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Thermodynamic evaluation of CHP (combined heat and power) plants integrated with installations of coal gasification
Energy 92 (2015) 179e188
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Thermodynamic evaluation of CHP (combined heat and power) plants integrated with installations of coal gasification Andrzej Zie˛ bik*, Tomasz Malik 1, Marcin Liszka 2 Silesian University of Technology, Institute of Thermal Technology, Konarskiego 22, 44-100 Gliwice, Poland
a r t i c l e i n f o
a b s t r a c t
Article history: Received 9 January 2015 Received in revised form 23 April 2015 Accepted 1 June 2015
Integration of a CHP steam plant with an installation of coal gasification and gas turbine leads to an IGCCCHP (integrated gasification combined cycle-combined heat and power). Two installations of coal gasification have been analyzed, i.e. pressurized entrained flow gasifier e case 1 and pressurized fluidized bed gasifier with CO2 recirculation e case 2. Basing on the results of mathematical modelling of an IGCCCHP plant, the algorithms of calculating typical energy indices have been derived. The following energy indices are considered, i.e. coefficient of heat performance and relative savings of chemical energy of fuels. The results of coefficients of heat performance are contained between 1.87 and 2.37. Values exceeding 1 are thermodynamically justified because the idea of cogeneration of heat and electricity based on combining cycles of the heat engine and heat pump the efficiency of which exceeds 1. Higher values concerning waste heat replace more thermodynamically effective sources of heat in CHP plants. Relative savings of the chemical energy of fuels are similar in both cases of IGCC-CHP plants and are contained between the lower value of the CHP (combined heat and power) plants fuelled with coal and higher value of CHP plants fired with natural gas. © 2015 Elsevier Ltd. All rights reserved.
Keywords: Gasification Cogeneration Waste heat Thermal integration Coefficient of heat performance Relative savings of fuels
1. Introduction Although the technology of coal gasification has been applied in the chemical industry for several years, only in the eighties and nineties of the last century it was applied in IGCC (integrated gasification combined cycle) power units. In these years four IGCC plants were constructed, i.e., Wabash River and Tampa Electric in USA, Demkolec Bugggenum in the Netherlands and Elcogas Puertollano in Spain [1,2]. The fifth IGCC power plant which was built in 2008 is located in Nakoso in Japan [3]. Besides coal also the byproducts of crude oil refinery (petroleum coke and asphalt), biomass, sludge, waste from pulp and paper industry are gasified. The IGCC power plants, mentioned above produce only electricity (the power rating is about 300 MWel of each). IGCC power plants have some experience thanks to about 25 years operation, whereas IGCC integrated with combined power and heat units are only at the beginning of their development. In literature we can generally meet cases of small cogeneration units
* Corresponding author. Tel.: þ48 322371049; fax: þ48 322372872. E-mail addresses: [email protected] (A. Zie˛ bik), [email protected] (T. Malik), [email protected] (M. Liszka). 1 Tel.: þ48 322371757; fax: þ48 322372872. 2 Tel.: þ48 322372852; fax: þ48 322372872. http://dx.doi.org/10.1016/j.energy.2015.06.003 0360-5442/© 2015 Elsevier Ltd. All rights reserved.
integrated with installations of biomass or municipal wastes gasification. For example in Schwarze Pumpe [4] operated a gasification system fed with lignite and municipal wastes. In this plant existed two possibilities of its operation, i.e., cogeneration path (combined heat and power) with a power rating of 75MWel and chemical path (synthesis of methanol). The small pilot cogeneration system integrated with a gasification installation operated in the years 1996÷2000 in Varnamo (Sweden) [5]. The parameters of gasifier e 2 MPa; 950÷1000 C, LHV of syngas e 5 MJ/Nm3. Steam parameters e 4 MPa, 450 C. Energy utilization factor amounted to 83%. The demonstration IGCC e CHP plant fed with biomass came into being in Belgium [6]. The atmospheric gasifier with a fluidized bed was applied. The power rating of the demonstrating plant amounts to 0.5 MWel. In the coming years power rating is predicted to amount to 2 MWel. The IGCC plant operating in Vresova (Czech Republic) [7] is equipped with 26 Lurgi gasifiers and one new Siemens gasifier. The overall power rating of this system amounts to 400 MWel. Gasifiers are fuelled with lignite. The enthalpy of hot flue gases is used to preheat network water in the district heating system. In this way the idea of cogeneration is realized (IGCC-CHP). The additional production of cogenerated heat leads to an increase of the EUF (energy utilization factor) of this system by about 4 percentage points in comparison with an IGCC power plant.
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Nomenclature
ref tt
Main symbols B exergy E energy P power rating Q_ flux of heat T temperature
Abbreviations AGR acid gas removal ASU air separation unit BHE basic heat exchanger BIGCC biomass integrated gasification combined cycle C, COM compressor CC combustion chamber CCU CO2 compression unit CF Carnot factor CFB circulating fluidized boiler CHP combined heat and power CL conditioning line COHP coefficient of heat performance COP coefficient of performance DHS district heating system DHWP district heating water preheater E expander EUF energy utilization factor FW feed water GT gas turbine HP high-pressure HRSG heat recovery steam generation IGCC integrated gasification combined cycle LHV lower heating value LP low-pressure MP medium-pressure PHE peak heat exchanger WGSR water gas shift reactor
Greek symbols D increase ε relative loss h efficiency s power to heat ratio Subscripts a ambient ch chemical cog cogeneration cond condensing E energetic el electric G gross h heat hp heating plant in inlet m average thermodynamic N net out outlet pp power plant
In Ref. [8] the idea of adapting the existing combined gas and steam cycle fuelled with natural gas to IGCC plant fed with biomass and co-fired with natural gas together with syngas has been proposed. In this way the a so-called BIGCC (Biomass Integrated Gasification Combined Cycle) is realized. An exemplary economical analysis has been performed basing on the existing combined gas €teborg with heat. It has been and steam cycle Rya providing Go proved that in the case of biomass promotion such a modernization €ping has been is profitable. This solution as a new concept for Linko considered in Ref. [9]. The economical result of such an enterprise depends on obligatory regulations in law. Such a solution is favourable because of the reduction of CO2 emissions. The BIGCC e CHP plant with a power rating of 2 MWel and heat flux amounts to 4 MWth operated in Austria [9]. The paper [10] presents analysis of utilizing the wastes from a crude oil refinery in gasifier in order to produce heat and electricity in CHP plant. The construction of such IGCC-CHP plants near refineries in Mexico city is considered to cover the demand for heat and electricity. In fact, excepting one case (Vresova [7]), literature describes only small IGCC-CHP plants fired mainly with biomass or municipal wastes but operating large IGCC power plants [1e3] may also be considered as a base for the adaptation aiming at the integration of IGCC plants with CHP units. The IGCC-CHP system consisting of two main subsystems, i.e., production and cleaning of syngas and CHP plant. If CO2 removal is considered, the system is extended by an ASU (air separation unit) and module of CO2 removal and compression. Only cryogenic ASU provides adequate efficiency of oxygen production. From the
reference transformation and transmission
experience concerning hitherto operation of IGCC power plants the pressurized flow dry-feed gasifier is to be recommended. The advantages of this technology are among others high efficiency, high degree of fuel conversion, fuel flexibility, a low share of methane and pollutants in syngas. Disadvantages are large demands for oxygen and high temperature of syngas. In the case of CO2 removal the water gas shift reactor is indispensable. The removal of CO2 and H2S is generally realized by physical absorption (Selexol, Rectisol e most often used solvents). The purified syngas contains above 90% of H2. For the combustion of syngas the GT (gas turbines) designed for combustion of natural gas have been adapted. The HRSG (heat recovery steam generator) may be additionally equipped with an interstage reheater. The steam from HRSG is delivered to the steam turbine on several levels of pressure. As the authors of [11] have stressed the application of coal gasification in the fluidized bed reactor with CO2 recirculation leads to a reduction of investment and operation costs of installation. The utilization of CO2 as gasifying medium besides oxygen and steam is possible thanks to Bouduard's reaction. In results CO besides H2 is the main component of syngas. In the fluidized process gasification with CO2 recirculation the char is also produced for the combustion of which an oxy-fuel fluidized boiler (CFB) is applied. The application of oxy-combustion in the boiler of char is justified because it allows to avoid the separation of CO2 from the mixture of N2 and O2. Only separation of H2O is needed. The traditional line of conditioning and treatment of syngas as in entrained flow gasifier has been substituted by cleaning of syngas from solid particles and its hot desulphurization [12]. Thanks to
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the elimination of some irreversible thermodynamical processes it may be expected that the fluidized bed gasifier with CO2 recirculation will be characterized by a higher exergy efficiency than the entrained flow gasifier [13]. But on the other hand the part of modules belonging to the fluidized bed gasifier with CO2 recirculation did not achieve the adequate degree of maturity. It concerns mainly cleaning and desulphurization of hot syngas. A separate problem is GT in which oxy-combustion technology as in the char boiler has been applied. Although, as mentioned earlier, the maturity of some parts of fluidized bed gasifier with CO2 recirculation is not satisfying in literature there are some conceptions concerning this gasifier. The authors of [14] investigated the influence of thermal parameters (pressure and temperature) on gasification. They stress that applying CO2 in gasification processes influence the reduction of NOx and allow to control the temperature in the gasifier. The analysis of gasification process in the fluidized bed reactor by means of CO2 and steam mixture has been carried out in Ref. [15]. According to the opinion presented in Ref. [15] this way of gasification is suitable in the case of coal with a high share of volatile matter and biomass. The advantage of CO2 recirculation is a simultaneous utilization of CO2 as gasifying medium and transporting agent. The conception of an Oxy-IGCC system with recirculation of CO2 has been presented in Ref. [16]. In this system nitrogen was replaced by CO2, which is provided to the gasifier. Some part of flue gases (mainly CO2 and H2O) is recirculated to GT after compression. It limits the nitrogen input to the system. The authors of [17] analyzed future systems of IGCC among others Oxy-IGCC. In the latter case the recirculation of flue gases from the HRSG outlet has been proposed in order to reduce the temperature of flue gases before the expander of GT. In Ref. [18] the oxy-fuel IGCC system has also been presented. Nitrogen was substituted by the CO2 as transporting agent. Syngas cooled down to 850 C has been preliminarily cleaned from solid particles in cyclones and next after expansion and cooling down to 550 C finally cleaned by means of filter. Due to the jointed removal of CO2 and SO2 desulphurization has not been assumed. A part of outlet flue gases (mainly CO2 and H2O) is recirculated to the combustion chamber of GT in order to control the temperature before the expander of GT. The remaining part of CO2 after the condensation of H2O has been cleaned of N2 and Ar in the cryogenic installation and next compressed for its transport. The cooling of the blades is realized by means of CO2 from the compressor. The paper [19] is devoted to the analysis of CO2 capture methods proposed in IGCC plants. Two methods have been analyzed, i.e., chemical absorption and membrane CO2 separation. Most authors pay attention not only to thermodynamical advantages of Oxy-IGCC plant with CO2 recirculation but also to disadvantages, besides those already mentioned (cleaning and desulphurization of hot syngas) also problems concerning oxy-combustion of syngas and operation of GT expander. These problems result from different properties of CO2 in relation to air. Therefore this leads to the modification of the traditional GT. Usually the EUF (Energy Utilization Factor) [20] is used for the evaluation of energy affects of heat and electricity cogeneration. The more adequate measures of the effectiveness of CHP plants are COHP (coefficient of heat performance) also called partial energy efficiency of heat production [21] as well as relative savings of chemical energy of fuels in a CHP plant in comparison with the separate production of heat and electricity. Both these indices are the subject matter in this paper. The cogeneration (polygeneration) process is characterized by the main product and by-product (cogeneration) or by-products (polygeneration). The decision concerning the choice of the main
