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Comparison of IGCC (integrated gasification combined cycle) and CFB (circulating fluidized bed) cogeneration plants equipped with CO2 removal
Energy 58 (2013) 86e96
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Comparison of IGCC (integrated gasification combined cycle) and CFB (circulating fluidized bed) cogeneration plants equipped with CO2 removal Marcin Liszka, Tomasz Malik*, Micha1 Budnik, Andrzej Zie˛ bik Institute of Thermal Technology, Silesian University of Technology, 44-100 Gliwice, Konarskiego 22, Poland
a r t i c l e i n f o
a b s t r a c t
Article history: Received 24 August 2012 Received in revised form 2 March 2013 Accepted 7 May 2013 Available online 10 June 2013
The introduction of CO2 removal processes causes usually generation of waste heat. As the temperature of waste heat carriers is usually moderately high (ca. 100 C), there is a potential possibility for using them in district heating systems. The main goal of present paper is thus the energy and CO2 emission analysis of CHP (combined heat and power production) plants equipped with CO2 removal and utilizing waste heat generated within the plant. First case is dealing with the CFB (circulating fluidized bed) plant equipped with post-combustion chemical CO2 absorption. The second case is dealing with an IGCC (integrated gasification combined cycle) equipped with the pre-combustion CO2 removal by physical absorption. Both plants have been modeled on the Thermoflex software. The reference, CFB-based CHP plant without CO2 removal has also been modeled. The obtained results indicate that IGCC plant has better thermodynamic indicators than CFB-based unit. Moreover, the CO2 emission considering system interconnections within the electricity production network is negative for both plants equipped with CCS (carbon capture and storage). The highest exergy efficiency is achieved for the reference CFB plant. The decrease of exergy efficiency caused by CO2 capture and compression is ca. 8 percentage points, but in case of IGCC CHP plant the exergy efficiency is only 3 percentage points lower than for the reference system. Ó 2013 Elsevier Ltd. All rights reserved.
Keywords: IGCC CFB CHP CCS Waste heat
1. Introduction The CO2 removal processes integrated with coal-fired power units cause significant drop of energy efficiency and economic profitability of the overall power generation process. The decrease of power generation efficiency is externalized usually by increased amount of waste heat rejected to the environment. The waste heat coming from the CO2 removal and compression installations is often of moderate temperature (ca. 80e100 C), and therefore its utilization within the power cycle or for external purposes could be possible. On the other hand, the decrease of CO2 emission without its removal is also possible. The combined heat and power production (CHP) is a good example where the thermodynamic integration of processes leads inherently to higher effectiveness, fuel saving and therefore decrease of CO2 emission which has been many times discussed in the literature. In Ref. [1] is stated, that energy savings and CO2 reduction is possible thanks to combined production of
* Corresponding author. E-mail addresses: [email protected] (M. Liszka), [email protected], [email protected] (T. Malik), [email protected] (M. Budnik), [email protected] (A. Zie˛ bik). 0360-5442/$ e see front matter Ó 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.energy.2013.05.005
heat and power, however the amount of energy savings and CO2 reductions strongly depends on the performances of the CHP plants, especially efficiencies, number of running hours, as well as features of the reference system based on separate production of heat and power. The maximum chemical energy savings because of cogeneration, in case of modern technologies for separate production are ca. 20%. In accordance to [2], to meet ambitious CO2 reduction targets and to raise energy efficiency, the future structure of power generation in Europe has to be changed. It is expected to raise a share of CHP plants in power generation. Influence of legislative regulations on combined heat and power production and differences between using energy and exergy assessment are emphasized in Ref. [3]. It is seen, that legislative regulations in most of countries put different emphasis on power or heat production based on energy (not qualitative) calculus. Author of Ref. [3] compared different CHP plants using relative avoided irreversibility (RAI) factor, in order to find exergetic consequences of various legislations. Some, but not all, CHP cases analyzed in the paper are exergetically beneficial to separate generation. The proved and well-known positive thermodynamic consequences of the cogeneration process and the already mentioned features of the CO2 removal systems brought an idea for a “zero emission” CHP plant concept. Combining the availability of a
M. Liszka et al. / Energy 58 (2013) 86e96
Nomenclature AGR ASU E_ chfuel EUF DHX GT h ha HP HRSG IGCC LHV _ m
acid gas removal air separation unit chemical energy of coal, calculated on LHV basis, W energy utilization factor district heat exchanger gas turbine specific enthalpy, kJ/kg specific enthalpy at ambient parameters, kJ/kg high pressure heat recovery steam generation integrated gasification combined cycle lower heating value mass flow rate, kg/s
moderate-temperature waste heat at the CO2 removal facility with inherently high effectiveness of the coal-fired CHP plant, the idea for the CHP system equipped with CCS (carbon capture and storage) unit and utilizing waste energy for district heat production has been proposed and analyzed within the current paper. It was expected, that the high-level integration of power cycle with CO2 removal unit and district water heat exchangers will make possible the partial recovery of CCS energy expenses. Within the current paper two different CHP plants incorporating presented idea have been proposed and investigated. First is the steam unit equipped with back-pressure steam turbine, circulating fluidized-bed boiler and CO2 removal unit based on chemical absorption in monethanolamine. Second plant configuration is based on IGCC structure equipped with pre-combustion CO2 removal based on physical absorption in Selexol. The idea for rather small CHP units equipped with CO2 removal and waste heat recovery is relatively new. There are a lot of literature references for CHP systems (non CCS) based on CFB (circulating fluidized bed) boilers, as well as, for large coal-fired power units equipped with post-combustion CCS. The problem of waste heat recovery from the chemical CO2 absorption units is discussed e.g. in Refs. [4,5]. The utilization of low-grade heat for district heating purposes is analyzed in Ref. [6]. In case of IGCC CHP system, installations described in literature use mostly biomass. Experience gained in IGCC CHP plants based on biomass gasification may be however transferred into similar plants based on coal. Several IGCC CHP plants do exist, however usually biomass or wastes are gasified, there is no plant which uses hard coal as a main feedstock. The SVZ plant in Schwarze Pumpe is one of such installations where coal and municipal wastes mix is gasified in BGL (British Gas and Lurgi) gasifier [7]. Installation produces electricity and methanol. This installation was however unprofitable, which caused that in year 2007 has been closed [7]. Another example of IGCC CHP plant is installation in Varnamo in Sweden. This biomass-based unit reaches 6 MWe electric and 9 MWth thermal power, while the energy efficiency in cogeneration mode is 83% [8]. Plant in Varnamo was operating since 1996 till 2000 and then it was closed for the same reason as SVZ plant [8]. Plant which uses lignite as a main feedstock for IGCC has been built in Versova (Czech Republic) [9]. There are 26 Lurgi and 1 Siemens gasifier in operation. Electricity and liquid fuels are the main products of this installation, however hot flue gas is used for district heat production [9]. In all recognized IGGC CHP installations, district heat is produced conventionally, as for combined cycles e using flue gas from the heat recovery steam generator (HRSG) exhaust or steam turbine extraction.
MP NelN NelG Q_ dh
r s sa ST Ta WGSR B_ fuel B_ dh
zi
hB
87
medium pressure net electric power of the system, W gross electric power of the system, W district heat flow rate, W enthalpy of vaporization, kJ/kg specific entropy, kJ/kgK specific entropy at ambient parameters, kJ/kgK steam turbine ambient temperature, K water gas shift reactor chemical exergy of coal, W exergy of produced district heat, W molar share of i-th compound exergy efficiency
2. Case studies Two case studies of CCS-integrated CHP units have been analyzed: -
IGCC CHP plant with waste heat recovery equipped with Selexol-based CO2 absorption, CFB CHP plant with waste heat recovery equipped with tapbackpressure steam turbine and MEA-based CO2 absorption.
