumption-optimized air separation units (www.engineering-solutions.airliquide. com). Of the other two new elements, enhanced oxygen combustion is widely used in the glass industry and in other process industries where high temperatures are required (Baukal et al. 2013). Exhaust gas recirculation is also not a new concept and is used in gas turbines in the context of decreasing NOx (Wunning and Wunning 1997). Thus, the major elements of oxyfuel combustion have been demonstrated commercially in other contexts. A number of large scale oxyfuel combustion projects are in various stages of commissioning (Rackley 2010). In comparison, CLC can be at best considered as a developing technology. Large scale and long hours of operation have not yet been proved. The largest demonstration plant in operation is only of 1 MWth capacity (Stro¨hle et al. 2014) and the longest continuous operation is still only about 200 h. While fluidized bed operations are well-known, the lifetime of the oxygen carriers is still uncertain. Retaining catalytic activity and resistance to attrition and agglomeration during continuous operation apart from cost and large scale manufacture are factors related to oxygen carriers that are still being
123
studied. Reactor development for a circulating fluidized bed involving two separate but interconnected fluidized beds operating at different temperatures and requiring high throughput of the solid catalyst is an on-going activity. Future-readiness of the layout The lifetime of a thermal power plant is in excess of 50 years. While CCS is not mandatory right now, it is possible that it may become so in a decade or two. In this scenario, it is necessary to build power plants that are future-ready, i.e. which can be made to operate in a case where CCS becomes mandatory. Extensive retrofitting of the power plant to accommodate carbon capture may not be possible and should be avoided. From the future-compatibility point of view, a CLC-based power plant is clearly the superior design. CLC plants can work in either CCS mode or non-CCS mode with very little changes required to make the switch. No special efforts or equipment will be necessary to enable CO2 capture. If CCS is not needed, then the flue gas from the flue gas conditioner needs not be compressed and can be sent directly to the chimney. When CCS is required, then this flue gas can be diverted to a CO2 compressor. In the case of a power plant based on oxyfuel combustion, more extensive changes are required as an air separation unit is required for generating pure oxygen. While studies indicate that retrofitting of atmospheric air combustion coal-fired boilers can be retrofitted for working in oxyfuel mode, the case for pressurized oxyfuel combustion may be different because flue gas compression and recirculation are necessary. In the case of pressurized oxyfuel combustion, the flow rates and composition of the exhaust gas are significantly different from those under air combustion; this may warrant changes in the turbine and heat recovery systems.
Conclusion In the present study, a detailed analysis of four gas-fired power plant layouts with in-built carbon capture has been made. The following major conclusions can be drawn from this study: •
•
Pressurized oxyfuel combustion with CO2 recycle suffers from poor efficiency due to the amount of power consumed in compressing the recycle gas to the combustor pressure; much higher overall cycle efficiency can be obtained by avoiding this step by resorting to SMOC Between atmospheric and pressurized CLC, the latter gives significantly higher overall cycle efficiency even if a supercritical Rankine cycle is used in the former.
Comparative analysis of four gas-fired, carbon capture-enabled power plant layouts
•
•
Between pressurized oxyfuel and pressurized CLCbased combined cycle power plants, higher efficiency is obtained with the latter. Much of the power in these plants is produced by the air or gas turbines. The higher specific heat ratio of the gaseous mixture driving the turbine in the case of CLC enables more power extraction in the highly efficient process (compared to the bottoming Rankine cycle) compared with the oxyfuel case. The CO2-rich exhaust gas is almost pure in the case of CLC, while the CO2 content is only 83.5 % by weight in oxyfuel combustion. This, coupled with the fact that CLC-based plants need less retrofitting to accommodate CCS at a future date, makes them ‘‘future-ready’’ in the sense that they can readily accommodate CCS with only 2 % loss in overall thermal efficiency for CO2 capture.
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