181
product depends on which product of the co(poly)generation process decides about the capacity of the main installations. The choice of the main product and by-product is the first step in the way of dividing input fuel charging the main product and by-products and in the case of economical aspects (general problem) the division of the costs. In the monograph [21] the method of the division of the costs (of input fuels, too), basing on the replaced process has been described. This method is also known as the so-called “method of avoided costs”. It may be advisable to add that in USA this method is approved by the law act known as PURPA (Public Utility Regulatory Policies Act) [22]. In literature we meet most often the so called “arithmetical” partial efficiencies, mainly concerning electricity production. They are calculated in the simple way dividing the production of electricity (or heat) by the entire consumption of the chemical energy of fuel. Calculated in this way partial energy efficiencies of electricity and heat production are devoided both of the thermodynamic and economical sense [21], although they may be useful in calculations of PES (Primary Energy Savings) [23]. Among the literature mentioned above items concerning energy indices which are in detail discussed in Refs. [24,25] two items, i.e. [26] and [27] are worth noticing. The authors of [26] treated electricity similarly as the authors of [21] using the term an additional product, whereas the authors of [27] applied method of avoided input fuels optionally for heat or electricity. 2. Conceptions of IGCC-CHP plants The paper is devoted to two conceptions of IGCC-CHP plants concerning firstly the entrained flow gasifier and in the second case to fluidized bed reactor with CO2 recirculation. Both cases of CHP plants are equipped with an extractionecondensating turbine with two bleeders for the district heating system. The first case concerns a solution tested in practice in IGCC power plants [1e3]. The second case is prospective technology promising from the viewpoint of thermodynamic irreversibility reduction but still requires final solution of some technological aspects (among others desulphurization of hot syngas) [17,28]. Fig. 1 presents the schematic diagram of an IGCC plant with pressurized dry-feed gasifier fired with coal. After cooling, syngas is delivered to the conditioning line consisting of a scrubber, COS hydrolysis reactor and WGSR (water gas shift reactor). Syngas is cleaned from solid particles of ash in cyclone, ceramic filter and scrubber. Solid fractions are usually partially recirculated to the gasifier. NH3, HCN, HCl and NaCl are absorbed in the scrubber. In the additional reactor of hydrolysis COS is converted to H2S and this latter acid gas is removed in the H2S absorber. The conversion of CO to CO2 proceeds according to reaction of WGSR (water gas shift reactor). After the WGSR syngas contains mainly H2 and CO2 as well as an inconsiderable amounts of CH4, N2, Ar and impurities (mainly compounds of sulphur). Oxygen with a purity of 95% is produced in the cryogenic installation of ASU. Nitrogen, the by-product of ASU can be used for the pneumatic transport of fuel. Acid gases (H2S and CO2) are removed by means of physical absorption. This method consist in the solving of CO2 and H2S in solvents without chemical reactions. The efficiency of H2S removal amounts to 99,5%. In the case of CO2 we have 98%. This process should be applied when the share of acid gases is relatively high. This process is characterized by a low energy consumption and high selectivity of H2S and CO2 removal. The module AGR contains also compressors of CO2. Syngas from AGR is delivered to the heat cycle. The CHP plant is equipped with the F-class GT (gas turbine), triple-pressure HRSG (heat recovery steam generator) and extractionecondensating steam turbine. The steam turbine is equipped with bleeders of heating steam feeding the heat exchangers of the district heating system.
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Fig. 1. Schematic diagram of IGCC CHP plant with entrained flow gasifier; ASU e Air Separation Unit; G e Gasifier; CL e Conditioning line; WGSR e Water Gas Shift Reactor; AGR e Acid Gas Removal; CHP e Combined Heat and Power; C e Compressor; CC e Combustion Chamber; E e Expander; HP e High Pressure; MP- Medium Pressure; LP e Low Pressure; GT - Gas Turbine; FW - Feed Water; HRSG e Heat Recovery Steam Generator; DHWP e District Heating Water Preheater; BHE e Basic Heat Exchanger; PHE e Peak Heat Exchanger; Q_ DHS - Heat flux for district heating system; E_ CHF e Flux of chemical energy of fuel; E_ CHS e Flux of chemical energy of syngas; Q_ C e Heat flux of water cooling; H_ e Flux of enthalpy; DH_ e Increase of enthalpy flux from installation of waste heat recovery; Pel_i e Internal consumption of electricity.
Most of the waste steam and heat from the technological modules (gasifier with cooler of syngas and conditioning line) is utilized within the CHP plant. Fig. 2 presents a schematic diagram of an IGCC-CHP plant with pressurized fluidized bed gasifier with CO2 recirculation considered as a gasifying agent besides oxygen and MP steam. After the gasifier syngas is exported for hot cleaning from solid particles and next to the conditioning line where it is cooled down prior to H2S absorption. After desulphurization in AGR, the cleaned syngas is delivered to combustion chamber of GT together with oxygen and CO2. GT is the F-class turbine adapted for flue gases from combustion of syngas in the atmosphere of CO2 and oxygen. The blades of GT are cooled by the part of CO2 from GT compressors. The experiences concerning existing IGCC systems show that the GT of F-class met with success in the case of syngas fuelling [1e3]. Outlet flue gases from GT are delivered to the triple-pressure HRSG in which HP steam (high-pressure), MP steam (mediumpressure) and low-pressure steam are produced. Outlet flue gases from HRSG are fed to the preliminary heat exchanger of the district heating system. The cooling of outlet flue gases after HRSG below the saturation point temperature is possible because syngas contains minute quantities of sulphur compounds. The char, by-product of gasifier is combusted in the oxycombustion CFB boiler. Leave steam from boiler of char together with fluxes of steam from HRSG are delivered to the extractioncondensing turbine. From the low-pressure bleeders of the steam turbine basic (BHE) and peak (PHE) heat exchangers of district heating system are fed. The waste heat recovery for the purpose of preheating water in
district heating networks is realized in interstage coolers of compressors in ASU and CO2 CCU (compression unit). 3. Results of simulative calculations Mathematical modelling of the IGCC-CHP plants which are presented in the schematic diagrams (Figs. 1 and 2) has been carried out using professional software [29]. This is computer application making it possible to develop thermodynamic models of energy systems. These models are assembled with components available in the library of this software. The components are particular elements of IGCC-CHP system e.g. gasifier, heat exchangers. Firstly, the set of components have been chosen and next the structure of energy system is constructed by means of adequate links between components. After checking the correction of these links by the software, the input data are entered to the model. The input data include parameters of the components and information about fluxes of input and output agents. The mathematical model may run in the mode “design” or “off-design”. In this paper models in the mode “design” are analyzed and all calculated values concern nominal parameters. Tables 1 and 2 present selected input parameters concerning simulative calculations and results of simulations while in Table 3 syngas composition at the outlet of gasifier has been presented. The obtained results show that the second case is characterized by higher EUF factors than in the case 1. However, in the case 1 the net electric power is almost 55 MW higher than in the second case, while the heat production remains on the same level in both cases. Comparing chemical energy of syngas in each stage of conversion,
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Fig. 2. Schematic diagram of IGCC-CHP with fluidized bed gasifier with recirculation of CO2; the explanation of abbreviations is the same as concerning Fig. 1.
Table 1 Main input parameters concerning simulative calculations. Parameter
Gasifier pressure Temperature of syngas leaving gasifier Type of solvent for H2S removal in AGR Pressure ratio in GT Temperature of flue gases entering expander of GT Live steam temperature Live steam pressure Reheated steam temperature Reheated steam pressure Condenser pressure
Unit
Results Case 1
Case 2
MPa C e e C
42.38 1460.9 Selexol 14.88 1350
34 900 MDEA 19.38 1263
C MPa C MPa kPa
565 12.8 565 3.95 5
565 18 565 3.95 5
Table 2 Selected results of simulations. Parameter
Unit
Results Case 1
Case 2
Steam turbine power Gas turbine power Gross electric power Net electric power Net electric power of condensing part Relative internal consumption of electricity Total heat flux for DHS Chemical energy of fuel LHV of coal Chemical energy of syngas leaving gasifier/ entering conditioning line LHV of syngas entering conditioning line Chemical energy of syngas entering AGR LHV of syngas entering AGR Chemical energy of syngas entering gas turbine LHV of syngas entering gas turbine Chemical energy of slag/char EUFG EUFN
MWe MWe MWe MWe MWe %
85.54 162.00 247.54 174.29 69.28 29.59
105.39 85.69 191.08 120.30 46.493 37.04
MWth MWch MJ/kg MWch
200.00 569.73 20.16 445.76
200.00 458.95 22.91 267.84
MJ/kg MWch MJ/kg MWch MJ/kg MWch % %
9.27 402.85 6.51 398.27 30.33 4.87 78.55 65.70
7.34 267.63 7.89 264.71 7.99 122.38 85.21 69.79
in the first case the values are higher than in the second case. This happens due to the lower electricity production in case 2 and also due to lower carbon conversion in gasifier. Lower carbon conversion in the gasifier results in char production, which is fed to the CFB boiler. Due to the absence of WGSR and CO2 capture process in AGR module, syngas fed to the GT is rich in CO2 and unconverted CO, thus the LHV is definitely lower than in the case 1, which results from the high content of H2 in the syngas. 4. Analysis of waste energy sources and DHS fluxes of heat Technological modules (gasifier with syngas cooling system and conditioning line) are sources of waste steam production (highpressure HP, medium-pressure MP, low-pressure LP). These fluxes of waste steam are provided into the superheaters of HRSG (case 1 and 2) and also into oxy-combustion char boiler (case 2) and next fed to the steam turbine generating electricity. The recovered waste heat from the conditioning line, from interstage cooling of compressors in ASU as well as interstage cooling of CO2 compressors is utilized in the district heating system [30]. In case 1 the gasifier (evaporative cooling) together with the syngas cooling system and conditioning line are sources of HP and MP waste steam. The HP waste steam from the gasifier is superheated steam (453 C), whereas the HP waste steam from the conditioning line is saturated vapour. Both these fluxes are supplied to the superheater of HRSG and next feed the HP (high-pressure) part of steam turbine. The MP waste steam (saturated vapour) from the gasifier and the conditioning line serve only for process aims.