Both analyzed cases have been compared with the reference plant which is based on CFB boiler and steam cycle of the same main parameters. The CCS installation and waste heat recovery systems have been however eliminated form the reference plant. The idea is to evaluate both CCS technologies not from the point of view of themselves, but referring to the real, commonly used nonCCS technology based on the same fuel. The IGCC plants fed with coal are really occasionally used (if any) as CHP units because of high capital cost and structure complication compared to short annual time of rated capacity utilization. The typical, non-CCS CHP unit fed with coal is based on CFB boiler and is a real reference for investor decision. The IGCC plant becomes however much more interesting when the necessity of CCS occurs. That is the reason why the CFB-based plant is used as reference for both CCS-type processes. The typical, best available design and parameters have been assumed for the reference plant based on [10]. All the three simulated CHP plants have been scaled to the same, rated district heat production (110 MWt). For comparison purposes, the same fuel parameters have been used for analyzed systems. Fuel composition has been presented in Table 1. 2.1. IGCC plant IGCC plants are usually designed as electricity or chemicals production facilities, however they have a high potential for district Table 1 Fuel composition. Coal parameters (as received) C, carbon H, hydrogen O, oxygen N, nitrogen S, sulfur Moisture Ash LHV
e e e e e e e MJ/kg
0.5263 0.0343 0.1102 0.0075 0.0104 0.2237 0.0876 20.16
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heat production. Present IGCC concepts (especially with CO2 capture) give an opportunity for recovering waste heat at levels suitable for district heat production, as well as for using classical heat sources e.g. tap-steam turbine or outlet of HRSG. Proposed IGCC CHP plant configuration is schematically presented in Fig. 1. The system is based on that presented in Ref. [11] which has been optimized and redesigned towards IGCC CHP plant. It is composed of cryogenic air separation unit (ASU), dryfeed gasifier with syngas cooler, water gas shift reactors (WGSR), acid gas removal (AGR) unit and finally the combined cycle. The entrained flow dry-feed gasifier has been chosen for syngas production. Such a selection seems to be optimal for analyzed IGCC and fuel. Such a selection has also been considered within other published studies [12,13]. The gasifier operating pressure has been set to 4.24 MPa. The temperature of the syngas leaving the reactor reaches 1639 C. The syngas is cooled down primarily by its partial recirculation and then by the production of high pressure steam in a radiant/convection heat exchanger. The temperature of the syngas leaving the cooler and entering the scrubber is equal to 335 C. The gasification reactor consumes oxygen of 95% purity. The coal feeding system is based on ASU nitrogen. The syngas treating and conditioning line is composed of an inter-cooled WGSR reactor which is supplied with MP steam taken from MP steam collector in order to keep proper H2O to CO ratio within each stage of the reactor. The syngas temperature after the first WGSR reactor has been assumed to 460 C while behind the second one to 360 C. The heat rejected from the syngas during the conditioning processes is recovered to the steam cycle as HP, MP and LP steam and for district heat production. The AGR unit is based on a twostage Selexol process. The syngas stream leaving the second WGSR is cooled down, dehydrated and supplied to the first stage of
AGR unit, where 99% of H2S is stripped. Heat for solvent regeneration in stripper column is provided by low pressure steam from HRSG. The separated H2S is then sent to the Claus plant for conversion to elemental sulfur. The H2S-free gas is supplied to the second stage of AGR where it is brought in contact with a lowtemperature lean Selexol solvent for CO2 absorption. The reverse CO2 desorption process occurs in flash drums operating on 3 different pressure steps. Desorbed CO2 is compressed and pumped into the transportation pipeline. The hydrogen-rich (ca. 90%) syngas leaving the AGR is diluted by ASU nitrogen, preheated by VLP steam and used as a gas turbine (GT) fuel. An F-class GT has been selected. As already mentioned, the steam turbine receives steam from both the triple-pressure HRSG and syngas cooling equipment. All compressors within the ASU and AGR islands have been assumed as electric motor e driven machines. Table 2 summarizes the assumptions/specifications concerning the input/output for the system. Waste heat recovery concept involves the final flue gas cooler located in the HRSG, syngas cooler in syngas treating and conditioning line prior to AGR unit, as well as, intercoolers in compression trains of ASU air, nitrogen and CO2 product. All waste heat recovery exchangers are marked in red boxes (in web version) in Fig. 1. For further transportation, the CO2 stream is compressed to 13 MPa. 2.2. CFB plant For the current moment, one of the closest to commercial application method for CO2 capture in classic coal-fed CHP units is post-combustion absorption using MEA or similar solvent. The main energy requirement for this type of process is heat demand
Fig. 1. Concept of IGCC CHP plant.
M. Liszka et al. / Energy 58 (2013) 86e96 Table 2 Assumed parameters for IGCC CHP plant [14e16]. Parameter Pressure in the reactor Temperature of syngas at scrubber outlet Nitrogen to fuel ratio (for fuel transportation), mass basis Steam to fuel ratio, mass basis Oxygen to fuel ratio, mass basis Specific electricity consumption Syngas treating and conditioning line CO conversion ratio at 1st WGSR CO conversion ratio at 2nd WGSR H2O to CO ratio at 1st WGSR H2O to CO ratio at 2nd WGSR Syngas temperature prior to AGR Acid gas removal and CO2 compression Effectiveness of H2S removal Effectiveness of CO2 removal Process steam consumption CO2 capture miscellaneous auxiliary load Gas turbine Combustor exit temperature Compressor pressure ratio Steam cycle Live (HP) steam temperature Live (HP) steam pressure MP steam pressure
IGCC CHP plant MPa OC e
4.24 180 0.175
e e kWh/Mgfuel
0.005 0.66 67
% % e e OC
63.6 86.2 2.34 4 35
% % kg/s kWh/MgCO2
99 90 1.81 60
OC e
1300 15.5
OC MPa MPa
565 12.8 3.95
for desorption of CO2 from the amine solution, which is also stated in Ref. [4]. Proposed CHP plant with CO2 capture system is equipped with CFB boiler, tap-backpressure steam turbine and CO2 capture unit e Fig. 2. CFB boiler produces live steam which has typical parameters for modern CFB boilers installed recently in Poland for CHP mode of operation (560 C, 16.1 MPa). Boiler is equipped with economizer, evaporator, as well as, convective and radiant superheaters. Steam expands in tap-backpressure steam turbine. Steam cycle is equipped with four heat recovery exchangers. The heat necessary for the CO2
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removal unit is taken from the steam turbine exhaust as a backpressure steam. The rest of steam flow available at the turbine outlet is supplied to the district water heater which operates in parallel with other heaters utilizing waste heat from the CO2 absorption and compression unitsedistrict water is preheated basically in CO2 dehumidifier and CO2 compression train (inter-coolers). Hot flue gas leaving the economiser is primarily cooled down in rotary heat exchanger, where combustion air is preheated. Then in electrostatic precipitator fly ash is removed and finally prior to CO2 absorption process, flue gas is cooled down to 40 C and desulphurized for final required SO2 concentration (10 ppmv). Absorption unit is composed of absorber and stripper columns. In absorber column flue gas is brought in contact with MEA solvent, rich solvent is then injected into a stripper column where its regeneration occurs and CO2 is separated. For further transportation, the CO2 stream is compressed to 13 MPa. For comparison purposes, the typical CFB-based CHP plant without CCS has also been studied. The district heat production within the non-CCS CFB CHP plant takes place in two heat exchangers connected to steam turbine outlet (base load) and extraction (peak-load). The structure and thermal parameters within the boiler island and steam cycle are the same expecting the steam turbine outlet, where steam pressure is lower than for the CCS case, as the required temperature for district heat exchanger is lower than for CO2 desorption process. Crucial parameters of both considered CFB CHP plants have been presented in Table 3. 3. Assessment factors For the comparison purposes, each of three analyzed units (IGCC with CCS, CFB with CCS and CFB reference e without CCS) has been evaluated from the energy, exergy and CO2 emission points of view. Energy utilization factor has been calculated as defined in (1), representing the proportions of energy balance rather than a true thermodynamic assessment.
Fig. 2. Concept of CFB CHP plant.
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M. Liszka et al. / Energy 58 (2013) 86e96
Table 3 Assumed parameters for CHP plants with CFB boiler. Parameter
CHP plant without CO2 capture
CHP plant with CO2 capture
MPa C %
Natural circulation 16.1 560 91
Natural circulation 16.1 560 91
%
85
85
130
130
C C % MPa
260 850 20 0.084
260 850 20 0.24
kJ
e
4000
%
e
90
Unit
Boiler type Live steam pressure Live steam temperature Dry step efficiency of steam turbine (HP, MP) Dry step efficiency of steam turbine (LP) Temperature of flue gases behind rotary air heater Temperature of preheated air Furnace exit temperature Excess air ratio Steam pressure at steam turbine exhaust Heat demand for the CO2 absorption unit (per 1 kg of CO2 removed) CO2 removal effectiveness
C
Q_ þ NelN EUF ¼ dh E_
Fig. 3. Scheme for calculus of avoided CO2 emission.
