Comparative Analysis of Alternative Configurations of the Mercury 50

Article pubs.acs.org/EF

Comparative Analysis of Alternative Configurations of the Mercury 50 Recuperated Gas-Turbine-Based Biomass Integrated Gasification Combined Heat and Power (BIGCHP) Plant Jacek Kalina* Institute of Thermal Technology, Silesian University of Technology, Konarskiego 22, 44-100 Gliwice, Poland ABSTRACT: Biomass integrated gasification combined heat and power (BIGCHP) technology is an interesting option for global CO2 emission reduction and fossil fuel savings. In this paper, several original configurations of the cogeneration system based on different gasification technologies and Mercury 50 recuperated gas turbine are proposed and examined theoretically. The energy conversion performance of the gasification island is investigated using an in-house built Engineering Equation Solver (EES) quasi-equilibrium model of the process. The gaseous fuel-fired cogeneration plant is modeled using the GateCycle simulation software. The results are compared in terms of electric energy generation efficiency, biomass energy utilization factor, CO2 emission reduction, and fossil fuel energy savings. It was found that both gasification technology and plant configuration have significant influence on the results. Nevertheless, the performance of the plant in the fields of emission reduction and fossil fuel energy savings is very encouraging. In some of the considered design cases, the net efficiency of power generation is higher than 30%. The amount of nonrenewable energy saved within the regional energy system is greater than the biomass energy input into the cogeneration plant. To justify the use of the proposed technology, an initial economic analysis of a sample investment project is presented.

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INTRODUCTION Carbon dioxide emission reduction and reasonable use of the available nonrenewable energy resources are nowadays the biggest issues of the development of the energy sector. In this aspect, the biomass integrated gasification combined heat and power (BIGCHP) is considered as one of the most effective technologies. In comparison to traditional biomass combustion, the integrated gasification plants represent a higher level of power generation efficiency.1−3 Dornburg et al.3 presented that the highest relative primary energy savings that result from using biomass can be obtained with atmospheric and pressurized integrated biomass gasification combined cycle cogeneration plants. An amount of the nonrenewable primary energy that is replaced within a regional energy system by a cogeneration plant can be higher than 1.0 GJ/GJ of the biomass energy input.3,4 According to Walter et al.,5 in the middle run, both co-fired and pure integrated biomass gasification plants can be a better option than capture and storage of CO2. It has already been demonstrated in projects ARBRE (U.K.), Värnamo (Sweden), Güssing (Austria), and others2,6 that a variety of technological schemes of power plants can be designed and successfully operated with medium-scale reactors. There are currently many ongoing research and development activities in the field.7 Technical, environmental, and economic performances of the integrated biomass gasification power and cogeneration plants have been analyzed by many authors (Caputo et al.,1 Larson et al.,2 Dornburg at al.,3 Kalina,4 Walter et al.,5 Klimantos,6 Marbe et al.,8,9 Rodrigues et al.,10 Brown et al.,11 Zwart,12 Franco et al.,13 and others). The common conclusion is that the technology is attractive because it leads to the highest level of energy effectiveness and emission reduction. In most studies, however, it is presented that profitability of investment projects is poor and © 2011 American Chemical Society

significantly affected by the scale of a plant. In addition, investment projects are feasible if biomass is available within a relatively small distance from the designed location of a plant. Dependent upon many different factors, it is typically between 25 and 100 km.14 Another key problem of the successful commercialization of the technology is the commercial availability of reliable and efficient gas turbines (GTs) modified for syngas operation.5,6,10,12 Nowadays, because of emission reduction and renewable energy policies that have been adopted in many countries, there are available financial and legal mechanisms that significantly support new investment initiatives in the field of biomass energy conversion. There is now a great opportunity for implementation and further development of thermodynamically effective biomass energy conversion technologies. The aim of this work is to examine a potential for CO2 emission reduction and savings of the primary energy of fossil fuels that come with the BIGCHP technology. This is being analyzed together with the current economic attractiveness of a sample investment project. It is assumed that the plant is located in Poland, and therefore, the study takes into account the localization-specific conditions. An advanced medium-scale recuperated GT-based cogeneration plant is taken into account. The machine has relatively high thermal efficiency. In addition, the on-site consumption of electricity is relatively low because of the low compression ratio of the turbine. Therefore, the Special Issue: International Conference on Carbon Reduction Technologies Received: October 19, 2011 Revised: November 28, 2011 Published: November 29, 2011 6452