Table 3 Syngas composition at the gasifier outlet. Composition, mol % H2
CO2
H2O
CO
N2
H2S
COS
CH4
BTX
Other
Case 1 24.010 5.728 12.700 48.920 8.205 0.381 0.028 0.001 0.000 0.027 Case 2 14.915 21.430 11.599 46.217 2.608 0.375 0.042 2.458 0.025 0.331
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This MP waste steam together with the part of the outlet flux from the HP part of the steam turbine is used in the gasifier and the conditioning line (WGSR). The remaining part of the outlet steam from the HP part of the steam turbine together with MP steam from HRSG is passed to the interstage reheater and next to the MP part of the steam turbine. The conditioning line is also a source of LP waste steam on two levels of pressure, i.e., 0.8 and 0.45 MPa. The flux of LP waste steam 0.8 MPa is delivered together with the flux of LP steam from HRSG to the inlet of LP2 part of the steam turbine (Fig. 1). The flux of LP waste steam 0.45 MPa serves partially to the cover of the internal heat consumption in AGR module and the remaining part is applied to the preheating of syngas before the combustion chamber of the gas turbine. Summing up, the fluxes of waste steam from the gasifier with the syngas cooler system and from the conditioning line utilized in the steam turbine are sources of about 13.3 MWel which amounts to about 5.4% of the entire power rating of the gross electric power, 4.4% provided by the waste from the gasifier and the remaining part from the conditioning line. In the second case (fluidized bed reactor with CO2 recirculation presented in Fig. 2) the evaporative cooling of the gasifier is a source of MP saturated waste steam (252.6 C) which is next passed to the superheaters of HRSG and oxy-combustion char boiler. The waste production of HP steam (360 C) is realized in the syngas cooler system (conditioning line). This steam is also superheated in HRSG and the char boiler. From both these sources of waste steam utilized in the steam turbine the power electricity amounts to 6 MWel. This is 3.1% of gross electric power, 2.2% provided by the waste steam from the conditioning line. Generation of waste heat for the purpose of preheating the network water of district heating system is realized in the module of the conditioning line, in the air separation unit and in the CO2 compressors. First of all, the fluxes of waste heat are utilized to preheat the district heating network water. Next a DHWP (district heating water preheater) situated at the outlet of HRSG is applied, thanks to which the temperature of flue gases is decreased. The BHE (basic heat exchanger) and PHE (peak heat exchanger) are fundamental parts of the district heating system. In case 1 the share of waste heat in heat production is about 28% whereas in case 2 only 20%. The share of DHWP and PHE in heat production is the same in both cases and amounts to 6% and about 33%, respectively. The amounts of waste heat as well as information about heat fluxes generated in DHWP, BHE and PHE heat exchangers have been gathered in Table 4. Each of DHS heat fluxes is connected with the different range of temperature of preheated network water which characterize a quality of heat defined by the Carnot Factor (CF) [21]:
CF ¼
Tm Ta Tm
(1)
where: Ta e ambient temperature, Tm e average thermodynamic temperature of district heating network water. The average thermodynamic temperature Tm is defined as follows [21]:
Tm ¼
Tout Tin ln TTout in
where: Tout e outlet temperature,
(2)
Table 4 Fluxes of heat for DH system. Source of heat flux
Case 1 Q_ DHS MWt
Tm, K
CF
Case 2 Q_ DHS MWt
Tm, K
CF
Conditioning line of syngas CO2 compressors ASU compressors District heating water preheater Basic heat exchanger Peak heat exchanger
32.4
372.2
0.2611
15.4
373.2
0.2611
6.8 16.6 12.6
364.9 367.8 372.2
0.2464 0.2523 0.2611
10.4 13.9 12.0
367 362.5 369.9
0.2507 0.2414 0.2566
64.5 67.1
373.2 392.9
0.2631 0.3001
81.2 67.1
370.7 392.9
0.2582 0.3001
Tin e inlet temperature. The Carnot Factors as a measure of the quality of heat serve for the determination of the coefficient of heat performance [21]. By-production of electricity using the waste steam from evaporative cooling of gasifier as well as from the cooling system of syngas and by-production of heat for the purpose of district heating system are the effects of the external utilization of waste energy. Besides this there also exist in IGCC-CHP systems internal utilization of waste energy, usually more effective than the external one [21]. In case 1 preheating of cleaned syngas takes place before the combustion chamber of GT using recirculated hot syngas and utilized waste MP steam from AGR in the gasifier and conditioning line. The first way of internal utilization of waste energy has also been applied in case 2. Moreover, the CO2 recirculated into the fluidized bed gasifier is preheated by means of hot syngas cooling water. The thermodynamic analysis of internal utilization of waste energy generated in IGCC is not dealt with in this paper.
5. Coefficient of heat performance The idea of dividing input fuels (in the economical approach to the costs) between useful products of co(poly)generation process based on the principle that the fuel consumption charging the byproduct results from the avoided fuel consumption in the replaced process. Usually a CHP plant is constructed from the viewpoint of covering the demand for heat. It means that heat is the main product (at least in the heating season). Then electricity generated in the cogeneration process (no condensing mode) is a by-product. Basing on the principle of avoided consumption of fuel in replaced process, the production of electricity in cogeneration should be charged by such a consumption of the chemical energy of fuel as in the power plant operated in accordance with the same technology (constructed at the same time) and delivering the same amount of electricity to the consumer. The Directive [23] and guidance to it precises the criteria of the choice of the reference (replaced) power plant. This approach leads to the formula [21]: cog E_ ch el ¼
Pel cog G 1 εel cog htt h0tt hE pp N
(3)
where: cog E_ ch el e flux of the chemical energy of fuel charging the production of electricity in cogeneration mode of IGCC-CHP plant, Pel cog G e gross power rating of cogeneration mode of IGCC-CHP plant, εel cog e index of the relative internal consumption of electricity,
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htt ; h0tt e the efficiencies of transformation and transmission of electricity from IGCC-CHP plant and from replaces power plant, respectively, hE pp N e net energy efficiency of replaced (reference) power plant. The remaining part of electricity is generated in the condensing mode. The chemical energy of fuel charging the production of electricity in the condensing part of the IGCC-CHP plant is calculated from the equation:
P cond E_ ch el ¼ el cond N hE cond N
(4)
where: cond E_ ch el
e flux of the chemical energy of fuel charging the production of electricity in condensing part of IGCC-CHP plant, Pel cond N e net power rating of condensing part of IGCC-CHP plant, hE cond N e net energy efficiency of condensing part of IGCC-CHP plant. The production of electricity in cogeneration leads to savings of the chemical energy of fuels in comparison with separate production of heat and electricity because it is produced on the stream of heat for district heating systems, whereas the production of electricity in condensing mode takes place on the stream of steam passed to condenser. Thus, the consumption of the chemical energy of fuel charging the production of heat flux delivered to the district heating system results from: cog cog cond E_ ch h ¼ E_ ch IGCCCHP E_ ch el E_ ch el
(5)
The chemical energy of fuel charging the production of heat for district heating system consists of the following components cog E_ ch h ¼ E_ ch DHWP þ E_ ch BHE þ E_ ch PHE þ E_ ch CL þ E_ ch ASU þ E_ ch COM
(6) where E_ ch DHWP , E_ ch BHE , E_ ch PHE , E_ ch CL , E_ ch ASU , E_ ch COM denote fluxes of the chemical energy of fuel charging the heat production in DHWP, BHE, PHE, CL, ASU and AGR, respectively. The first item concerns the production of heat in the preliminary district heating water preheater located in HRSG. The two next ones express the basic and peak part of heat production based on steam fluxes from the low-pressure bleeders of the steam turbine. The last ones denote waste heat fluxes from the conditioning line and installations of interstage coolers of ASU and CO2 compressors. Introducing the coefficient of heat performance, defined as follows:
COHPi ¼
Q_ i _ Ech h i
(7)
We obtain Eq. (6) in the following form: cog E_ ch h ¼
Q_ i COHP i i¼1
n X
(8)
where: COHPi e coefficient of heat performance in i-th source of DHS heat production,
185
Q_ i e flux of DHS heat production form i-th source of heat including installation of waste heat recovery, E_ ch h i e flux of the chemical energy of fuel charging the production of i-th flux of heat, n e the number of heat fluxes with various levels of thermal parameters. In order to solve Eq. (8) we must introduce (n-1) additional equations describing the relations between the particular coefficients of heat performance. To solve this problem the exergy method has been applied, the flux of the chemical energy of fuel is proportional to the flux of the exergy of heat. It means that we can write:
DB_ i E_ ch i ¼ DB_ ref E_ ch ref
(9)
where: E_ ch i e flux of the chemical energy of fuel of i-th DHS heat production, E_ ch ref e flux of the chemical energy of fuel of the reference DHS heat (one case conventionally chosen from the set of DHS heat fluxes), DB_ i e flux of exergy of i-th DHS heat flux, DB_ ref e flux of exergy of reference DHS heat flux. The flux of exergy of the i-th heat flux is calculated from the equation:
DB_ i ¼ Q_ i CFi
(10)
where CFi denotes the Carnot factor characterizing the i-th flux of heat defined according to Eq. (1). The values of the Carnot factor concerning fluxes of heat from the installation of waste heat recovery (conditioning line, interstage cooling of the compressors in ASU and AGR are calculated in the section devoted to the analysis of waste energy sources) (Table 4). Basing on Eqs. (1), (7), (9) and (10) we can write:
CFref ðCOHPÞi ¼ ðCOHPÞref CFi
(11)
If conventionally DHWP (district heating water preheater) is considered as a reference one, basing on Eqs. (3)e(7) and (11), we have:
COHPDHWP ¼
1 CFDHWP
P _ Q i CFi i
P E_ ch IGCCCHP hel cog N Phel cond N E pp N
(12)
E cond N
and
COHPi ¼ COHPDHWP
CFDHWP CFi
(13)
where i denote BHE, PHE, CL, ASU and AGR, respectively. Fig. 3 presents the results of the analysis of the coefficient of heat performance concerning the particular fluxes of heat including waste heat recovery from technological installations. It is thermodynamically justified that the values of COHP exceed 1 because the concept of heat and electricity cogeneration results from joining the heat cycles of the engine and the heat pump [21]. In the latter case the Coefficient of Performance always exceeds one. In the case of waste heat recovery higher values of COHP are caused by lower
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186
In Eq. (15) it has been assumed that the efficiency of transporting the heat from the IGCC-CHP plant and the heating plant are the same. The chemical energy of fuel charging the production of electricity in the replaced power plant is expressed by the Formula (3) in which it has been assumed that htt ¼ h0tt :
Pel cogN E_ ch pp ¼ EUFpp N
(16)
where EUFpp N ¼ hEppN denote energy utilization factor concerning replaced IGCC power plant. The flux of the chemical energy of fuel charging the cogeneration of heat and electricity in an IGCC-CHP plant results from Eqs. (4) and (5): Fig. 3. Coefficient of heat performance.
thermal parameters. It means that heat from the installations of waste energy recovery replaces heating steam from the bleeders of the steam turbine providing a higher power to heat ratio which is the quality factor of cogeneration.