(1)
chfuel
Energy analysis does not take into account different quality of products. Exergy is a measure of energy quality or thermodynamic irreversibility related to the isolated devices or whole analyzed system [17e19]. Exergy analysis is suitable for the thermodynamic comparison of co-product or multi-product systems. The exergy efficiency of each analyzed CHP system has been calculated in accordance to (2).
hB ¼
-
(2) -
The exergy of produced heat is expressed by increase of exergy of district water as presented in (3) where subscript “II” characterizes hot water, while subscript “I” characterizes cold water.
_ dh ½hII hI Ta ðsII sI Þ B_ dh ¼ m
(3)
The CO2 emission factor which indicates the net CO2 emission per 1 GJ of produced heat has also been calculated in accordance with (4). Considering dual product situation (heat and electricity) it has been assumed that the main product is heat and the emission assigned to heat is calculated as difference between total emission from the analyzed CHP unit and emission avoided in other power stations due to production of specified amount of electricity in considered CHP unit. The scheme for avoided emission calculus has been illustrated in Fig. 3. The equivalent power plant is assumed to be coal-fired, nonCCS, supercritical unit of net electric efficiency equal to 44%.
_ CO2 _ CO2 m m _ Q
-
-
B_ dh þ NelN B_ fuel
ε ¼
Main assumptions taken for the simulation process for all considered systems are as follows:
avoid
(4)
dh
4. Simulation model All analyzed CHP systems have been modeled using the Thermoflex software [20]. Thermoflex contains models of typical energy conversion devices like compressors, turbines or heat exchangers, as well as, agglomerated multi-device models such as steam boiler or gasifier islands. The modeling approach combines the physical and empirical modeling. The flow sheets of analyzed IGCC, CFB and CFB reference systems used for simulation purposes are presented in Figs A.1eA.3 in Appendix A.
the same district heat power (ca. 110 MWth), the same parameters of district water 62.6 C/37 C (annual average), the same feedstock (hard coal), CO2 stream compressed to 13 MPa for both CO2 capture installations, the same temperature of cooling water at battery limits (20 C).
The calculated parameters in characteristic points of the analyzed systems are presented in Tables A.1eA.3 in Appendix A. 5. Results The crucial calculated parameters at system boundaries of each analyzed CHP unit have been presented in Table 4. For the same district heat production, the obtained net and gross electricity production is the highest for IGCC unit reaching 78.40 MW and 113.30 MW respectively. Such big difference between these values is caused by high electricity consumption within the system. Gross electricity production is almost the same for both CFB CHP plants, however in case of CFB CHP plant with CO2 capture, due to the higher auxiliary electricity consumption, net electricity production is lower and equals 50.80 MW, while for reference plant net electricity production is 60.10 MW. The CO2 emission for both plants equipped with CO2 capture is obviously lowein the range of ca. 2e 2.5 kg/s. Lack of energy consumption for the CO2 capture installation in case of reference CFB plant results in the highest value of energy utilization factor achieved which is 0.90. EUF factor for the IGCC CHP plant is 0.72 which is lower than for other systems as it does not take into account different quality of products. When comparing exergy efficiency, the highest value of 0.35 is still achieved for the reference CFB CHP plant (without CO2 capture). The decrease of exergy efficiency caused by CO2 capture and compression in case of CFB CHP plant is ca. 8 percentage points, but in case of IGCC CHP plant the exergy efficiency plant is only 3 points lower than for the reference system. Such a low difference is caused by positive effect of higher electricity to district heat ratio.
M. Liszka et al. / Energy 58 (2013) 86e96 Table 4 Results of simulation analysis. Parameter
Unit
IGCC CHP CFB CHP plant CFB CHP plant with plant with without CO2 CO2 capture CO2 capture capture (reference)
Total district heat production Including: Waste heat Steam-fed heat exchangers Fuel flow rate Fuel chemical energy (LHV-based) Gross electricity production Net electricity production Electric power consumption for CO2 compressors CO2 emission from CHP plant (total) CO2 mass flow rate for transportation (captured) EUF (Eq. (1)) Fuel exergy input District water exergy increase (Eq. (3)) Exergy efficiency (Eq. (2)) CO2 emission factor per GJ of produced district heat (Eq. (4))
MWth
110.22
110.26
110.14
MWth MWth
0 110.22
53.24 57.02
29.22 80.92
kg/s MW
9.34 188.29
10.40 209.66
13.02 262.48
MWe
64.70
64.10
113.30
MWe
60.10
50.80
78.40
MW
e
6.10
7.00
91
is thus equal to 0.0174%. The total mass flow rate entering the system is 1732.70 kg/s, while the total mass flow rate leaving the system is 1732.70 kg/s which means that there is no cycle mass balance error. In CFB CHP plant with CO2 capture simulation model total energy input is 5328407.00 kW, while total energy output is 5328333.00 kW which means 74.00 kW cycle heat balance error. The relative error is thus equal to 0.0014%. Total mass flow rate entering the system is 2384.90 kg/s, while the total mass flow rate leaving the system is 2384.80 kg/s which means 0.10 kg/s cycle mass balance error. In CFB CHP plant without CO2 capture simulation model total energy input is 2271799.00 kW, while total energy output is 2271792.00 kW which means 7.00 kW cycle heat balance error. The relative error is thus equal to 0.0003%. Total mass flow rate entering the system is 1126.80 kg/s, while the total mass flow rate leaving the system is 1126.80 kg/s which means that there is no cycle mass balance error. All the calculated errors are expected to be caused primarily by round-off and convergence method errors. 7. Concluding remarks
kg/s
18.46
2.06
2.52
kg/s
e
18.49
22.20
% MW MW
0.90 205.24 10.36
0.77 228.53 10.36
0.72 286.11 10.36
e
0.35
0.27
0.32
81.59
131.95
kgCO2/GJt 48.86
The CO2 emission factor calculated in accordance with (4) is below zero for both cases with CO2 capture due to effect of coupling of CO2 capture and cogeneration processes. Better values have been obtained for IGCC CHP plant. Values of emission factor have been achieved for assumed net electric efficiency of equivalent power station equal to 44%. For better recognition of the impact of equivalent plant efficiency on CO2 emission, the sensitivity analysis has been prepared as presented in Fig. 4.
6. Error analysis Error analysis has been prepared separately for each simulation model. In IGCC CHP plant simulation model total energy input is 3456375.00 kW, while total energy output is 3455773.00 kW which means 602.40 kW cycle heat balance error. The relative error
Two configurations of coal-fed CHP plants with massive CO2 removal and waste heat recovery systems have been proposed and analyzed assuming constant district heat demand. Obtained results of exergy analysis indicate, that the drop of efficiency due to CO2 removal and compression (ca. 8% points for CFB CHP) is lower than for large-scale coal-fired power units (ca. 10e12% points) for similar CCS heat demand as reported in Refs. [21,22]. The reason is that the waste heat recovery lets for partial cancellation of negative impact of CCS on overall plant efficiency. An IGCC CHP unit with CO2 capture has significantly better emission factors and thermodynamic excellence when comparing to CHP plant with CFB boiler and post-combustion CO2 capture process. Advantages of IGCC CHP unit are mainly due to commonly known effect of Brayton and Rankine cycles integration, as well as, due to advantage of pre-combustion CO2 removal over postcombustion system (referring to assumed in this paper energy demands for both installations). Negative value of CO2 emission factor which arises from applied CO2 removal processes and substituting of electricity produced in other power stations (system advantage of cogeneration), enables potentially for substituting emission from power facilities, where decreasing emission is economically ineffective or impossible (e.g. peak-load boilers). Future work should be focused on off-design analysis of both proposed CHP systems to evaluate change of supply of waste heat as function of variable ambient temperature and district heat demand. The comparative economic analysis reflecting the costs of district heat production, as well as, costs of avoiding the CO2 emission should also be done. Acknowledgments
Fig. 4. Sensitivity analysis of equivalent power station efficiency on CHP emission factor.