dx.doi.org/10.1021/ef201624h | Energy Fuels 2012, 26, 6452−6465

Energy & Fuels

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Therefore, the flow of fuel gas is smaller, and the power consumption for compression is reduced. Using the integrated gasification and combustion double circulating fluidized-bed reactor technology helps to solve gasification waste-substance-related problems. The main driving force for using biomass as a fuel in the energy sector is the reduction of fossil fuel consumption and global CO2 emission. It is assumed that the existing generation facilities are replaced if the biomass-fueled plants are introduced into the regional energy system at a fixed level of energy demand. In Polish conditions, about 85% of electricity is generated from hard and brown coal. Diversification of the fuel consumption structure is highly required. The electricity from renewable sources and natural-gas-fired cogeneration is nowadays supported by different legal and financial means. Consequently, it can be assumed that, with a high probability, the replaced electricity will be the one from the coal-fired plants. Therefore, it is decided to assess the potential fuel energy savings and emission reduction with respect to coal. Two indices of technology performance are used. These are global reduction of CO2 emission (under assumption that the firing of biomass is CO2-emission-neutral) and energy replacement index (ERI). The second index shows the amount of energy from fossil fuels that is saved within the regional energy system using renewable energy in a cogeneration plant (in gigajoules of nonrenewable energy per gigajoule of biomass energy input)

foreseen advantages of the proposed system are high net efficiency of electricity generation, significant reduction of CO2 emission, and substantial savings of nonrenewable primary energy. The plant is an excellent candidate for a base load block in many municipal heating systems in Polish conditions.15 When it is taken into account that the technology can be applied in many distributed locations, replacing existing coalfired central heating plants, a great cumulative effect can be expected.

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ALTERNATIVE PLANT CONFIGURATIONS

The plant is based on the Mercury 50 Solar Turbine Incorporated GT model.16 The machine is of a modular design. Each of the major components, including combustor, turbine, compressor, and recuperator, can be replaced independently. The design of the combustion system of the turbine has virtually no impact on the rotating equipment.17 The system has been conveniently located at one end of the engine, and therefore, it is likely to be adapted for different innovative solutions. According to Lundberg et al.,18 the combustion system of the Mercury 50 is to be adaptable to future firing with biomass- and coal-derived fuels. The machine has already been considered as a potential candidate for some innovative GT cycles.18−21 A total number of seven alternative designs of the system are examined that are numbered A.1−A.3.1. Different biomass gasification technologies and different configurations of the cogeneration plant are taken into account. Characteristics of particular alternative solutions are given in Table 1. The base structure of the plant within the alternative designs A1, A2, and A3 is shown in Figures 1−3.

ΔmCO2 = Δmcoal LHVcoalWEcoal + Eel WE ref ⎛ EUF − η ⎞ el 3.6WE = Eel⎜⎜ ⎟ coal + WE ref ⎟ ⎝ ηel ηb ⎠ Δmcoal LHVcoal +

Table 1. Characteristics of Alternative Plant Designs alternative design A.1 A.1.1 A.1.2 A.2 A.2.1 A.3 A.3.1

gasification technology autothermal atmospheric fluidized bed (AFB) AFB AFB autothermal pressurized fluidized bed (PFB) PFB allothermal fast internally circulated fluidized bed (FICFB) FICFB

ERI =

3.6Eel ηref,system

m wood LHVwood EUF − ηel ηel = + ηb ηref,system

cogeneration plant cycle combined gas and steam turbine (CC) CC with supplementary firing simple (SC) CC

(1)

(2)

where

Eel = Eel,gen(1 − α) − Eel,fss

(3)

3.6Eel m wood LHVwood

(4)