The EUF (energy utilization factor) expressing the overall energy efficiency of a CHP plant is not a sufficiently adequate measure of energy effectiveness of heat and electricity cogeneration. A better measure than EUF is the COHP (coefficient of heat performance) analyzed in the previous section, but a quite adequate measure of the energy effectiveness of heat and electricity cogeneration is the saving of the chemical energy of fuel in comparison with the separate production of heat and electricity. Savings of the chemical energy of fuels are calculated based on the assumption that the demand for heat and electricity by the consumers are provided from both, the cogeneration system and the separate producers of heat and electricity. This assumption also refers to the nominal flux of heat and power rating. Savings DE_ ch of the chemical energy of fuel result from the difference between the consumption in separate production of heat and electricity and the consumption in the cogeneration process:
where: Pel G e gross power rating, EUFCHP G e gross energy utilization factor.
DE_ ch ¼
where
Pel G ð1 εel Þ ¼ Pel cog N þ Pel cond N
The chemical energy of fuel charging the production of heat in the heating plant is calculated from the equation:
Q_ EUFhp G
(15)
where: Q_ e nominal flux of heat, EUFhp G e gross energy utilization factor of the replaced heating plant.
(19)
Hence the relative energy savings of fuels has the following form:
DE_ ch 1 1 1 1 ¼ þ scog N EUFhp G EUFCHP G EUFpp N ð1 εel ÞEUFCHP G Q_ 1 1 þ scond N hE cond N ð1 εel ÞEUFCHP G (20) scog N ¼
E_ ch hp e flux of the chemical energy of fuel charging the separate production of heat in the heating plant, E_ ch pp e flux of the chemical energy of fuel charging the separate production of electricity in replaced power plant, E_ ch cog e flux of the chemical energy of fuel charging the cogeneration of heat and electricity in IGCC-CHP plant.
Pel cog N Pel G P Q_ Q_ þ þ el cond N EUFhp G EUFpp N EUFCHP G EUFCHP G hE cond N (18)
(14)
where:
E_ ch hp ¼
(17)
Including Eqs. (15)e(17) Into (14) we have:
6. Savings of the chemical energy of fuel
DE_ ch ¼ E_ ch hp þ E_ ch pp E_ ch cog
Q_ þ Pel G Pel cond N E_ ch cog ¼ EUFCHP G hE cond N
Pel cog N Q_
scond N ¼
Pel cond N Q_
(21)
(22)
where: scog N e net power to heat ratio in cogeneration, scond N e ratio of net power in condensation mode to heat. Fig. 4 presents the results of calculating the relative savings of chemical energy of fuels obtained in the two analyzed cases of IGCC-CHP plants and in order to compare, average relative savings concerning a back-pressure CHP plant fired with coal and combined gas and steam CHP plant fired with natural gas. The following data have been used: for both cases of IGCC-CHP plants e EUFhp G ¼ 0.9; Case 1 e EUF G1 ¼ 0.7855, scog N1 ¼ 0.52505, EUFpp N1 ¼ hE cond1 ¼ 0.3661, εel1 ¼ 0.2959, scond N1 ¼ 0.3464; Case 2 e EUF G2 ¼ 0.8521, scog N2 ¼ 0.36905, EUFpp N2 ¼ hE cond2 ¼ 0.3319, εel2 ¼ 0.3704, scond N2 ¼ 0.232465. For both analyzed variants values
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Fig. 4. Relative savings of chemical energy of fuels; b-p e back-pressure.
have been quoted, either directly taking over Table 2 or calculated on the data contained in Table 2, excepting the values of energy efficiency of the condensing part of the turbine obtained directly by simulative calculations. In the case of back-pressure CHP it was assumed that the energy efficiencies of the replaced heating plant and a CHP plant amounts to 0.88, whereas the net energy efficiency of the replaced power plant is equal 0.43 and the ratio of power to heat amounts to 0.4. The combined gas and steam CHP plant is characterized by the following input data: energy efficiency of heating plant and cogeneration plant are the same amounting 0.9, ratio of power to heat is equal 0.9 and net energy efficiency of replaced power plant amounts to 0.514. In both cases of IGCC-CHP plants the results of relative energy savings of chemical energy of fuels are similar on the average level of 0.635. In comparison with this, in classical back-pressure CHP plant fired with coal relative energy savings are lower and amount to 0.48. In the case of a combined gas and steam CHP plant fired with natural gas the relative savings of chemical energy of fuel are highest amounting to 0.75. From the viewpoint of energy effectiveness (relative energy savings of the chemical energy of fuels are the most adequate measure of cogeneration effectiveness) everyone of analyzed technologies of cogeneration is profitable in comparison with the separate production of heat and electricity. IGCC-CHP technologies give better results than classical CHP fired with coal but not as favourable as combined gas and steam CHP plant fired with natural gas. 7. Sensitivity analysis The index of relative savings of the chemical energy of fuels is the most adequate measure of the energy effectiveness of cogeneration. Calculated as a difference between the consumption of the chemical energy of fuels in a CHP plant and in the case of separate production of heat and electricity it depends on arbitrarily assumed reference energy efficiencies of a heating plant and a power plant. In compliance with the Directive on the promotion of cogeneration [23] these reference energy efficiencies are obligatory from the viewpoint of EU energy statistics. But they may also be reference energy efficiencies characteristic for each given country or its region. Then they will differ from the reference values quoted in the Directive. Thus, the reference energy efficiencies concerning the separate production of heat and electricity may differ. Therefore in this case sensitivity analysis is justified. Fig. 5 presents the results of sensitivity analysis concerning relative savings of the chemical energy of fuels in the case of IGCCCHP plants. It has been assumed that the reference energy efficiencies of a heating plant and a power plant may changed within
Fig. 5. Influence of changes of energy efficiencies of power plant and heating plant on the index of savings of the chemical energy of fuels; b ebasic case.
the range of ±2%. From the sensitivity analysis it results that this leads to a change of relative savings of the chemical energy of fuels by about ±4.5% in relation to the basic value in the case of changes of the efficiency of a power plant and ±3.5% in a heating plant, respectively. When these changes concern both plants of separate production do occur both in a power plant and a heating plants, we obtain a change of the index of relative savings of the chemical energy of fuels on the level of ±8%. 8. Conclusions CHP plants integrated with installations of coal gasification (IGCC-CHP) are at the beginning of their development, although IGCC power plants have been operated for 25 years. Installations of coal gasification are the source of waste heat. Therefore process integration is not the only possibility of joining the heat cycle of the gas turbine with the heat cycle of the steam turbine, but also of recovering the waste energy from the cooling of syngas as well as from interstage cooling of the compressors and its utilization in a CHP plant. Results of the simulation of two variants of IGCC-CHP plants obtained by means of their mathematical model constructed in the professional software [29] were the base of the analysis of energy indices. Two cases of gasifiers, the entrained flow system and fluidized bed gasifier with CO2 recirculation have been analyzed. Besides the traditional EUF (energy utilization factor), the coefficient of heat performance and the index of relative energy savings thanks to cogeneration have been analyzed, too. The COHP (coefficient of heat performance) has been analyzed for all six fluxes of heat delivered to the district heating system. Higher values of COHP in the case of waste heat recovery result from the lower thermal parameters. It proves that waste heat replaces the heat flux from the bleeder with a high value of the power to heat ratio (more favourable cogeneration). The index of savings the chemical energy of fuels in relation to heat production is an adequate measure of the energy effectiveness of cogeneration. The results obtained in the analyzed case of IGCC-
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CHP plants are higher than the results of classical CHP plant but they are lower than relative energy savings concerning a gas and steam CHP plant [21]. Changes of reference energy efficiencies of a heating plant and a power plant (separate production of heat and electricity) influence considerably the index of the savings of the chemical energy of fuels, particularly if changes of energy efficiencies of both kinds of plants are considered. Acknowledgements 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” No SP/E/3/77008/10 funded by the Polish National Centre for Research and Development within the strategic program of research and development: “Advanced energy generation technologies”. References [1] Minchener AJ. Coal gasification for advanced power generation. Fuel 2005;84: 2222e35. [2] Maurstad O. An overview of coal based integrated gasification combined cycle (IGCC) technology. Massachusetts Institute of Technology Laboratory for Energy and the Environment; September 2005. Publication no MIT LFEE 2005002 WP. [3] Hashimoto T, Sakamoto K, Kitagawa Y, Hyakutake Y, Setani N. Development of IGCC commercial plant with air-blown gasifier. Mitsubishi Heavy Ind Tech Rev June. 2009;46(2). [4] Rakowski J. Review of technological problems connected with gasification of solid fuels for energy purposes (in Polish). Energetyka September 2003: 591e601. [5] Stahl K, Neergaard M. IGCC power plant for biomass utilization Varnamo, Sweden. Biomass Bioenergy 1998;15(3):205e11. [6] A fluidized bed air biomass gasification chp plant with an externally fired evaporative gas turbine cycle, Project performance summary. http://ec. europa.eu/energy/renewables/bioenergy/doc/gasification/027bm_367_1992. pdf Belgium. [7] Report from Vresova: 12 years of operating experience with the world's largest coal-fuelled IGCC. (Power plant operating experience). October 2008. http://goliath.ecnext.com. [8] Fahlen E, Ahlgren EO. Assessment of integration of different biomass gasification alternatives in a district heating system. Energy 2009;34:2184e95. [9] Difs K, Watterlund E. Biomass gasification opportunities in a district heating system. Biomass Bioenergy 2010;34(5):637e51. [10] Marin-Sanchez JE, Rodriguez-Toral MA. An estimation of cogeneration potential by using refinery residuals in Mexico. Energy Policy 2007;(35): 5876e91.