This work has been prepared in framework of the task of research, “Development of coal gasification technology for high efficient production of fuels and electricity” funded by the Polish National Centre for Research and Development within the strategic program of research and development: "Advanced energy generation technologies". The results presented in this paper were obtained also from research work financed by the National Centre of Research and Development in the framework of Contract SP/E/1/67484/10 e Strategic Research Program e Advanced technologies for energy generation: Development of a technology for highly efficient zeroemission coal-fired power units integrated with CO2 capture.
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Appendix A
M. Liszka et al. / Energy 58 (2013) 86e96
Fig A.1. Simulation model of IGCC CHP plant with waste heat recovery (Thermoflex).
M. Liszka et al. / Energy 58 (2013) 86e96 93
Fig. A.2. Simulation model of CFB CHP plant with CO2 capture (Thermoflex): a) boiler and power cycle, b) CO2 capture and compression installation.
94 M. Liszka et al. / Energy 58 (2013) 86e96
Fig. A.3. Simulation model of CFB CHP plant, without CO2 capture (Thermoflex).
M. Liszka et al. / Energy 58 (2013) 86e96
95
Table A.1 Calculated parameters at selected points of the plant structure for IGCC CHP case. (Point numbers correspond to those in Fig. A.1). Water/steam Stream number
T, C
p, bar
m, kg/s
Quality
154 152 101 123 67 126 127 160
565 565 321.92 211.96 72.53 122.8 125.38 122.06
128 39.5 8 3 0,3478 43.16 154.06 11.22
40.26 35.02 39.93 35.67 35.67 8.52 40.34 4.92
Superheated 235.4 C Superheated 315.4 C Superheated 151.5 C Superheated 78.4 C 0.9703 Sub cooled 132.1 C Sub cooled 218.9 C Sub cooled 62.9 C
Syngas Stream number
T, C
41 47 204 20 219 29 1 201
600 179.88 220 358.39 149.61 58.9 27.22 143.73
p, bar
m, kg/s
H2
CO2
CO
N2
H2O
H2S
COS
Ar
Other
47.80 42.44 42.44 1.37 1.37 1.83 3.02 1.91
8.18 7.26 7.26 4.67 4.67 6.23 10.29 42.59
15.2 24.73 24.73 25.68 25.68 0.66 0.042 0.03
0.38 0.33 0.33 0.23 0.23 0.31 0.0005 0.0003
0.031 0.0275 0.0275 0.0004 0.0004 0.0005 0.0008 0.0275
0.03 0.02 0.02 0.01 0.01 0.02 0.03 0.03
0.009 0.0025 0.0025 0.0096 0.0096 0.0095 0.0067 0.7822
Mole fractions 41.17 40.44 38.89 35.06 30.24 28.79 27.03 26.5
22.74 24.44 24.44 35.82 35.82 27.79 5.12 17.33
21.73 19.29 19.29 38.31 38.31 51.21 84.5 53.3
6.64 5.9 5.9 29.72 29.72 39.73 2.11 1.33
Table A.2 Calculated parameters at selected points of the plant structure for CHP plant with CO2 capture case. (Point numbers correspond to those in Fig. A.2a and b). Water/steam Stream number
T, C
p, bar
m, kg/s
Quality
16 20 31 32 1 29 33 17 15 255 256 257 247 248
560 344.8 287.1 194.6 158.8 126.1 126.1 245 470 37 37 37 49.35 62.6
161 39.8 25.3 10.9 6 2.4 2.4 172.6 162.6 20 20 20 20 20
81.14 76.54 71.59 63.32 61.19 35.99 25.09 81.34 81.14 1030 42.3 987.7 1030 1030
Superheated 212.1 C Superheated 94.8 C Superheated 62.6 C Superheated 10.9 C 0.977 0.936 0.936 Sub cooled 108.5 C Superheated 121.3 C Sub cooled 175.4 C Sub cooled 175.4 C Sub cooled 175.4 C Sub cooled 163 C Sub cooled 149.8 C
Flue gas Stream number
T, C
37 38 40 44 167 218
850 323.13 130.3 130.3 35 30
p, bar
m, kg/s
mash, kg/s
CO2
N2
H2O
SO2
Ar
O2
71.11 71.11 71.34 71.34 87.68 0
10.40 10.40 10.06 10.06 4.88 0.03
0.007 0.007 0.007 0.007 0 0
0.86 0.86 0.86 0.86 1.06 0
3.18 3.18 3.8 3.8 4.67 0
Mole fractions 1.0427 1.0353 1.0328 1.0132 1.0132 130
95.41 95.41 98.83 98.83 76.65 18.49
1.241 1.241 1.241 0.002 0 0
14.44 14.44 13.93 13.93 1.71 99.97
Table A.3 Calculated parameters at selected points of the plant structure for reference CHP plant without CO2 capture case. (Point numbers correspond to those in Fig. A.3) Water/steam Stream number
T, C
p, bar
m, kg/s
Quality
16 20 32 33 24 31 29 41 17 15
560 344.8 287.1 194.6 158.8 105.6 95 105.6 245 470
161 39.8 25.3 10.9 6 1.2 0.85 1.2 172.6 162.6
72.7 68.6 64.2 60.5 53.9 53.7 53.7 0.2 72.9 72.7
Superheated 212.1 C Superheated 94.8 C Superheated 62.6 C Superheated 10.9 C 0.977 0.913 0.901 0.913 Sub cooled 108.5 C Superheated 121.3 C (continued on next page)
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M. Liszka et al. / Energy 58 (2013) 86e96
Table A.3 (continued) Flue gas Stream number
T, C
p, bar
m, kg/s
mash, kg/s
CO2
5 8 66 18
850 329 130 130
1.0378 1.0303 1.0228 1.0132
85.73 85.73 94.97 94.97
1.134 1.134 1.134 0.002
14.44 14.44 13.01 13.01
N2
H2O
SO2
Ar
O2
71.1 71.1 71.71 71.71
10.41 10.41 9.49 9.49
0.007 0.007 0.007 0.007
0.86 0.86 0.86 0.86
3.18 3.18 4.92 4.92
Mole fractions
References [1] Martens A. The energetic feasibility of CHP compared to the separate production of heat and power. Applied Thermal Engineering 1998;18: 935e46. [2] Westner G, Madlener R. Development of cogeneration in Germany: a meanvariance portfolio analysis of individual technology’s prospects in view of the new regulatory framework. Energy 2011;36:5301e13. [3] Ertesvag IS. Exergetic comparison of efficiency indicators for combined heat and power (CHP). Energy 2007;32:2038e50. [4] Pfaff I, Oexmann J, Kather A. Optimised integration of post-combustion CO2 capture process in greenfield power plants. Energy 2010;35:4030e41. [5] Yu YS, Li Y, Li Q, Jiang J, Zhang ZX. An innovative process for simultaneous removal of CO2 and SO2 from flue gas of a power plant by energy integration. Energy Conversion and Management 2009;50:2885e92. [6] Kapil A, Bulatov I, Smith R, Kim Jin-Kuk. Process integration of low grade heat in process industry with district heating networks. Energy 2012;44:11e9. [7] Rakowski J. Overview of technical issues associated with the gasification of technologicznych solid fuels for energy production [Przegla˛ d zagadnien zwia˛ zanych ze zgazowaniem paliw sta1ych dla potrzeb energetycznych]. Energetyka 2003 September;9:591e601 [in Polish]. [8] Stahl K, Neergaard M. IGCC power plant for biomass utilisation, Värnamo, Sweden. Biomass and Bioenergy 1998;15(7):205e11. [9] Report from Vresova: 12 years of operating experience with the world’s largest coal-fuelled IGCC. (PLANT OPERATING EXPERIENCE). Available from: http://goliath.ecnext.com/coms2/gi_0199-9669125/Report-from-Vresova-12years.html [accessed 01.10.08]. [10] RAFAKO S.A., ul. qa˛ kowa 33, 47e400 Racibórz, Poland. Available from:http:// www.rafako.com.pl [accessed 01.03.13]. [11] Liszka M, Malik T, Manfrida G. Energy and exergy analysis of hydrogenoriented coal gasification with CO2 capture. Energy 2012;45:142e50.