SC CC

ηel =

SC

EUF =

A simple gasification technology is an advantage of the alternative design A.1. The disadvantages are considerable gas-cleaning requirements and high consumption of power for compression of large amounts of the low-calorific-value GT fuel gas. The parameters of steam within the bottoming steam turbine cycle are relatively low because of the low temperature of GT exhaust gas. Within the configuration A.1.1, there is a supplementary firing applied. It leads to an increased electric and heating power of the plant. On the other hand, however, there is an increased demand for wet biomass and considerable heat consumption for drying purposes. In another alternative design A.1.2, a simple GT cycle is proposed. The heat for the heating network is generated at heat recovery water boilers using hot producer gas and GT exhaust gas. Within this configuration, there is no bottoming steam cycle, which results in a lower investment cost. Configurations A.2 and A.2.1 are designed on the basis of pressurized fluidized-bed gasification technology. There is no demand for producer gas compression, and gas-cleaning requirements are significantly reduced. In the alternative designs A.3 and A.3.1, the allothermal gasification technology is applied using pure steam as the gasification agent. This technology leads to a much higher calorific value of the GT fuel gas.

σ=

3.6Eel + Q m wood LHVwood

ηel 3.6Eel = Q EUF − ηel

(5)

(6)

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MODELING OF THE BIOMASS CONVERSION PROCESS The type of feedstock used in the analysis is spruce in the form of chips. Proximate analysis of the dry fuel resulted in the following characteristics (% wt, dry basis): fixed carbon, 28.3%; volatile mater, 70.2%; and ash, 1.5%. Composition of the wood is (% wt, dry basis): carbon (C), 51.2%; hydrogen (H), 6.1%; oxygen (O), 40.9%; and nitrogen (N), 0.3%. A higher heating value of the dry biomass is HHVdb = 20.1 MJ/kg. It is assumed that the initial water content of biomass is 40% of mass (wet basis). The feedstock is dried to 10% of the water content22 using a rotary drum drier. In each case, the drying medium is a mixture of GT exhaust gas after the heat recovery boiler and ambient air. In the configuration A.1.1, a small amount of producer gas is burned to provide all of the heat 6453


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Figure 1. Scheme of the BIGCHP plant with an atmospheric fluidized-bed gasifier, a GT, and a bottoming steam cycle, design A.1 (AC, air compressor; BH, bleed air heater; BEX, bleed air expander; BF, bag filter; C, cyclone or cooler; CC, combustion chamber; CO, condenser; D, drum; DAH, drying air heater; DEA, deaerator; FGF, flue gas fan; FH, fuel heater; GC, gas compressor or gas cooler; GC/EV, gas cooler/evaporator; GR, gasification reactor; NWH, network water heater; P, pump; R, recuperator; RDD, rotary drum drier; SCV, screw conveyor; SH, superheater; ST, steam turbine; T, turbine; TC, tar cracker; WH, water heater; and WSC, wet scrubber).

necessary for drying. A schematic diagram of the rotary drum drier section is given in Figure 4. The drum drier is designed to operate at the pressure slightly lower than the atmospheric pressure. The draft fan is located after the drier. The applied value of the underpressure is 5 kPa. The temperature of the drying medium at the inlet of the drier is 140 °C. According to Bolhàr-Nordenkampf et al.,23 the advantages of using the lowtemperature flue gas for the drying process are low exergy input into the dryer and low organic emissions. In this work, because of the relatively big size of wood chips and low temperature of heating medium, the emission of organic compounds and corresponding loss of carbon are neglected. The total mass balance of the drying process takes the form

Finally, the energy balance of the drying process can be written 4 T Ḣ wood,in + ṁ dm( ∑ giΔhi|Texh 0 i=1

+ Xdm,inh H2O|Tdm ,(z H O)in p ) 4 T = Ḣ wood,out + ṁ dm( ∑ giΔhi|Tout 0 i=1

+ Xdm,outhH2O|Tout ,(z H O)out p ) + Q̇ out dm 2

Ḣ wood = ṁ wood,db(1 + wdb)c wet(Twood − T0)

(10)

The dry drying medium is assumed to be composed of N2, O2, CO2, and Ar. The heat capacity of wet wood is calculated using correlation given by Regland et al.24

(7)

c wet =

The balance of moisture is as follows:

(cdry + 4.19wdb) 1 + wdb

+ (0.02355Twood

− 1.32wdb − 6.191)wdb

ṁ wood,dbwdb + ṁ dmXdm,in = ṁ wood,dbwdb,max + ṁ dmXdm,out

(9)

where the enthalpy of wet wood chips is calculated using the formula

ṁ wood,db(1 + wdb) + ṁ dm(1 + Xdm,in) = ṁ wood,db(1 + wdb,max ) + ṁ dm(1 + Xdm,out)

dm

2

cdry = 0.1031 + 0.003867Twood

(8) 6454

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Figure 2. Scheme of the BIGCHP plant with a pressurized fluidized-bed gasifier, a GT, and a bottoming steam cycle, design A.2 (HGF, hot gas filter; PGR, pressurized gasification reactor).

20−25%. Therefore, the operating pressure of the reactor is set to 1200 kPa. The operating temperature is 950 °C. The temperature of the gas at the GT inlet is assumed to be 400 °C to prevent tar condensation. The third technology is the fast internally circulated fluidized-bed process using pure steam as the gasification agent.26,27 The operating parameters of the gasification process are temperature at 850 °C and pressure at 120 kPa. The heat is delivered to the gasification process by the bed material circulating between the combustion and gasification zones. The temperature at the combustion section is 950 °C. To maintain this temperature, a fraction of the product gas is recirculated into the combustion section of the reactor unit. The gasconditioning section consists of the producer gas cooler, bag filter, and tar scrubber using rape oil methyl ester (RME) as the solvent.27 In each case, the performance of the gasification process is analyzed using the thermodynamic equilibrium-based approach. The thermodynamic equilibrium models are generally regarded as satisfactory for studies of energy systems.28 However, if unconstrained equilibrium of the chemical system of a fluidized-bed reactor is assumed, the results typically show overestimated mass conversion efficiency, heating value of the gas, and

It is assumed that the temperature of wood at the outlet of the drier is equal to the wet bulb temperature for the given pressure. Heat loss from the drier is assumed to be 3% of the total inlet enthalpy. The relative humidity of the drier outlet gas is controlled to be lower than 100%. From this condition, the demand for additional heating using a portion of producer gas is calculated. There are three main gasification technologies tested within the project. The first technology is autothermal atmospheric pressure fluidized-bed gasification using air as the gasification agent. The technology has been applied within the project ARBRE.22 The gasifier is operated at the pressure of 1.5 bar and temperature of 850 °C. The temperature is elevated to 920 °C in the secondary tar cracker. After the gas leaves the tar cracker, it is cooled to 180−200 °C in a steam generator before the bag filter. After the filter and before the solution scrubbing, there is a secondary cooling of the gas to 75 °C. The outlet fuel gas is saturated with water. The second technology is autothermal pressurized fluidizedbed gasification using air as the gasification agent. This technology has been used in the Värnamo gasification plant.25 The pressure required by the GT fuel delivery system is usually higher than the pressure of air at the GT compressor outlet by 6455


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Figure 3. Scheme of the BIGCHP plant with allothermal fluidized steam gasification, design A.3 (CR, combustion reactor; GF, gas fan; S, solvent separator; SC, solvent scrubber; SEP, water separator; and WC, ventilator cooler).

Figure 4. Schematic diagram of the drier system used for model development.

the form

generation of hydrogen and carbon oxide. There are usually underestimated yields of methane and higher hydrocarbons. Mevissen et al.29 presented that the differences between predicted and experimental data can be significant. Therefore, to make the study more realistic, a single-compartment quasi-equilibrium model is applied. The composition of the reactor product gas is determined by minimization of Gibbs free energy of the system in gaseous phase. Given that the chemical potential is equivalent to the partial free enthalpy of the component in the mixture and the mixture is a perfect solution of ideal gases at specified pressure p and temperature T, the objective function takes

ls

∑ ni[hi0(T ) − Tsi0(T , p) + RT ln zi] → min i=1

(13)

The assumed products i of gas-phase reactions at equilibrium are H2, CO, CH4, CO2, and H2O. Solid products leaving the reactor are ash and unconverted char of the following stoichiometric formula: CHc1Oc2Nc3. Tar, char, NH3, C2H4, and a portion of the total final yield of CH4 are considered to be the non-equilibrium products of the process. These components are just withdrawn from the substrates and bypass the calculation 6456