˛ zko _ [11] Chmielniak T, Scia M, Sobolewski A. Fluidized bed gasification of coal in a CO2 atmosphere (in Polish). Karbo 1/2013, 6e15. [12] Malik T, Liszka M, Zie˛ bik A. A concept of a CHP plant based on coal gasification in the reactor with CO2 recircualtion (in Polish). Karbo 4/2014, 188e194. [13] Malik T, Stanek W, Liszka M, Zie˛ bik A. Thermoeconomic analysis of IGCC-CHP plant equipped with CO2 removal. In: 9th Conference on Sustainable Development of Energy, Water and Environment Systems; September 20-27, 2014. Venice-Istanbul. [14] Irfan MF, Usman MR, Kusakabe K. Coal gasification in CO2 atmosphere and its kinetics since 1948: a brief review. Energy 2011;36:12e40. [15] Svoboda K, Pohorelý M, Jeremi as M, Kameníkov P, Hartman M, Skoblja S, et al. Fluidized bed gasification of coaleoil and coalewatereoil slurries by oxygenesteam and oxygeneCO2 mixtures. Fuel Process Technol 2012;95:16e26. [16] Oki Y, Inumarua J, Hara S, Kobayashi M, Watanabea H, Umemotoa S, et al. Development of oxy-fuel IGCC system with CO2 recirculation for CO2 capture. Energy Proc 2011;4:1066e73. [17] Kunze C, Spliethoff H. Assessment of oxy-fuel, pre- and post-combustionbased carbon capture for future IGCC plants. Appl Energy 2012;94:109e16. [18] Romano MC, Lozza GG. Long-term coal gasification-based power with nearzero emissions. Part B: zecomag and oxy-fuel IGCC cycles. Int J Greenh Gas Control 2010;4:469e77. ska K, Kotowicz J. Modeling and analysis [19] Skorek-Osikowska A, Janusz-Szyman of selected carbon dioxide capture methods in IGCC systems. Energy 2012;45: 92e100. [20] Horlock JH. Cogeneration e combined heat and power (CHP) thermodynamics and economics. Malabar, Florida: Krieger Publishing Company; 1997. [21] Szargut J, Zie˛ bik A. Fundamentals of thermal engineering (in Polish) PWN, Warszawa. 2000. [22] Danziger R. Cogeneration technology. The 1991 National Energy Management Forum e June 24 and 25, 1991, Melbourne, Australia. [23] Directive 2004/8/EC of the European Parliament and of the Council of 11 February 2004 on the promotion of cogeneration based on useful heat demand in the internal energy market and amending Directive 92/42/EC. [24] Zie˛ bik A, Budnik M, Liszka M. Thermodynamic indices assessing the integration of coal-fired CHP plants with post-combustion CO2 processing units (CPU). Energy Convers Manag 2013;73:389e97. [25] Zie˛ bik A, Budnik M, Liszka M. Analysis of energy indices of a power plant adapted for the production of heat integrated with the amine CO2 processing unit. J Clean Prod 2015:13e22. [26] Solli C, Anantharaman R, Strømman AH, Zhang X, Hertwich EG. Evaluation of different CHP options for refinery integration in the context of a low carbon future. Int J Greenh Gas Control 2009;3(2):152e60. ^ Harvey S, Berntsson T. Technical, environmental and economic [27] Marbe A, analysis of co-firing of gasified biofuel in a natural gas combined cycle (NGCC) combined heat and power (CHP) plant. Energy 2006;31(10e11):1614e31. [28] Sciubba E. Modeling, simulation and optimization of a syngas desulfurization device. Report RSE/2009/195. [29] Thermoflow, Inc., 29 Hudson Road, Sudbury, MA 01776 USA, http://www. thermoflow.com. [30] Liszka M, Malik T, Budnik M, Zie˛ bik A. Comparison of IGCC (integrated gasification combined cycle) and CFB (circulating fluidized bed) cogeneration plants equipped with CO2 removal. Energy 2013;58:86e96.
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Energy journal homepage: www.elsevier.com/locate/energy
Thermodynamic evaluation of CHP (combined heat and power) plants integrated with installations of coal gasification Andrzej Zie˛ bik*, Tomasz Malik 1, Marcin Liszka 2 Silesian University of Technology, Institute of Thermal Technology, Konarskiego 22, 44-100 Gliwice, Poland
a r t i c l e i n f o
a b s t r a c t
Article history: Received 9 January 2015 Received in revised form 23 April 2015 Accepted 1 June 2015
Integration of a CHP steam plant with an installation of coal gasification and gas turbine leads to an IGCCCHP (integrated gasification combined cycle-combined heat and power). Two installations of coal gasification have been analyzed, i.e. pressurized entrained flow gasifier e case 1 and pressurized fluidized bed gasifier with CO2 recirculation e case 2. Basing on the results of mathematical modelling of an IGCCCHP plant, the algorithms of calculating typical energy indices have been derived. The following energy indices are considered, i.e. coefficient of heat performance and relative savings of chemical energy of fuels. The results of coefficients of heat performance are contained between 1.87 and 2.37. Values exceeding 1 are thermodynamically justified because the idea of cogeneration of heat and electricity based on combining cycles of the heat engine and heat pump the efficiency of which exceeds 1. Higher values concerning waste heat replace more thermodynamically effective sources of heat in CHP plants. Relative savings of the chemical energy of fuels are similar in both cases of IGCC-CHP plants and are contained between the lower value of the CHP (combined heat and power) plants fuelled with coal and higher value of CHP plants fired with natural gas. © 2015 Elsevier Ltd. All rights reserved.
Keywords: Gasification Cogeneration Waste heat Thermal integration Coefficient of heat performance Relative savings of fuels
1. Introduction Although the technology of coal gasification has been applied in the chemical industry for several years, only in the eighties and nineties of the last century it was applied in IGCC (integrated gasification combined cycle) power units. In these years four IGCC plants were constructed, i.e., Wabash River and Tampa Electric in USA, Demkolec Bugggenum in the Netherlands and Elcogas Puertollano in Spain [1,2]. The fifth IGCC power plant which was built in 2008 is located in Nakoso in Japan [3]. Besides coal also the byproducts of crude oil refinery (petroleum coke and asphalt), biomass, sludge, waste from pulp and paper industry are gasified. The IGCC power plants, mentioned above produce only electricity (the power rating is about 300 MWel of each). IGCC power plants have some experience thanks to about 25 years operation, whereas IGCC integrated with combined power and heat units are only at the beginning of their development. In literature we can generally meet cases of small cogeneration units
* Corresponding author. Tel.: þ48 322371049; fax: þ48 322372872. E-mail addresses: [email protected] (A. Zie˛ bik), [email protected] (T. Malik), [email protected] (M. Liszka). 1 Tel.: þ48 322371757; fax: þ48 322372872. 2 Tel.: þ48 322372852; fax: þ48 322372872. http://dx.doi.org/10.1016/j.energy.2015.06.003 0360-5442/© 2015 Elsevier Ltd. All rights reserved.
integrated with installations of biomass or municipal wastes gasification. For example in Schwarze Pumpe [4] operated a gasification system fed with lignite and municipal wastes. In this plant existed two possibilities of its operation, i.e., cogeneration path (combined heat and power) with a power rating of 75MWel and chemical path (synthesis of methanol). The small pilot cogeneration system integrated with a gasification installation operated in the years 1996÷2000 in Varnamo (Sweden) [5]. The parameters of gasifier e 2 MPa; 950÷1000 C, LHV of syngas e 5 MJ/Nm3. Steam parameters e 4 MPa, 450 C. Energy utilization factor amounted to 83%. The demonstration IGCC e CHP plant fed with biomass came into being in Belgium [6]. The atmospheric gasifier with a fluidized bed was applied. The power rating of the demonstrating plant amounts to 0.5 MWel. In the coming years power rating is predicted to amount to 2 MWel. The IGCC plant operating in Vresova (Czech Republic) [7] is equipped with 26 Lurgi gasifiers and one new Siemens gasifier. The overall power rating of this system amounts to 400 MWel. Gasifiers are fuelled with lignite. The enthalpy of hot flue gases is used to preheat network water in the district heating system. In this way the idea of cogeneration is realized (IGCC-CHP). The additional production of cogenerated heat leads to an increase of the EUF (energy utilization factor) of this system by about 4 percentage points in comparison with an IGCC power plant.
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180
Nomenclature
ref tt
Main symbols B exergy E energy P power rating Q_ flux of heat T temperature
Abbreviations AGR acid gas removal ASU air separation unit BHE basic heat exchanger BIGCC biomass integrated gasification combined cycle C, COM compressor CC combustion chamber CCU CO2 compression unit CF Carnot factor CFB circulating fluidized boiler CHP combined heat and power CL conditioning line COHP coefficient of heat performance COP coefficient of performance DHS district heating system DHWP district heating water preheater E expander EUF energy utilization factor FW feed water GT gas turbine HP high-pressure HRSG heat recovery steam generation IGCC integrated gasification combined cycle LHV lower heating value LP low-pressure MP medium-pressure PHE peak heat exchanger WGSR water gas shift reactor
Greek symbols D increase ε relative loss h efficiency s power to heat ratio Subscripts a ambient ch chemical cog cogeneration cond condensing E energetic el electric G gross h heat hp heating plant in inlet m average thermodynamic N net out outlet pp power plant
In Ref. [8] the idea of adapting the existing combined gas and steam cycle fuelled with natural gas to IGCC plant fed with biomass and co-fired with natural gas together with syngas has been proposed. In this way the a so-called BIGCC (Biomass Integrated Gasification Combined Cycle) is realized. An exemplary economical analysis has been performed basing on the existing combined gas €teborg with heat. It has been and steam cycle Rya providing Go proved that in the case of biomass promotion such a modernization €ping has been is profitable. This solution as a new concept for Linko considered in Ref. [9]. The economical result of such an enterprise depends on obligatory regulations in law. Such a solution is favourable because of the reduction of CO2 emissions. The BIGCC e CHP plant with a power rating of 2 MWel and heat flux amounts to 4 MWth operated in Austria [9]. The paper [10] presents analysis of utilizing the wastes from a crude oil refinery in gasifier in order to produce heat and electricity in CHP plant. The construction of such IGCC-CHP plants near refineries in Mexico city is considered to cover the demand for heat and electricity. In fact, excepting one case (Vresova [7]), literature describes only small IGCC-CHP plants fired mainly with biomass or municipal wastes but operating large IGCC power plants [1e3] may also be considered as a base for the adaptation aiming at the integration of IGCC plants with CHP units. The IGCC-CHP system consisting of two main subsystems, i.e., production and cleaning of syngas and CHP plant. If CO2 removal is considered, the system is extended by an ASU (air separation unit) and module of CO2 removal and compression. Only cryogenic ASU provides adequate efficiency of oxygen production. From the
reference transformation and transmission
experience concerning hitherto operation of IGCC power plants the pressurized flow dry-feed gasifier is to be recommended. The advantages of this technology are among others high efficiency, high degree of fuel conversion, fuel flexibility, a low share of methane and pollutants in syngas. Disadvantages are large demands for oxygen and high temperature of syngas. In the case of CO2 removal the water gas shift reactor is indispensable. The removal of CO2 and H2S is generally realized by physical absorption (Selexol, Rectisol e most often used solvents). The purified syngas contains above 90% of H2. For the combustion of syngas the GT (gas turbines) designed for combustion of natural gas have been adapted. The HRSG (heat recovery steam generator) may be additionally equipped with an interstage reheater. The steam from HRSG is delivered to the steam turbine on several levels of pressure. As the authors of [11] have stressed the application of coal gasification in the fluidized bed reactor with CO2 recirculation leads to a reduction of investment and operation costs of installation. The utilization of CO2 as gasifying medium besides oxygen and steam is possible thanks to Bouduard's reaction. In results CO besides H2 is the main component of syngas. In the fluidized process gasification with CO2 recirculation the char is also produced for the combustion of which an oxy-fuel fluidized boiler (CFB) is applied. The application of oxy-combustion in the boiler of char is justified because it allows to avoid the separation of CO2 from the mixture of N2 and O2. Only separation of H2O is needed. The traditional line of conditioning and treatment of syngas as in entrained flow gasifier has been substituted by cleaning of syngas from solid particles and its hot desulphurization [12]. Thanks to