[12] Cormos CC. Integrated assessment of IGCC power generation technology with carbon capture and storage (CCS). Energy 2012;42:434e45. [13] Perez-Fortes M, Bojarski AD, Velo E, Nougues JM, Puigjaner L. Conceptual model and evaluation of generated power and emissions in an IGCC plant. Energy 2009;34:1721e32. [14] Erlach B, Schmidt M, Tsatsaronis G. Comparison of carbon capture IGCC with pre-combustion decarbonisation and with chemical-looping combustion. Energy 2011;36:3804e15. [15] Martelli E, Kreutz T, Carbo M, Consonni S, Jansen D. Shell coal IGCCS with carbon capture: conventional gas quench vs. innovative configurations. Applied Energy 2011;88:3978e89. [16] Chiesa P, Consonni S, Kreutz T, Williams R. Co-production of hydrogen, electricity and CO2 from coal with commercially ready technology. Part A: performance and emissions. International Journal of Hydrogen Energy 2005;30:747e67. [17] Szargut J. Exergy method. Technical and ecological applications. Southampton-Boston: WIT Press; 2005. [18] Uson S, Valero A. Thermoeconomic diagnosis of energy systems. Prensas Universitarias de Zaragoza; 2010. [19] Bejan A, Tsatsaronis G, Moran M. Thermal design & optimisation. New York: John Wiley & Sons; 1996. [20] Thermoflow, Inc., 29 Hudson Road, Sudbury, MA 01776 USA. Available from: http://www.thermoflow.com [accessed 01.03.13]. [21] Davison J. Performance and costs of power plants with capture and storage of CO2. Energy 2007;32:1163e76. [22] Liszka M, Zie˛ bik A. Thermoeconomic comparison of coal-based oxy-fuel and post-combustion CO2 captureecase study for Polish conditions. In: Proceedings of 25th annual international Pittsburgh coal conference; 2008 Sep 29eOct 2; Pittsburgh, PA, USA.
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Energy journal homepage: www.elsevier.com/locate/energy
Comparison of IGCC (integrated gasification combined cycle) and CFB (circulating fluidized bed) cogeneration plants equipped with CO2 removal Marcin Liszka, Tomasz Malik*, Micha1 Budnik, Andrzej Zie˛ bik Institute of Thermal Technology, Silesian University of Technology, 44-100 Gliwice, Konarskiego 22, Poland
a r t i c l e i n f o
a b s t r a c t
Article history: Received 24 August 2012 Received in revised form 2 March 2013 Accepted 7 May 2013 Available online 10 June 2013
The introduction of CO2 removal processes causes usually generation of waste heat. As the temperature of waste heat carriers is usually moderately high (ca. 100 C), there is a potential possibility for using them in district heating systems. The main goal of present paper is thus the energy and CO2 emission analysis of CHP (combined heat and power production) plants equipped with CO2 removal and utilizing waste heat generated within the plant. First case is dealing with the CFB (circulating fluidized bed) plant equipped with post-combustion chemical CO2 absorption. The second case is dealing with an IGCC (integrated gasification combined cycle) equipped with the pre-combustion CO2 removal by physical absorption. Both plants have been modeled on the Thermoflex software. The reference, CFB-based CHP plant without CO2 removal has also been modeled. The obtained results indicate that IGCC plant has better thermodynamic indicators than CFB-based unit. Moreover, the CO2 emission considering system interconnections within the electricity production network is negative for both plants equipped with CCS (carbon capture and storage). The highest exergy efficiency is achieved for the reference CFB plant. The decrease of exergy efficiency caused by CO2 capture and compression is ca. 8 percentage points, but in case of IGCC CHP plant the exergy efficiency is only 3 percentage points lower than for the reference system. Ó 2013 Elsevier Ltd. All rights reserved.
Keywords: IGCC CFB CHP CCS Waste heat
1. Introduction The CO2 removal processes integrated with coal-fired power units cause significant drop of energy efficiency and economic profitability of the overall power generation process. The decrease of power generation efficiency is externalized usually by increased amount of waste heat rejected to the environment. The waste heat coming from the CO2 removal and compression installations is often of moderate temperature (ca. 80e100 C), and therefore its utilization within the power cycle or for external purposes could be possible. On the other hand, the decrease of CO2 emission without its removal is also possible. The combined heat and power production (CHP) is a good example where the thermodynamic integration of processes leads inherently to higher effectiveness, fuel saving and therefore decrease of CO2 emission which has been many times discussed in the literature. In Ref. [1] is stated, that energy savings and CO2 reduction is possible thanks to combined production of
* Corresponding author. E-mail addresses: [email protected] (M. Liszka), [email protected], [email protected] (T. Malik), [email protected] (M. Budnik), [email protected] (A. Zie˛ bik). 0360-5442/$ e see front matter Ó 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.energy.2013.05.005
heat and power, however the amount of energy savings and CO2 reductions strongly depends on the performances of the CHP plants, especially efficiencies, number of running hours, as well as features of the reference system based on separate production of heat and power. The maximum chemical energy savings because of cogeneration, in case of modern technologies for separate production are ca. 20%. In accordance to [2], to meet ambitious CO2 reduction targets and to raise energy efficiency, the future structure of power generation in Europe has to be changed. It is expected to raise a share of CHP plants in power generation. Influence of legislative regulations on combined heat and power production and differences between using energy and exergy assessment are emphasized in Ref. [3]. It is seen, that legislative regulations in most of countries put different emphasis on power or heat production based on energy (not qualitative) calculus. Author of Ref. [3] compared different CHP plants using relative avoided irreversibility (RAI) factor, in order to find exergetic consequences of various legislations. Some, but not all, CHP cases analyzed in the paper are exergetically beneficial to separate generation. The proved and well-known positive thermodynamic consequences of the cogeneration process and the already mentioned features of the CO2 removal systems brought an idea for a “zero emission” CHP plant concept. Combining the availability of a
M. Liszka et al. / Energy 58 (2013) 86e96
Nomenclature AGR ASU E_ chfuel EUF DHX GT h ha HP HRSG IGCC LHV _ m
acid gas removal air separation unit chemical energy of coal, calculated on LHV basis, W energy utilization factor district heat exchanger gas turbine specific enthalpy, kJ/kg specific enthalpy at ambient parameters, kJ/kg high pressure heat recovery steam generation integrated gasification combined cycle lower heating value mass flow rate, kg/s
moderate-temperature waste heat at the CO2 removal facility with inherently high effectiveness of the coal-fired CHP plant, the idea for the CHP system equipped with CCS (carbon capture and storage) unit and utilizing waste energy for district heat production has been proposed and analyzed within the current paper. It was expected, that the high-level integration of power cycle with CO2 removal unit and district water heat exchangers will make possible the partial recovery of CCS energy expenses. Within the current paper two different CHP plants incorporating presented idea have been proposed and investigated. First is the steam unit equipped with back-pressure steam turbine, circulating fluidized-bed boiler and CO2 removal unit based on chemical absorption in monethanolamine. Second plant configuration is based on IGCC structure equipped with pre-combustion CO2 removal based on physical absorption in Selexol. The idea for rather small CHP units equipped with CO2 removal and waste heat recovery is relatively new. There are a lot of literature references for CHP systems (non CCS) based on CFB (circulating fluidized bed) boilers, as well as, for large coal-fired power units equipped with post-combustion CCS. The problem of waste heat recovery from the chemical CO2 absorption units is discussed e.g. in Refs. [4,5]. The utilization of low-grade heat for district heating purposes is analyzed in Ref. [6]. In case of IGCC CHP system, installations described in literature use mostly biomass. Experience gained in IGCC CHP plants based on biomass gasification may be however transferred into similar plants based on coal. Several IGCC CHP plants do exist, however usually biomass or wastes are gasified, there is no plant which uses hard coal as a main feedstock. The SVZ plant in Schwarze Pumpe is one of such installations where coal and municipal wastes mix is gasified in BGL (British Gas and Lurgi) gasifier [7]. Installation produces electricity and methanol. This installation was however unprofitable, which caused that in year 2007 has been closed [7]. Another example of IGCC CHP plant is installation in Varnamo in Sweden. This biomass-based unit reaches 6 MWe electric and 9 MWth thermal power, while the energy efficiency in cogeneration mode is 83% [8]. Plant in Varnamo was operating since 1996 till 2000 and then it was closed for the same reason as SVZ plant [8]. Plant which uses lignite as a main feedstock for IGCC has been built in Versova (Czech Republic) [9]. There are 26 Lurgi and 1 Siemens gasifier in operation. Electricity and liquid fuels are the main products of this installation, however hot flue gas is used for district heat production [9]. In all recognized IGGC CHP installations, district heat is produced conventionally, as for combined cycles e using flue gas from the heat recovery steam generator (HRSG) exhaust or steam turbine extraction.