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The machine has been composed of a 10-stage axial compressor, recuperator, combustion chamber, and two-stage expander. The compressor is equipped with a variable inlet guide vane (IGV) that is followed by two stages of variable guide vanes (VGVs) that are interconnected and controlled as a unit for optimum compressor control. The first stage of the expander is fully cooled. The second stage incorporates cooled vanes and uncooled blades. The cooling air is taken from the recuperator outlet. The main design data of the Mercury 50 GT are given in Table 3.

Table 2. Predicted Characteristics of Raw Product Gas and GT Fuel Gas gasification system

AFB

PFB

GT fuel gas

product gas

raw gas

T (K) CO (%) H2 (%) CH4 (%) C2H4 (%) CO2 (%) H2O (%) N2 (%) Ar (%) tars (%) εC LHV (kJ N−1 m−3) V (N m3 kgdb−1) m (kg/kgdb) mair (kg/kgdb) mH2O (kg/kgdb)

1192 15.96 12.00 3.10 0.64 11.78 11.91 43.82 0.56 0.107 0.908 5009

573 17.09 12.85 3.31 0.69 12.62 5.91 46.93 0.60 0.0

raw gas

FICFB

GT fuel gas 673 16.33 11.87 3.16 0.65 11.50 12.23 43.47 0.56 0.108

5139

1223 16.33 11.87 3.16 0.65 11.50 12.23 43.47 0.56 0.108 0.903 5073

2.630

2.456

2.976 1.929 0.0

2.825

raw gas

GT fuel gas 573 23.69 42.69 9.02 1.63 17.02 5.91 0.05 0.00 0.0

5073

1123 18.52 33.37 7.05 1.27 13.31 26.26 0.04 0.00 0.029 0.850 9290

2.599

2.599

1.949

1.524

2.935 1.904 0.0

2.935

1.566 0.0 0.55

1.222

Table 3. Mercury 50 GT Design Data at ISO Conditions18

11789

of equilibrium. The details of the model are given in the text published in another journal.30 Table 2 presents predicted characteristics of raw and product gas from different gasification technologies that are taken into account in this study.

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MODELING OF GT PERFORMANCE Performance of the Mecury 50 GT is predicted using the commercially available simulation software GateCycle. The model is presented in Figure 5. In the case of firing the turbine with a low calorific value producer gas, the off-design simulation mode has been applied to all components of the system.

parameter

symbol

unit

value

Nett electric power power generation efficiency compressor inlet flow rate compressor pressure ratio recuperator air outlet temperature recuperator air outlet pressure natural gas inlet flow rate compressor air lost expander outlet flow rate combustor outlet temperature turbine rotor inlet temperature combustor pressure drop exhaust pressure drop speed expander isentropic efficiency compressor isentropic efficiency turbine and gear box mechanical efficiency generator efficiency recuperator efficiency

Pel ηel ṁ C,in PR TR,out TR,out ṁ NG,in ṁ air,loss ṁ EX,out Tmax TRIT Δpcomb Δpout N ηi,ex ηi,c ηm ηg εR

kW % kg/s

4570 41.5 16.651 9.33:1 894 910 0.23 0.09 16.79 1481 1436 3.0 3.8 14179 87.6 87.5 95.7 97.0 92.0

K kPa kg/s kg/s kg/s K K % % rpm % % % % %

In the first step, the model of the natural-gas-fired machine was built and tuned to match the main technical data at ISO conditions. The detailed specification of the turbine has been taken from Lundberg et al.18 It has to be stressed that the

Figure 5. GateCycle model of Mercury 50 GT. 6457


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Table 4. Results of Simulation of Mercury 50 GT-Based System alternative design