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the elimination of some irreversible thermodynamical processes it may be expected that the fluidized bed gasifier with CO2 recirculation will be characterized by a higher exergy efficiency than the entrained flow gasifier [13]. But on the other hand the part of modules belonging to the fluidized bed gasifier with CO2 recirculation did not achieve the adequate degree of maturity. It concerns mainly cleaning and desulphurization of hot syngas. A separate problem is GT in which oxy-combustion technology as in the char boiler has been applied. Although, as mentioned earlier, the maturity of some parts of fluidized bed gasifier with CO2 recirculation is not satisfying in literature there are some conceptions concerning this gasifier. The authors of [14] investigated the influence of thermal parameters (pressure and temperature) on gasification. They stress that applying CO2 in gasification processes influence the reduction of NOx and allow to control the temperature in the gasifier. The analysis of gasification process in the fluidized bed reactor by means of CO2 and steam mixture has been carried out in Ref. [15]. According to the opinion presented in Ref. [15] this way of gasification is suitable in the case of coal with a high share of volatile matter and biomass. The advantage of CO2 recirculation is a simultaneous utilization of CO2 as gasifying medium and transporting agent. The conception of an Oxy-IGCC system with recirculation of CO2 has been presented in Ref. [16]. In this system nitrogen was replaced by CO2, which is provided to the gasifier. Some part of flue gases (mainly CO2 and H2O) is recirculated to GT after compression. It limits the nitrogen input to the system. The authors of [17] analyzed future systems of IGCC among others Oxy-IGCC. In the latter case the recirculation of flue gases from the HRSG outlet has been proposed in order to reduce the temperature of flue gases before the expander of GT. In Ref. [18] the oxy-fuel IGCC system has also been presented. Nitrogen was substituted by the CO2 as transporting agent. Syngas cooled down to 850 C has been preliminarily cleaned from solid particles in cyclones and next after expansion and cooling down to 550 C finally cleaned by means of filter. Due to the jointed removal of CO2 and SO2 desulphurization has not been assumed. A part of outlet flue gases (mainly CO2 and H2O) is recirculated to the combustion chamber of GT in order to control the temperature before the expander of GT. The remaining part of CO2 after the condensation of H2O has been cleaned of N2 and Ar in the cryogenic installation and next compressed for its transport. The cooling of the blades is realized by means of CO2 from the compressor. The paper [19] is devoted to the analysis of CO2 capture methods proposed in IGCC plants. Two methods have been analyzed, i.e., chemical absorption and membrane CO2 separation. Most authors pay attention not only to thermodynamical advantages of Oxy-IGCC plant with CO2 recirculation but also to disadvantages, besides those already mentioned (cleaning and desulphurization of hot syngas) also problems concerning oxy-combustion of syngas and operation of GT expander. These problems result from different properties of CO2 in relation to air. Therefore this leads to the modification of the traditional GT. Usually the EUF (Energy Utilization Factor) [20] is used for the evaluation of energy affects of heat and electricity cogeneration. The more adequate measures of the effectiveness of CHP plants are COHP (coefficient of heat performance) also called partial energy efficiency of heat production [21] as well as relative savings of chemical energy of fuels in a CHP plant in comparison with the separate production of heat and electricity. Both these indices are the subject matter in this paper. The cogeneration (polygeneration) process is characterized by the main product and by-product (cogeneration) or by-products (polygeneration). The decision concerning the choice of the main
181
product depends on which product of the co(poly)generation process decides about the capacity of the main installations. The choice of the main product and by-product is the first step in the way of dividing input fuel charging the main product and by-products and in the case of economical aspects (general problem) the division of the costs. In the monograph [21] the method of the division of the costs (of input fuels, too), basing on the replaced process has been described. This method is also known as the so-called “method of avoided costs”. It may be advisable to add that in USA this method is approved by the law act known as PURPA (Public Utility Regulatory Policies Act) [22]. In literature we meet most often the so called “arithmetical” partial efficiencies, mainly concerning electricity production. They are calculated in the simple way dividing the production of electricity (or heat) by the entire consumption of the chemical energy of fuel. Calculated in this way partial energy efficiencies of electricity and heat production are devoided both of the thermodynamic and economical sense [21], although they may be useful in calculations of PES (Primary Energy Savings) [23]. Among the literature mentioned above items concerning energy indices which are in detail discussed in Refs. [24,25] two items, i.e. [26] and [27] are worth noticing. The authors of [26] treated electricity similarly as the authors of [21] using the term an additional product, whereas the authors of [27] applied method of avoided input fuels optionally for heat or electricity. 2. Conceptions of IGCC-CHP plants The paper is devoted to two conceptions of IGCC-CHP plants concerning firstly the entrained flow gasifier and in the second case to fluidized bed reactor with CO2 recirculation. Both cases of CHP plants are equipped with an extractionecondensating turbine with two bleeders for the district heating system. The first case concerns a solution tested in practice in IGCC power plants [1e3]. The second case is prospective technology promising from the viewpoint of thermodynamic irreversibility reduction but still requires final solution of some technological aspects (among others desulphurization of hot syngas) [17,28]. Fig. 1 presents the schematic diagram of an IGCC plant with pressurized dry-feed gasifier fired with coal. After cooling, syngas is delivered to the conditioning line consisting of a scrubber, COS hydrolysis reactor and WGSR (water gas shift reactor). Syngas is cleaned from solid particles of ash in cyclone, ceramic filter and scrubber. Solid fractions are usually partially recirculated to the gasifier. NH3, HCN, HCl and NaCl are absorbed in the scrubber. In the additional reactor of hydrolysis COS is converted to H2S and this latter acid gas is removed in the H2S absorber. The conversion of CO to CO2 proceeds according to reaction of WGSR (water gas shift reactor). After the WGSR syngas contains mainly H2 and CO2 as well as an inconsiderable amounts of CH4, N2, Ar and impurities (mainly compounds of sulphur). Oxygen with a purity of 95% is produced in the cryogenic installation of ASU. Nitrogen, the by-product of ASU can be used for the pneumatic transport of fuel. Acid gases (H2S and CO2) are removed by means of physical absorption. This method consist in the solving of CO2 and H2S in solvents without chemical reactions. The efficiency of H2S removal amounts to 99,5%. In the case of CO2 we have 98%. This process should be applied when the share of acid gases is relatively high. This process is characterized by a low energy consumption and high selectivity of H2S and CO2 removal. The module AGR contains also compressors of CO2. Syngas from AGR is delivered to the heat cycle. The CHP plant is equipped with the F-class GT (gas turbine), triple-pressure HRSG (heat recovery steam generator) and extractionecondensating steam turbine. The steam turbine is equipped with bleeders of heating steam feeding the heat exchangers of the district heating system.
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Fig. 1. Schematic diagram of IGCC CHP plant with entrained flow gasifier; ASU e Air Separation Unit; G e Gasifier; CL e Conditioning line; WGSR e Water Gas Shift Reactor; AGR e Acid Gas Removal; CHP e Combined Heat and Power; C e Compressor; CC e Combustion Chamber; E e Expander; HP e High Pressure; MP- Medium Pressure; LP e Low Pressure; GT - Gas Turbine; FW - Feed Water; HRSG e Heat Recovery Steam Generator; DHWP e District Heating Water Preheater; BHE e Basic Heat Exchanger; PHE e Peak Heat Exchanger; Q_ DHS - Heat flux for district heating system; E_ CHF e Flux of chemical energy of fuel; E_ CHS e Flux of chemical energy of syngas; Q_ C e Heat flux of water cooling; H_ e Flux of enthalpy; DH_ e Increase of enthalpy flux from installation of waste heat recovery; Pel_i e Internal consumption of electricity.
Most of the waste steam and heat from the technological modules (gasifier with cooler of syngas and conditioning line) is utilized within the CHP plant. Fig. 2 presents a schematic diagram of an IGCC-CHP plant with pressurized fluidized bed gasifier with CO2 recirculation considered as a gasifying agent besides oxygen and MP steam. After the gasifier syngas is exported for hot cleaning from solid particles and next to the conditioning line where it is cooled down prior to H2S absorption. After desulphurization in AGR, the cleaned syngas is delivered to combustion chamber of GT together with oxygen and CO2. GT is the F-class turbine adapted for flue gases from combustion of syngas in the atmosphere of CO2 and oxygen. The blades of GT are cooled by the part of CO2 from GT compressors. The experiences concerning existing IGCC systems show that the GT of F-class met with success in the case of syngas fuelling [1e3]. Outlet flue gases from GT are delivered to the triple-pressure HRSG in which HP steam (high-pressure), MP steam (mediumpressure) and low-pressure steam are produced. Outlet flue gases from HRSG are fed to the preliminary heat exchanger of the district heating system. The cooling of outlet flue gases after HRSG below the saturation point temperature is possible because syngas contains minute quantities of sulphur compounds. The char, by-product of gasifier is combusted in the oxycombustion CFB boiler. Leave steam from boiler of char together with fluxes of steam from HRSG are delivered to the extractioncondensing turbine. From the low-pressure bleeders of the steam turbine basic (BHE) and peak (PHE) heat exchangers of district heating system are fed. The waste heat recovery for the purpose of preheating water in
district heating networks is realized in interstage coolers of compressors in ASU and CO2 CCU (compression unit). 3. Results of simulative calculations Mathematical modelling of the IGCC-CHP plants which are presented in the schematic diagrams (Figs. 1 and 2) has been carried out using professional software [29]. This is computer application making it possible to develop thermodynamic models of energy systems. These models are assembled with components available in the library of this software. The components are particular elements of IGCC-CHP system e.g. gasifier, heat exchangers. Firstly, the set of components have been chosen and next the structure of energy system is constructed by means of adequate links between components. After checking the correction of these links by the software, the input data are entered to the model. The input data include parameters of the components and information about fluxes of input and output agents. The mathematical model may run in the mode “design” or “off-design”. In this paper models in the mode “design” are analyzed and all calculated values concern nominal parameters. Tables 1 and 2 present selected input parameters concerning simulative calculations and results of simulations while in Table 3 syngas composition at the outlet of gasifier has been presented. The obtained results show that the second case is characterized by higher EUF factors than in the case 1. However, in the case 1 the net electric power is almost 55 MW higher than in the second case, while the heat production remains on the same level in both cases. Comparing chemical energy of syngas in each stage of conversion,
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Fig. 2. Schematic diagram of IGCC-CHP with fluidized bed gasifier with recirculation of CO2; the explanation of abbreviations is the same as concerning Fig. 1.