MP NelN NelG Q_ dh
r s sa ST Ta WGSR B_ fuel B_ dh
zi
hB
87
medium pressure net electric power of the system, W gross electric power of the system, W district heat flow rate, W enthalpy of vaporization, kJ/kg specific entropy, kJ/kgK specific entropy at ambient parameters, kJ/kgK steam turbine ambient temperature, K water gas shift reactor chemical exergy of coal, W exergy of produced district heat, W molar share of i-th compound exergy efficiency
2. Case studies Two case studies of CCS-integrated CHP units have been analyzed: -
IGCC CHP plant with waste heat recovery equipped with Selexol-based CO2 absorption, CFB CHP plant with waste heat recovery equipped with tapbackpressure steam turbine and MEA-based CO2 absorption.
Both analyzed cases have been compared with the reference plant which is based on CFB boiler and steam cycle of the same main parameters. The CCS installation and waste heat recovery systems have been however eliminated form the reference plant. The idea is to evaluate both CCS technologies not from the point of view of themselves, but referring to the real, commonly used nonCCS technology based on the same fuel. The IGCC plants fed with coal are really occasionally used (if any) as CHP units because of high capital cost and structure complication compared to short annual time of rated capacity utilization. The typical, non-CCS CHP unit fed with coal is based on CFB boiler and is a real reference for investor decision. The IGCC plant becomes however much more interesting when the necessity of CCS occurs. That is the reason why the CFB-based plant is used as reference for both CCS-type processes. The typical, best available design and parameters have been assumed for the reference plant based on [10]. All the three simulated CHP plants have been scaled to the same, rated district heat production (110 MWt). For comparison purposes, the same fuel parameters have been used for analyzed systems. Fuel composition has been presented in Table 1. 2.1. IGCC plant IGCC plants are usually designed as electricity or chemicals production facilities, however they have a high potential for district Table 1 Fuel composition. Coal parameters (as received) C, carbon H, hydrogen O, oxygen N, nitrogen S, sulfur Moisture Ash LHV
e e e e e e e MJ/kg
0.5263 0.0343 0.1102 0.0075 0.0104 0.2237 0.0876 20.16
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M. Liszka et al. / Energy 58 (2013) 86e96
heat production. Present IGCC concepts (especially with CO2 capture) give an opportunity for recovering waste heat at levels suitable for district heat production, as well as for using classical heat sources e.g. tap-steam turbine or outlet of HRSG. Proposed IGCC CHP plant configuration is schematically presented in Fig. 1. The system is based on that presented in Ref. [11] which has been optimized and redesigned towards IGCC CHP plant. It is composed of cryogenic air separation unit (ASU), dryfeed gasifier with syngas cooler, water gas shift reactors (WGSR), acid gas removal (AGR) unit and finally the combined cycle. The entrained flow dry-feed gasifier has been chosen for syngas production. Such a selection seems to be optimal for analyzed IGCC and fuel. Such a selection has also been considered within other published studies [12,13]. The gasifier operating pressure has been set to 4.24 MPa. The temperature of the syngas leaving the reactor reaches 1639 C. The syngas is cooled down primarily by its partial recirculation and then by the production of high pressure steam in a radiant/convection heat exchanger. The temperature of the syngas leaving the cooler and entering the scrubber is equal to 335 C. The gasification reactor consumes oxygen of 95% purity. The coal feeding system is based on ASU nitrogen. The syngas treating and conditioning line is composed of an inter-cooled WGSR reactor which is supplied with MP steam taken from MP steam collector in order to keep proper H2O to CO ratio within each stage of the reactor. The syngas temperature after the first WGSR reactor has been assumed to 460 C while behind the second one to 360 C. The heat rejected from the syngas during the conditioning processes is recovered to the steam cycle as HP, MP and LP steam and for district heat production. The AGR unit is based on a twostage Selexol process. The syngas stream leaving the second WGSR is cooled down, dehydrated and supplied to the first stage of
AGR unit, where 99% of H2S is stripped. Heat for solvent regeneration in stripper column is provided by low pressure steam from HRSG. The separated H2S is then sent to the Claus plant for conversion to elemental sulfur. The H2S-free gas is supplied to the second stage of AGR where it is brought in contact with a lowtemperature lean Selexol solvent for CO2 absorption. The reverse CO2 desorption process occurs in flash drums operating on 3 different pressure steps. Desorbed CO2 is compressed and pumped into the transportation pipeline. The hydrogen-rich (ca. 90%) syngas leaving the AGR is diluted by ASU nitrogen, preheated by VLP steam and used as a gas turbine (GT) fuel. An F-class GT has been selected. As already mentioned, the steam turbine receives steam from both the triple-pressure HRSG and syngas cooling equipment. All compressors within the ASU and AGR islands have been assumed as electric motor e driven machines. Table 2 summarizes the assumptions/specifications concerning the input/output for the system. Waste heat recovery concept involves the final flue gas cooler located in the HRSG, syngas cooler in syngas treating and conditioning line prior to AGR unit, as well as, intercoolers in compression trains of ASU air, nitrogen and CO2 product. All waste heat recovery exchangers are marked in red boxes (in web version) in Fig. 1. For further transportation, the CO2 stream is compressed to 13 MPa. 2.2. CFB plant For the current moment, one of the closest to commercial application method for CO2 capture in classic coal-fed CHP units is post-combustion absorption using MEA or similar solvent. The main energy requirement for this type of process is heat demand
Fig. 1. Concept of IGCC CHP plant.
M. Liszka et al. / Energy 58 (2013) 86e96 Table 2 Assumed parameters for IGCC CHP plant [14e16]. Parameter Pressure in the reactor Temperature of syngas at scrubber outlet Nitrogen to fuel ratio (for fuel transportation), mass basis Steam to fuel ratio, mass basis Oxygen to fuel ratio, mass basis Specific electricity consumption Syngas treating and conditioning line CO conversion ratio at 1st WGSR CO conversion ratio at 2nd WGSR H2O to CO ratio at 1st WGSR H2O to CO ratio at 2nd WGSR Syngas temperature prior to AGR Acid gas removal and CO2 compression Effectiveness of H2S removal Effectiveness of CO2 removal Process steam consumption CO2 capture miscellaneous auxiliary load Gas turbine Combustor exit temperature Compressor pressure ratio Steam cycle Live (HP) steam temperature Live (HP) steam pressure MP steam pressure
IGCC CHP plant MPa OC e
4.24 180 0.175
e e kWh/Mgfuel
0.005 0.66 67
% % e e OC
63.6 86.2 2.34 4 35
% % kg/s kWh/MgCO2
99 90 1.81 60
OC e
1300 15.5
OC MPa MPa
565 12.8 3.95
for desorption of CO2 from the amine solution, which is also stated in Ref. [4]. Proposed CHP plant with CO2 capture system is equipped with CFB boiler, tap-backpressure steam turbine and CO2 capture unit e Fig. 2. CFB boiler produces live steam which has typical parameters for modern CFB boilers installed recently in Poland for CHP mode of operation (560 C, 16.1 MPa). Boiler is equipped with economizer, evaporator, as well as, convective and radiant superheaters. Steam expands in tap-backpressure steam turbine. Steam cycle is equipped with four heat recovery exchangers. The heat necessary for the CO2
89
removal unit is taken from the steam turbine exhaust as a backpressure steam. The rest of steam flow available at the turbine outlet is supplied to the district water heater which operates in parallel with other heaters utilizing waste heat from the CO2 absorption and compression unitsedistrict water is preheated basically in CO2 dehumidifier and CO2 compression train (inter-coolers). Hot flue gas leaving the economiser is primarily cooled down in rotary heat exchanger, where combustion air is preheated. Then in electrostatic precipitator fly ash is removed and finally prior to CO2 absorption process, flue gas is cooled down to 40 C and desulphurized for final required SO2 concentration (10 ppmv). Absorption unit is composed of absorber and stripper columns. In absorber column flue gas is brought in contact with MEA solvent, rich solvent is then injected into a stripper column where its regeneration occurs and CO2 is separated. For further transportation, the CO2 stream is compressed to 13 MPa. For comparison purposes, the typical CFB-based CHP plant without CCS has also been studied. The district heat production within the non-CCS CFB CHP plant takes place in two heat exchangers connected to steam turbine outlet (base load) and extraction (peak-load). The structure and thermal parameters within the boiler island and steam cycle are the same expecting the steam turbine outlet, where steam pressure is lower than for the CCS case, as the required temperature for district heat exchanger is lower than for CO2 desorption process. Crucial parameters of both considered CFB CHP plants have been presented in Table 3. 3. Assessment factors For the comparison purposes, each of three analyzed units (IGCC with CCS, CFB with CCS and CFB reference e without CCS) has been evaluated from the energy, exergy and CO2 emission points of view. Energy utilization factor has been calculated as defined in (1), representing the proportions of energy balance rather than a true thermodynamic assessment.