A.1

A.1.1

A.1.2

A.2

A.2.1

A.3

GT pressure ratio GT power (kW) bleed air temperature (K) bleed air mass flow rate (kg/s) bleed air expander power (kW) fuel gas compressor power (kW) booster compressor power (kW) GT efficiency (%) fuel gas temperature (K) turbine outlet temperature (K) exhaust temperature after supplementary firing (K) turbine outlet pressure (kPa) turbine outlet flow (kg/s) producer gas for GT (kg/s) producer gas for supplementary firing (kg/s) producer gas for wood drying (kg/s) producer gas recirculation to gasification (kg/s) total raw gas flow (kg/s) superheated steam pressure (kPa) superheated steam temperature (K) steam generation (kg/s) steam cycle electric power (kW) network heating power (kW) exhaust gas temperature after heat recovery (K) dry biomass flow (kg/s) biomass energy input (kW) cold gas efficiency of gasification (%) own power demand (kW) Nett electric power (kW) electricity generation efficiency (%) EUF (%)

9.61 5072 307.0 1.651 322.8 792.1 na 42.64 573.0 384.0 na 98.0 17.644 2.644 0 0 0 2.786 3000 600.0 1.95 724 4487 187.0 0.936 17568 67.25 375 4951 28.2 55.9

9.61 5072 823.0 1.651 462.0 792.1 na 42.64 573.0 384.0 873.0 98.0 17.644 2.644 1.1206 0.49314 0 4.486 4500 773.0 3.99 2139 8724 138.0 1.507 28290 67.25 560 6320 22.3 55.2

9.61 5072 973.0 1.651 549.2 792.1 na 42.64 573.0 384.0 na 98.0 17.644 2.644 0 0 0 2.786 na na na na 6298 150.0 0.936 17568 67.25 365 4464 25.4 63.3

9.56 5143 308 1.781 na na na 44.05 673.0 388.3 na 98.0 17.47 2.600 0 0 0 2.600 3000.0 605.0 2.19 813.62 4418 180.0 0.886 16624 67.31 358 5517 33.2 61.9

9.56 5143 308 1.781 na na na 44.05 673.0 388.3 na 98.0 17.47 2.600 0 0 3 2.600 na na 0 0 6305 150.0 0.886 16624 67.31 342 4720 28.4 68.4

9.60 5053 na 0

9.60 5053 na 0

A.3.1

372.6 na 44.07 573.0 366.0 na 98.0 17.455 0.780 0 0 0.342 1.338 3000.0 599.0 2.02 754 4589 186.0 0.887 16639 68.92 356 5079 30.5 60.2

372.6 na 44.07 573.0 366.0 na 98.0 17.455 0.780 0 0 0.342 1.338 na na 0 0 6186 150.0 0.887 16639 68.92 340 4340 26.1 65.3

to Paisley et al.,36 the gas must be preheated to at least 250 °C before it enters the combustion chamber. Therefore, the fuel gas heater FH is applied within the plant structure of the alternative designs A.1, A.1.1, A.1.2, A.3, and A.3.1. It is assumed that the fuel gas is heated to 573 K. The additional function of this heater is to ensure that the incoming gas is above its dew point. In the configurations A.2 and A.2.1, the fuel gas after the heat recovery boiler and hot gas-cleaning section has the temperature of 673 K. It is also assumed that the fuel gas is compressed to 1180 kPa, which is the pressure about 20% higher than the combustion pressure. This increased pressure ensures proper operation of the GT fueling system. In the case of the combined cycle plant, it is assumed that the extraction-condensing turbine is applied. Therefore, in full cogeneration mode, the minimum flow of steam through the condensing section is required at the level of 10% of steam input. The results of simulation are given in Table 4.

compression ratio of the machine given in different publications varies from 9.1:1 to 9.9:1. It can therefore be concluded that the machine has promising characteristics in the aspect of adaptation for a low-calorific-value gaseous fuel. The problem of modeling of the GT performance under off-design conditions, when the machine is fueled by a lowcalorific-value gas, has been widely discussed in the published literature.31−35 There are already known different strategies that allow us to accept the new fuel by the compressor−expander system. Within this study, the problem of an increased fuel mass flow rate is faced by bleeding air from the compressor. According to Palmer et al.,33 this strategy eliminates most of the potential surge margin problems. Additionally, it is assumed that the pressure ratio can increase by 3.5% when the machine is fired with the low-caloric-value producer gas. The increase in this range should be acceptable for the machine.32,34,35 In the alternative designs A.1, A1.1, and A.1.2, the bleed air is used for an additional power generation in BEX (see Figure 1). In the configurations A.2 and A.2.1, the bleed air is driven to the booster compressor and is used for the gasification process in the PFB reactor. The pressure ratio of the GT compressor is adjusted to balance the amount of air required for the gasification process. In the system with FICFB gasification technology, no bleeding of the air is required. This is due to the fact that the composition and calorific values of the fuel gas lead to an acceptable increase of the compressor outlet pressure. The temperature of the biomass-derived GT fuel gas has a significant impact on the operation of the machine. According