Table 1 Main input parameters concerning simulative calculations. Parameter
Gasifier pressure Temperature of syngas leaving gasifier Type of solvent for H2S removal in AGR Pressure ratio in GT Temperature of flue gases entering expander of GT Live steam temperature Live steam pressure Reheated steam temperature Reheated steam pressure Condenser pressure
Unit
Results Case 1
Case 2
MPa C e e C
42.38 1460.9 Selexol 14.88 1350
34 900 MDEA 19.38 1263
C MPa C MPa kPa
565 12.8 565 3.95 5
565 18 565 3.95 5
Table 2 Selected results of simulations. Parameter
Unit
Results Case 1
Case 2
Steam turbine power Gas turbine power Gross electric power Net electric power Net electric power of condensing part Relative internal consumption of electricity Total heat flux for DHS Chemical energy of fuel LHV of coal Chemical energy of syngas leaving gasifier/ entering conditioning line LHV of syngas entering conditioning line Chemical energy of syngas entering AGR LHV of syngas entering AGR Chemical energy of syngas entering gas turbine LHV of syngas entering gas turbine Chemical energy of slag/char EUFG EUFN
MWe MWe MWe MWe MWe %
85.54 162.00 247.54 174.29 69.28 29.59
105.39 85.69 191.08 120.30 46.493 37.04
MWth MWch MJ/kg MWch
200.00 569.73 20.16 445.76
200.00 458.95 22.91 267.84
MJ/kg MWch MJ/kg MWch MJ/kg MWch % %
9.27 402.85 6.51 398.27 30.33 4.87 78.55 65.70
7.34 267.63 7.89 264.71 7.99 122.38 85.21 69.79
in the first case the values are higher than in the second case. This happens due to the lower electricity production in case 2 and also due to lower carbon conversion in gasifier. Lower carbon conversion in the gasifier results in char production, which is fed to the CFB boiler. Due to the absence of WGSR and CO2 capture process in AGR module, syngas fed to the GT is rich in CO2 and unconverted CO, thus the LHV is definitely lower than in the case 1, which results from the high content of H2 in the syngas. 4. Analysis of waste energy sources and DHS fluxes of heat Technological modules (gasifier with syngas cooling system and conditioning line) are sources of waste steam production (highpressure HP, medium-pressure MP, low-pressure LP). These fluxes of waste steam are provided into the superheaters of HRSG (case 1 and 2) and also into oxy-combustion char boiler (case 2) and next fed to the steam turbine generating electricity. The recovered waste heat from the conditioning line, from interstage cooling of compressors in ASU as well as interstage cooling of CO2 compressors is utilized in the district heating system [30]. In case 1 the gasifier (evaporative cooling) together with the syngas cooling system and conditioning line are sources of HP and MP waste steam. The HP waste steam from the gasifier is superheated steam (453 C), whereas the HP waste steam from the conditioning line is saturated vapour. Both these fluxes are supplied to the superheater of HRSG and next feed the HP (high-pressure) part of steam turbine. The MP waste steam (saturated vapour) from the gasifier and the conditioning line serve only for process aims.
Table 3 Syngas composition at the gasifier outlet. Composition, mol % H2
CO2
H2O
CO
N2
H2S
COS
CH4
BTX
Other
Case 1 24.010 5.728 12.700 48.920 8.205 0.381 0.028 0.001 0.000 0.027 Case 2 14.915 21.430 11.599 46.217 2.608 0.375 0.042 2.458 0.025 0.331
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This MP waste steam together with the part of the outlet flux from the HP part of the steam turbine is used in the gasifier and the conditioning line (WGSR). The remaining part of the outlet steam from the HP part of the steam turbine together with MP steam from HRSG is passed to the interstage reheater and next to the MP part of the steam turbine. The conditioning line is also a source of LP waste steam on two levels of pressure, i.e., 0.8 and 0.45 MPa. The flux of LP waste steam 0.8 MPa is delivered together with the flux of LP steam from HRSG to the inlet of LP2 part of the steam turbine (Fig. 1). The flux of LP waste steam 0.45 MPa serves partially to the cover of the internal heat consumption in AGR module and the remaining part is applied to the preheating of syngas before the combustion chamber of the gas turbine. Summing up, the fluxes of waste steam from the gasifier with the syngas cooler system and from the conditioning line utilized in the steam turbine are sources of about 13.3 MWel which amounts to about 5.4% of the entire power rating of the gross electric power, 4.4% provided by the waste from the gasifier and the remaining part from the conditioning line. In the second case (fluidized bed reactor with CO2 recirculation presented in Fig. 2) the evaporative cooling of the gasifier is a source of MP saturated waste steam (252.6 C) which is next passed to the superheaters of HRSG and oxy-combustion char boiler. The waste production of HP steam (360 C) is realized in the syngas cooler system (conditioning line). This steam is also superheated in HRSG and the char boiler. From both these sources of waste steam utilized in the steam turbine the power electricity amounts to 6 MWel. This is 3.1% of gross electric power, 2.2% provided by the waste steam from the conditioning line. Generation of waste heat for the purpose of preheating the network water of district heating system is realized in the module of the conditioning line, in the air separation unit and in the CO2 compressors. First of all, the fluxes of waste heat are utilized to preheat the district heating network water. Next a DHWP (district heating water preheater) situated at the outlet of HRSG is applied, thanks to which the temperature of flue gases is decreased. The BHE (basic heat exchanger) and PHE (peak heat exchanger) are fundamental parts of the district heating system. In case 1 the share of waste heat in heat production is about 28% whereas in case 2 only 20%. The share of DHWP and PHE in heat production is the same in both cases and amounts to 6% and about 33%, respectively. The amounts of waste heat as well as information about heat fluxes generated in DHWP, BHE and PHE heat exchangers have been gathered in Table 4. Each of DHS heat fluxes is connected with the different range of temperature of preheated network water which characterize a quality of heat defined by the Carnot Factor (CF) [21]:
CF ¼
Tm Ta Tm
(1)
where: Ta e ambient temperature, Tm e average thermodynamic temperature of district heating network water. The average thermodynamic temperature Tm is defined as follows [21]:
Tm ¼
Tout Tin ln TTout in
where: Tout e outlet temperature,
(2)
Table 4 Fluxes of heat for DH system. Source of heat flux
Case 1 Q_ DHS MWt
Tm, K
CF
Case 2 Q_ DHS MWt
Tm, K
CF
Conditioning line of syngas CO2 compressors ASU compressors District heating water preheater Basic heat exchanger Peak heat exchanger
32.4
372.2
0.2611
15.4
373.2
0.2611
6.8 16.6 12.6
364.9 367.8 372.2
0.2464 0.2523 0.2611
10.4 13.9 12.0
367 362.5 369.9
0.2507 0.2414 0.2566
64.5 67.1
373.2 392.9
0.2631 0.3001
81.2 67.1
370.7 392.9
0.2582 0.3001
Tin e inlet temperature. The Carnot Factors as a measure of the quality of heat serve for the determination of the coefficient of heat performance [21]. By-production of electricity using the waste steam from evaporative cooling of gasifier as well as from the cooling system of syngas and by-production of heat for the purpose of district heating system are the effects of the external utilization of waste energy. Besides this there also exist in IGCC-CHP systems internal utilization of waste energy, usually more effective than the external one [21]. In case 1 preheating of cleaned syngas takes place before the combustion chamber of GT using recirculated hot syngas and utilized waste MP steam from AGR in the gasifier and conditioning line. The first way of internal utilization of waste energy has also been applied in case 2. Moreover, the CO2 recirculated into the fluidized bed gasifier is preheated by means of hot syngas cooling water. The thermodynamic analysis of internal utilization of waste energy generated in IGCC is not dealt with in this paper.