Fig. 2. Concept of CFB CHP plant.
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M. Liszka et al. / Energy 58 (2013) 86e96
Table 3 Assumed parameters for CHP plants with CFB boiler. Parameter
CHP plant without CO2 capture
CHP plant with CO2 capture
MPa C %
Natural circulation 16.1 560 91
Natural circulation 16.1 560 91
%
85
85
130
130
C C % MPa
260 850 20 0.084
260 850 20 0.24
kJ
e
4000
%
e
90
Unit
Boiler type Live steam pressure Live steam temperature Dry step efficiency of steam turbine (HP, MP) Dry step efficiency of steam turbine (LP) Temperature of flue gases behind rotary air heater Temperature of preheated air Furnace exit temperature Excess air ratio Steam pressure at steam turbine exhaust Heat demand for the CO2 absorption unit (per 1 kg of CO2 removed) CO2 removal effectiveness
C
Q_ þ NelN EUF ¼ dh E_
Fig. 3. Scheme for calculus of avoided CO2 emission.
(1)
chfuel
Energy analysis does not take into account different quality of products. Exergy is a measure of energy quality or thermodynamic irreversibility related to the isolated devices or whole analyzed system [17e19]. Exergy analysis is suitable for the thermodynamic comparison of co-product or multi-product systems. The exergy efficiency of each analyzed CHP system has been calculated in accordance to (2).
hB ¼
-
(2) -
The exergy of produced heat is expressed by increase of exergy of district water as presented in (3) where subscript “II” characterizes hot water, while subscript “I” characterizes cold water.
_ dh ½hII hI Ta ðsII sI Þ B_ dh ¼ m
(3)
The CO2 emission factor which indicates the net CO2 emission per 1 GJ of produced heat has also been calculated in accordance with (4). Considering dual product situation (heat and electricity) it has been assumed that the main product is heat and the emission assigned to heat is calculated as difference between total emission from the analyzed CHP unit and emission avoided in other power stations due to production of specified amount of electricity in considered CHP unit. The scheme for avoided emission calculus has been illustrated in Fig. 3. The equivalent power plant is assumed to be coal-fired, nonCCS, supercritical unit of net electric efficiency equal to 44%.
_ CO2 _ CO2 m m _ Q
-
-
B_ dh þ NelN B_ fuel
ε ¼
Main assumptions taken for the simulation process for all considered systems are as follows:
avoid
(4)
dh
4. Simulation model All analyzed CHP systems have been modeled using the Thermoflex software [20]. Thermoflex contains models of typical energy conversion devices like compressors, turbines or heat exchangers, as well as, agglomerated multi-device models such as steam boiler or gasifier islands. The modeling approach combines the physical and empirical modeling. The flow sheets of analyzed IGCC, CFB and CFB reference systems used for simulation purposes are presented in Figs A.1eA.3 in Appendix A.
the same district heat power (ca. 110 MWth), the same parameters of district water 62.6 C/37 C (annual average), the same feedstock (hard coal), CO2 stream compressed to 13 MPa for both CO2 capture installations, the same temperature of cooling water at battery limits (20 C).
The calculated parameters in characteristic points of the analyzed systems are presented in Tables A.1eA.3 in Appendix A. 5. Results The crucial calculated parameters at system boundaries of each analyzed CHP unit have been presented in Table 4. For the same district heat production, the obtained net and gross electricity production is the highest for IGCC unit reaching 78.40 MW and 113.30 MW respectively. Such big difference between these values is caused by high electricity consumption within the system. Gross electricity production is almost the same for both CFB CHP plants, however in case of CFB CHP plant with CO2 capture, due to the higher auxiliary electricity consumption, net electricity production is lower and equals 50.80 MW, while for reference plant net electricity production is 60.10 MW. The CO2 emission for both plants equipped with CO2 capture is obviously lowein the range of ca. 2e 2.5 kg/s. Lack of energy consumption for the CO2 capture installation in case of reference CFB plant results in the highest value of energy utilization factor achieved which is 0.90. EUF factor for the IGCC CHP plant is 0.72 which is lower than for other systems as it does not take into account different quality of products. When comparing exergy efficiency, the highest value of 0.35 is still achieved for the reference CFB CHP plant (without CO2 capture). The decrease of exergy efficiency caused by CO2 capture and compression in case of CFB CHP plant is ca. 8 percentage points, but in case of IGCC CHP plant the exergy efficiency plant is only 3 points lower than for the reference system. Such a low difference is caused by positive effect of higher electricity to district heat ratio.
M. Liszka et al. / Energy 58 (2013) 86e96 Table 4 Results of simulation analysis. Parameter
Unit
IGCC CHP CFB CHP plant CFB CHP plant with plant with without CO2 CO2 capture CO2 capture capture (reference)
Total district heat production Including: Waste heat Steam-fed heat exchangers Fuel flow rate Fuel chemical energy (LHV-based) Gross electricity production Net electricity production Electric power consumption for CO2 compressors CO2 emission from CHP plant (total) CO2 mass flow rate for transportation (captured) EUF (Eq. (1)) Fuel exergy input District water exergy increase (Eq. (3)) Exergy efficiency (Eq. (2)) CO2 emission factor per GJ of produced district heat (Eq. (4))
MWth
110.22
110.26
110.14
MWth MWth
0 110.22
53.24 57.02
29.22 80.92
kg/s MW
9.34 188.29
10.40 209.66
13.02 262.48
MWe
64.70
64.10
113.30
MWe
60.10
50.80
78.40
MW
e
6.10
7.00
91
is thus equal to 0.0174%. The total mass flow rate entering the system is 1732.70 kg/s, while the total mass flow rate leaving the system is 1732.70 kg/s which means that there is no cycle mass balance error. In CFB CHP plant with CO2 capture simulation model total energy input is 5328407.00 kW, while total energy output is 5328333.00 kW which means 74.00 kW cycle heat balance error. The relative error is thus equal to 0.0014%. Total mass flow rate entering the system is 2384.90 kg/s, while the total mass flow rate leaving the system is 2384.80 kg/s which means 0.10 kg/s cycle mass balance error. In CFB CHP plant without CO2 capture simulation model total energy input is 2271799.00 kW, while total energy output is 2271792.00 kW which means 7.00 kW cycle heat balance error. The relative error is thus equal to 0.0003%. Total mass flow rate entering the system is 1126.80 kg/s, while the total mass flow rate leaving the system is 1126.80 kg/s which means that there is no cycle mass balance error. All the calculated errors are expected to be caused primarily by round-off and convergence method errors. 7. Concluding remarks
kg/s
18.46
2.06
2.52
kg/s
e
18.49
22.20
% MW MW
0.90 205.24 10.36
0.77 228.53 10.36
0.72 286.11 10.36
e
0.35
0.27
0.32
81.59
131.95
kgCO2/GJt 48.86
The CO2 emission factor calculated in accordance with (4) is below zero for both cases with CO2 capture due to effect of coupling of CO2 capture and cogeneration processes. Better values have been obtained for IGCC CHP plant. Values of emission factor have been achieved for assumed net electric efficiency of equivalent power station equal to 44%. For better recognition of the impact of equivalent plant efficiency on CO2 emission, the sensitivity analysis has been prepared as presented in Fig. 4.