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ECONOMIC ASSESSMENT The economic attractiveness of renewable energy projects considerably depends upon the location of the plant and local incentives and supportive measures. The economic evaluation of the proposed technology is performed for Poland. Biomass in the country is considered as the main renewable source of energy. Nowadays, there is a high demand for new biomassfueled electric power generation facilities. Therefore, the financial support system has been established by the legal regulations.37−39 According to the law, production of electricity 6458


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Figure 6. Investment cost of the gasification system within a 95% confidence interval: (a) AFB reactor, (b) PFB reactor, and (c) atmospheric pressure allothermal CFB reactor.

delivered and heat produced in gaseous fuel-fired cogeneration. Therefore, in the configurations A.1.2, A.2.1, and A.3.1 of the plant, the electricity is eligible for the “yellow certificates”. In the case of the integrated gasification combined cycle plant, it is not possible to install measurement devices that would clearly indicate the amount of heat and electricity from gaseous fuelfired cogeneration. Because there is currently not such installation running in Poland, there is a demand for legal interpretation of the regulations. It is not clear if the plant is eligible for certificate of electricity origin from the gaseous fuel-fired cogeneration. Even if it is eligible, it is not known how to calculate the relevant number of the “yellow certificates”. Therefore, in this study, in the case of the combined cycle plant (alternatives A.1, A.1.1, A.2, and A.3), the “red certificates” of the lower market value are taken into account. The economic attractiveness of the project is expressed by means of the common profitability indices of investment projects: net present value (NPV), internal rate of return (IRR), and discounted payback period (DPB).

using renewable energy sources and production of electricity in cogeneration facilities is being confirmed by the tradable certificates of origin. The certificates are issued for the electricity measured at the generator output. Since the year 2010, the electricity from biomass-fueled cogeneration plants is eligible for both renewable and cogeneration certificates. This significantly improves the economic performance of investment projects. The plant can be classified as highly efficient cogeneration if the level of annual primary energy savings (PES) is not lower than 10%.37 The required value of total efficiency (EUF) is 80% for combined cycle plants and 75% in the case of simple-cycle GT with the heat recovery water boiler. If a plant does not reach this value, the generated electricity is divided into the electricity from cogeneration and the electricity generated apart from cogeneration.37 The certificate of origin from cogeneration is being issued separately for energy produced in gaseous fuel-fired cogeneration (so-called “yellow certificates”) and other types of plants (so-called “red certificates”). The market value of the certificate of origin from the gaseous fuel-fired cogeneration is much higher than the other certificate. In this study, the values of 127 PLN/MWh and 23 PLN/MWh are being assumed (end of 2010).40 Nowadays, a fuel gas obtained from processing of biomass is regarded as the gaseous fuel in the meaning of cogeneration regulations.37 In the case of simple-cycle GT and heat recovery for heating purposes, it is easy to measure the amount of gas

N

NPV =

∑ t=0

N

∑ t=0 6459

CFt (1 + r )t

CFt (1 + IRR)t

(14)