5. Coefficient of heat performance The idea of dividing input fuels (in the economical approach to the costs) between useful products of co(poly)generation process based on the principle that the fuel consumption charging the byproduct results from the avoided fuel consumption in the replaced process. Usually a CHP plant is constructed from the viewpoint of covering the demand for heat. It means that heat is the main product (at least in the heating season). Then electricity generated in the cogeneration process (no condensing mode) is a by-product. Basing on the principle of avoided consumption of fuel in replaced process, the production of electricity in cogeneration should be charged by such a consumption of the chemical energy of fuel as in the power plant operated in accordance with the same technology (constructed at the same time) and delivering the same amount of electricity to the consumer. The Directive [23] and guidance to it precises the criteria of the choice of the reference (replaced) power plant. This approach leads to the formula [21]: cog E_ ch el ¼
Pel cog G 1 εel cog htt h0tt hE pp N
(3)
where: cog E_ ch el e flux of the chemical energy of fuel charging the production of electricity in cogeneration mode of IGCC-CHP plant, Pel cog G e gross power rating of cogeneration mode of IGCC-CHP plant, εel cog e index of the relative internal consumption of electricity,
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htt ; h0tt e the efficiencies of transformation and transmission of electricity from IGCC-CHP plant and from replaces power plant, respectively, hE pp N e net energy efficiency of replaced (reference) power plant. The remaining part of electricity is generated in the condensing mode. The chemical energy of fuel charging the production of electricity in the condensing part of the IGCC-CHP plant is calculated from the equation:
P cond E_ ch el ¼ el cond N hE cond N
(4)
where: cond E_ ch el
e flux of the chemical energy of fuel charging the production of electricity in condensing part of IGCC-CHP plant, Pel cond N e net power rating of condensing part of IGCC-CHP plant, hE cond N e net energy efficiency of condensing part of IGCC-CHP plant. The production of electricity in cogeneration leads to savings of the chemical energy of fuels in comparison with separate production of heat and electricity because it is produced on the stream of heat for district heating systems, whereas the production of electricity in condensing mode takes place on the stream of steam passed to condenser. Thus, the consumption of the chemical energy of fuel charging the production of heat flux delivered to the district heating system results from: cog cog cond E_ ch h ¼ E_ ch IGCCCHP E_ ch el E_ ch el
(5)
The chemical energy of fuel charging the production of heat for district heating system consists of the following components cog E_ ch h ¼ E_ ch DHWP þ E_ ch BHE þ E_ ch PHE þ E_ ch CL þ E_ ch ASU þ E_ ch COM
(6) where E_ ch DHWP , E_ ch BHE , E_ ch PHE , E_ ch CL , E_ ch ASU , E_ ch COM denote fluxes of the chemical energy of fuel charging the heat production in DHWP, BHE, PHE, CL, ASU and AGR, respectively. The first item concerns the production of heat in the preliminary district heating water preheater located in HRSG. The two next ones express the basic and peak part of heat production based on steam fluxes from the low-pressure bleeders of the steam turbine. The last ones denote waste heat fluxes from the conditioning line and installations of interstage coolers of ASU and CO2 compressors. Introducing the coefficient of heat performance, defined as follows:
COHPi ¼
Q_ i _ Ech h i
(7)
We obtain Eq. (6) in the following form: cog E_ ch h ¼
Q_ i COHP i i¼1
n X
(8)
where: COHPi e coefficient of heat performance in i-th source of DHS heat production,
185
Q_ i e flux of DHS heat production form i-th source of heat including installation of waste heat recovery, E_ ch h i e flux of the chemical energy of fuel charging the production of i-th flux of heat, n e the number of heat fluxes with various levels of thermal parameters. In order to solve Eq. (8) we must introduce (n-1) additional equations describing the relations between the particular coefficients of heat performance. To solve this problem the exergy method has been applied, the flux of the chemical energy of fuel is proportional to the flux of the exergy of heat. It means that we can write:
DB_ i E_ ch i ¼ DB_ ref E_ ch ref
(9)
where: E_ ch i e flux of the chemical energy of fuel of i-th DHS heat production, E_ ch ref e flux of the chemical energy of fuel of the reference DHS heat (one case conventionally chosen from the set of DHS heat fluxes), DB_ i e flux of exergy of i-th DHS heat flux, DB_ ref e flux of exergy of reference DHS heat flux. The flux of exergy of the i-th heat flux is calculated from the equation:
DB_ i ¼ Q_ i CFi
(10)
where CFi denotes the Carnot factor characterizing the i-th flux of heat defined according to Eq. (1). The values of the Carnot factor concerning fluxes of heat from the installation of waste heat recovery (conditioning line, interstage cooling of the compressors in ASU and AGR are calculated in the section devoted to the analysis of waste energy sources) (Table 4). Basing on Eqs. (1), (7), (9) and (10) we can write:
CFref ðCOHPÞi ¼ ðCOHPÞref CFi
(11)
If conventionally DHWP (district heating water preheater) is considered as a reference one, basing on Eqs. (3)e(7) and (11), we have:
COHPDHWP ¼
1 CFDHWP
P _ Q i CFi i
P E_ ch IGCCCHP hel cog N Phel cond N E pp N
(12)
E cond N
and
COHPi ¼ COHPDHWP
CFDHWP CFi
(13)
where i denote BHE, PHE, CL, ASU and AGR, respectively. Fig. 3 presents the results of the analysis of the coefficient of heat performance concerning the particular fluxes of heat including waste heat recovery from technological installations. It is thermodynamically justified that the values of COHP exceed 1 because the concept of heat and electricity cogeneration results from joining the heat cycles of the engine and the heat pump [21]. In the latter case the Coefficient of Performance always exceeds one. In the case of waste heat recovery higher values of COHP are caused by lower
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In Eq. (15) it has been assumed that the efficiency of transporting the heat from the IGCC-CHP plant and the heating plant are the same. The chemical energy of fuel charging the production of electricity in the replaced power plant is expressed by the Formula (3) in which it has been assumed that htt ¼ h0tt :
Pel cogN E_ ch pp ¼ EUFpp N
(16)
where EUFpp N ¼ hEppN denote energy utilization factor concerning replaced IGCC power plant. The flux of the chemical energy of fuel charging the cogeneration of heat and electricity in an IGCC-CHP plant results from Eqs. (4) and (5): Fig. 3. Coefficient of heat performance.
thermal parameters. It means that heat from the installations of waste energy recovery replaces heating steam from the bleeders of the steam turbine providing a higher power to heat ratio which is the quality factor of cogeneration.
The EUF (energy utilization factor) expressing the overall energy efficiency of a CHP plant is not a sufficiently adequate measure of energy effectiveness of heat and electricity cogeneration. A better measure than EUF is the COHP (coefficient of heat performance) analyzed in the previous section, but a quite adequate measure of the energy effectiveness of heat and electricity cogeneration is the saving of the chemical energy of fuel in comparison with the separate production of heat and electricity. Savings of the chemical energy of fuels are calculated based on the assumption that the demand for heat and electricity by the consumers are provided from both, the cogeneration system and the separate producers of heat and electricity. This assumption also refers to the nominal flux of heat and power rating. Savings DE_ ch of the chemical energy of fuel result from the difference between the consumption in separate production of heat and electricity and the consumption in the cogeneration process:
where: Pel G e gross power rating, EUFCHP G e gross energy utilization factor.
DE_ ch ¼
where
Pel G ð1 εel Þ ¼ Pel cog N þ Pel cond N
The chemical energy of fuel charging the production of heat in the heating plant is calculated from the equation:
Q_ EUFhp G
(15)
where: Q_ e nominal flux of heat, EUFhp G e gross energy utilization factor of the replaced heating plant.
(19)
Hence the relative energy savings of fuels has the following form:
DE_ ch 1 1 1 1 ¼ þ scog N EUFhp G EUFCHP G EUFpp N ð1 εel ÞEUFCHP G Q_ 1 1 þ scond N hE cond N ð1 εel ÞEUFCHP G (20) scog N ¼
E_ ch hp e flux of the chemical energy of fuel charging the separate production of heat in the heating plant, E_ ch pp e flux of the chemical energy of fuel charging the separate production of electricity in replaced power plant, E_ ch cog e flux of the chemical energy of fuel charging the cogeneration of heat and electricity in IGCC-CHP plant.
Pel cog N Pel G P Q_ Q_ þ þ el cond N EUFhp G EUFpp N EUFCHP G EUFCHP G hE cond N (18)
(14)
where:
E_ ch hp ¼
(17)
Including Eqs. (15)e(17) Into (14) we have:
6. Savings of the chemical energy of fuel
DE_ ch ¼ E_ ch hp þ E_ ch pp E_ ch cog
Q_ þ Pel G Pel cond N E_ ch cog ¼ EUFCHP G hE cond N
Pel cog N Q_
scond N ¼
Pel cond N Q_
(21)
(22)
where: scog N e net power to heat ratio in cogeneration, scond N e ratio of net power in condensation mode to heat. Fig. 4 presents the results of calculating the relative savings of chemical energy of fuels obtained in the two analyzed cases of IGCC-CHP plants and in order to compare, average relative savings concerning a back-pressure CHP plant fired with coal and combined gas and steam CHP plant fired with natural gas. The following data have been used: for both cases of IGCC-CHP plants e EUFhp G ¼ 0.9; Case 1 e EUF G1 ¼ 0.7855, scog N1 ¼ 0.52505, EUFpp N1 ¼ hE cond1 ¼ 0.3661, εel1 ¼ 0.2959, scond N1 ¼ 0.3464; Case 2 e EUF G2 ¼ 0.8521, scog N2 ¼ 0.36905, EUFpp N2 ¼ hE cond2 ¼ 0.3319, εel2 ¼ 0.3704, scond N2 ¼ 0.232465. For both analyzed variants values
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Fig. 4. Relative savings of chemical energy of fuels; b-p e back-pressure.
have been quoted, either directly taking over Table 2 or calculated on the data contained in Table 2, excepting the values of energy efficiency of the condensing part of the turbine obtained directly by simulative calculations. In the case of back-pressure CHP it was assumed that the energy efficiencies of the replaced heating plant and a CHP plant amounts to 0.88, whereas the net energy efficiency of the replaced power plant is equal 0.43 and the ratio of power to heat amounts to 0.4. The combined gas and steam CHP plant is characterized by the following input data: energy efficiency of heating plant and cogeneration plant are the same amounting 0.9, ratio of power to heat is equal 0.9 and net energy efficiency of replaced power plant amounts to 0.514. In both cases of IGCC-CHP plants the results of relative energy savings of chemical energy of fuels are similar on the average level of 0.635. In comparison with this, in classical back-pressure CHP plant fired with coal relative energy savings are lower and amount to 0.48. In the case of a combined gas and steam CHP plant fired with natural gas the relative savings of chemical energy of fuel are highest amounting to 0.75. From the viewpoint of energy effectiveness (relative energy savings of the chemical energy of fuels are the most adequate measure of cogeneration effectiveness) everyone of analyzed technologies of cogeneration is profitable in comparison with the separate production of heat and electricity. IGCC-CHP technologies give better results than classical CHP fired with coal but not as favourable as combined gas and steam CHP plant fired with natural gas. 7. Sensitivity analysis The index of relative savings of the chemical energy of fuels is the most adequate measure of the energy effectiveness of cogeneration. Calculated as a difference between the consumption of the chemical energy of fuels in a CHP plant and in the case of separate production of heat and electricity it depends on arbitrarily assumed reference energy efficiencies of a heating plant and a power plant. In compliance with the Directive on the promotion of cogeneration [23] these reference energy efficiencies are obligatory from the viewpoint of EU energy statistics. But they may also be reference energy efficiencies characteristic for each given country or its region. Then they will differ from the reference values quoted in the Directive. Thus, the reference energy efficiencies concerning the separate production of heat and electricity may differ. Therefore in this case sensitivity analysis is justified. Fig. 5 presents the results of sensitivity analysis concerning relative savings of the chemical energy of fuels in the case of IGCCCHP plants. It has been assumed that the reference energy efficiencies of a heating plant and a power plant may changed within
Fig. 5. Influence of changes of energy efficiencies of power plant and heating plant on the index of savings of the chemical energy of fuels; b ebasic case.
the range of ±2%. From the sensitivity analysis it results that this leads to a change of relative savings of the chemical energy of fuels by about ±4.5% in relation to the basic value in the case of changes of the efficiency of a power plant and ±3.5% in a heating plant, respectively. When these changes concern both plants of separate production do occur both in a power plant and a heating plants, we obtain a change of the index of relative savings of the chemical energy of fuels on the level of ±8%. 8. Conclusions CHP plants integrated with installations of coal gasification (IGCC-CHP) are at the beginning of their development, although IGCC power plants have been operated for 25 years. Installations of coal gasification are the source of waste heat. Therefore process integration is not the only possibility of joining the heat cycle of the gas turbine with the heat cycle of the steam turbine, but also of recovering the waste energy from the cooling of syngas as well as from interstage cooling of the compressors and its utilization in a CHP plant. Results of the simulation of two variants of IGCC-CHP plants obtained by means of their mathematical model constructed in the professional software [29] were the base of the analysis of energy indices. Two cases of gasifiers, the entrained flow system and fluidized bed gasifier with CO2 recirculation have been analyzed. Besides the traditional EUF (energy utilization factor), the coefficient of heat performance and the index of relative energy savings thanks to cogeneration have been analyzed, too. The COHP (coefficient of heat performance) has been analyzed for all six fluxes of heat delivered to the district heating system. Higher values of COHP in the case of waste heat recovery result from the lower thermal parameters. It proves that waste heat replaces the heat flux from the bleeder with a high value of the power to heat ratio (more favourable cogeneration). The index of savings the chemical energy of fuels in relation to heat production is an adequate measure of the energy effectiveness of cogeneration. The results obtained in the analyzed case of IGCC-
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