6. Error analysis Error analysis has been prepared separately for each simulation model. In IGCC CHP plant simulation model total energy input is 3456375.00 kW, while total energy output is 3455773.00 kW which means 602.40 kW cycle heat balance error. The relative error
Two configurations of coal-fed CHP plants with massive CO2 removal and waste heat recovery systems have been proposed and analyzed assuming constant district heat demand. Obtained results of exergy analysis indicate, that the drop of efficiency due to CO2 removal and compression (ca. 8% points for CFB CHP) is lower than for large-scale coal-fired power units (ca. 10e12% points) for similar CCS heat demand as reported in Refs. [21,22]. The reason is that the waste heat recovery lets for partial cancellation of negative impact of CCS on overall plant efficiency. An IGCC CHP unit with CO2 capture has significantly better emission factors and thermodynamic excellence when comparing to CHP plant with CFB boiler and post-combustion CO2 capture process. Advantages of IGCC CHP unit are mainly due to commonly known effect of Brayton and Rankine cycles integration, as well as, due to advantage of pre-combustion CO2 removal over postcombustion system (referring to assumed in this paper energy demands for both installations). Negative value of CO2 emission factor which arises from applied CO2 removal processes and substituting of electricity produced in other power stations (system advantage of cogeneration), enables potentially for substituting emission from power facilities, where decreasing emission is economically ineffective or impossible (e.g. peak-load boilers). Future work should be focused on off-design analysis of both proposed CHP systems to evaluate change of supply of waste heat as function of variable ambient temperature and district heat demand. The comparative economic analysis reflecting the costs of district heat production, as well as, costs of avoiding the CO2 emission should also be done. Acknowledgments
Fig. 4. Sensitivity analysis of equivalent power station efficiency on CHP emission factor.
This work has been prepared in framework of the task of research, “Development of coal gasification technology for high efficient production of fuels and electricity” funded by the Polish National Centre for Research and Development within the strategic program of research and development: "Advanced energy generation technologies". The results presented in this paper were obtained also from research work financed by the National Centre of Research and Development in the framework of Contract SP/E/1/67484/10 e Strategic Research Program e Advanced technologies for energy generation: Development of a technology for highly efficient zeroemission coal-fired power units integrated with CO2 capture.
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Appendix A
M. Liszka et al. / Energy 58 (2013) 86e96
Fig A.1. Simulation model of IGCC CHP plant with waste heat recovery (Thermoflex).
M. Liszka et al. / Energy 58 (2013) 86e96 93
Fig. A.2. Simulation model of CFB CHP plant with CO2 capture (Thermoflex): a) boiler and power cycle, b) CO2 capture and compression installation.
94 M. Liszka et al. / Energy 58 (2013) 86e96
Fig. A.3. Simulation model of CFB CHP plant, without CO2 capture (Thermoflex).
M. Liszka et al. / Energy 58 (2013) 86e96
95
Table A.1 Calculated parameters at selected points of the plant structure for IGCC CHP case. (Point numbers correspond to those in Fig. A.1). Water/steam Stream number
T, C
p, bar
m, kg/s
Quality
154 152 101 123 67 126 127 160
565 565 321.92 211.96 72.53 122.8 125.38 122.06
128 39.5 8 3 0,3478 43.16 154.06 11.22
40.26 35.02 39.93 35.67 35.67 8.52 40.34 4.92
Superheated 235.4 C Superheated 315.4 C Superheated 151.5 C Superheated 78.4 C 0.9703 Sub cooled 132.1 C Sub cooled 218.9 C Sub cooled 62.9 C
Syngas Stream number
T, C
41 47 204 20 219 29 1 201
600 179.88 220 358.39 149.61 58.9 27.22 143.73
p, bar
m, kg/s
H2
CO2
CO
N2
H2O
H2S
COS
Ar
Other
47.80 42.44 42.44 1.37 1.37 1.83 3.02 1.91
8.18 7.26 7.26 4.67 4.67 6.23 10.29 42.59
15.2 24.73 24.73 25.68 25.68 0.66 0.042 0.03
0.38 0.33 0.33 0.23 0.23 0.31 0.0005 0.0003
0.031 0.0275 0.0275 0.0004 0.0004 0.0005 0.0008 0.0275
0.03 0.02 0.02 0.01 0.01 0.02 0.03 0.03
0.009 0.0025 0.0025 0.0096 0.0096 0.0095 0.0067 0.7822
Mole fractions 41.17 40.44 38.89 35.06 30.24 28.79 27.03 26.5
22.74 24.44 24.44 35.82 35.82 27.79 5.12 17.33
21.73 19.29 19.29 38.31 38.31 51.21 84.5 53.3
6.64 5.9 5.9 29.72 29.72 39.73 2.11 1.33
Table A.2 Calculated parameters at selected points of the plant structure for CHP plant with CO2 capture case. (Point numbers correspond to those in Fig. A.2a and b). Water/steam Stream number
T, C
p, bar
m, kg/s
Quality
16 20 31 32 1 29 33 17 15 255 256 257 247 248
560 344.8 287.1 194.6 158.8 126.1 126.1 245 470 37 37 37 49.35 62.6
161 39.8 25.3 10.9 6 2.4 2.4 172.6 162.6 20 20 20 20 20
81.14 76.54 71.59 63.32 61.19 35.99 25.09 81.34 81.14 1030 42.3 987.7 1030 1030
Superheated 212.1 C Superheated 94.8 C Superheated 62.6 C Superheated 10.9 C 0.977 0.936 0.936 Sub cooled 108.5 C Superheated 121.3 C Sub cooled 175.4 C Sub cooled 175.4 C Sub cooled 175.4 C Sub cooled 163 C Sub cooled 149.8 C
Flue gas Stream number
T, C
37 38 40 44 167 218
850 323.13 130.3 130.3 35 30
p, bar
m, kg/s
mash, kg/s
CO2
N2
H2O
SO2
Ar
O2
71.11 71.11 71.34 71.34 87.68 0
10.40 10.40 10.06 10.06 4.88 0.03
0.007 0.007 0.007 0.007 0 0
0.86 0.86 0.86 0.86 1.06 0
3.18 3.18 3.8 3.8 4.67 0
Mole fractions 1.0427 1.0353 1.0328 1.0132 1.0132 130
95.41 95.41 98.83 98.83 76.65 18.49
1.241 1.241 1.241 0.002 0 0
14.44 14.44 13.93 13.93 1.71 99.97
Table A.3 Calculated parameters at selected points of the plant structure for reference CHP plant without CO2 capture case. (Point numbers correspond to those in Fig. A.3) Water/steam Stream number
T, C
p, bar
m, kg/s
Quality
16 20 32 33 24 31 29 41 17 15
560 344.8 287.1 194.6 158.8 105.6 95 105.6 245 470
161 39.8 25.3 10.9 6 1.2 0.85 1.2 172.6 162.6
72.7 68.6 64.2 60.5 53.9 53.7 53.7 0.2 72.9 72.7
Superheated 212.1 C Superheated 94.8 C Superheated 62.6 C Superheated 10.9 C 0.977 0.913 0.901 0.913 Sub cooled 108.5 C Superheated 121.3 C (continued on next page)
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M. Liszka et al. / Energy 58 (2013) 86e96
Table A.3 (continued) Flue gas Stream number
T, C
p, bar
m, kg/s
mash, kg/s
CO2
5 8 66 18
850 329 130 130
1.0378 1.0303 1.0228 1.0132
85.73 85.73 94.97 94.97
1.134 1.134 1.134 0.002
14.44 14.44 13.01 13.01
N2
H2O
SO2
Ar
O2
71.1 71.1 71.71 71.71
10.41 10.41 9.49 9.49
0.007 0.007 0.007 0.007
0.86 0.86 0.86 0.86
3.18 3.18 4.92 4.92
Mole fractions
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