=0 (15) dx.doi.org/10.1021/ef201624h | Energy Fuels 2012, 26, 6452−6465

Energy & Fuels DPB

∑

Article

Table 5. Data Used for Equipment Costs

CFt

=0 (1 + r )t (16) t=0 General assumptions for the analysis are as follows: (i) The project is located in Poland, and cash flow calculations are performed in local currency (PLN). (ii) The plant will be built by an existing heating company and connected to a municipal heating network. (iii) The heat produced by the plant will replace the heat that is currently produced by hard coal-fired boilers of 82% thermal efficiency. (iv) The economic lifetime of the project is 15 years. (v) The annual plant availability is 90% (7884 h). (vi) The year of calculations is 2010. (vii) The project is financed in 30% by own capital and 70% by bank credit. No subsidies are taken into account. (viii) The discounted cash flow rate is r = 7.0%. (ix) The electricity selling price is 200 PLN/MWh. (x) The value of certificate of electricity origin from a renewable energy source is 270 PLN/ MWh. (xi) The value of CO2 reduction certificates is 60 PLN/ MWh. (xii) The value of saved coal is 300 PLN/ton. (xiii) The natural gas price (according to the tariff composed of fixed and variable parts) is 1.163 PLN N−1 m−3. (xiv) The ratio of the euro to PLN is 3.90, and the ratio of the USD to PLN is 2.88. The total investment cost (TIC) of the project was estimated on the basis of the particular equipment cost analysis. It was not an easy task because of the fact that the market in this field is weak and most of the available cost data refer to a relatively small number of pilot and research plants. In the first step, the cost of the gasification island was estimated using data available from different sources.1,8−10,41−46 On the basis of the given references, the specific cost curves have been elaborated. The curves are presented in Figure 6. The considered investment expenditures include the whole system from collection and processing of wet feedstock to clean the gas outlet. In the case of indirect allothermal steam gasification, the estimation of the investment cost is relatively weak, which is due to the small number of available data. According to the 2007−2008 Gas Turbine World Handbook,47 the budget price of the Mercury 50 GT system is 2 923 000 USD. It is being assumed that the cost of the machine modified for biomass-derived gas operations is 20% higher.10 The costs of the remaining equipment are calculated using the general equation:

EC = ECP(c1ECPc2) (USD)

equipment HRSG duct burners raw gas cooler/secondary evaporator gas−water heat exchangers backpressure condensing turbine fuel gas compressors bleed air expander gas−gas heat exchangers condenser, cooling towers, and water treatment stations connection to the NG distribution system turbine fuel supply system

c1

c2

Pel Pel Pel A STC

2462.9 11146.3 2462.9 450 7866.5 207357 14088 1899.2 0.175

−0.3122 −0.415 −0.3122 −0.18 −0.318 −0.723 −0.502 −0.292 0.0

GTC GTC

0.06 0.04

0.0 0.0

ECP Q̇ Q̇ Q̇ Q̇

Figure 7. Total and specific investment costs.

(17)

Equipment characteristic parameters ECP and coefficients c1 and c2 of eq 17 are given in Table 5. The estimated values of the TIC are presented in Figure 7. One of the major limitations for using biomass as a fuel in the energy production sector comes from problems with longterm continuity and cost of supply. This study is based on the fuel availability survey and supply chain optimization.14 All potential sources of biomass within the analyzed region were identified, and the potential amount of biomass was determined. Each source was characterized by the geographical location, total available amount of wood of different assortments within different periods, daily supply capacity, physical properties of biomass, and the specific price (loco source). On the basis of the actual road route map, each location was characterized by a transportation distance and real travel time. It was found that the optimized cost of wood varies daily depending upon biomass availability in particular resources.

Figure 8. Cost of delivered wet biomass (loco plant).

The average annual optimized cost of the biomass supply as a function of the annual consumption is presented in Figure 8. These values are used as a cost of fuel within the subsequent economic analysis.

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RESULTS AND DISCUSSION The performance of the plant at ISO conditions is presented in Figures 9 and 10. The highest level of the of net efficiency of electricity generation (in full cogeneration mode) is reached in alternative design A.2 (combined cycle integrated PFB gasification technology). On the other hand, the GT simple cycle in the alternative design A.2.1 offers the highest value of biomass 6460


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Figure 9. Nett electricity generation efficiency and energy utilization factor.

Figure 10. Nonrenewable energy replacement index and specific global CO2 emission reduction.

Table 6. Main Results of Annual Mass and Energy Balance alternative design number of hours in operation electricity generated [MWh (generator output, PF = 0.8)] plant own consumption (MWh) Nett electricity to grid (MWh) network heat (GJ) network heat from cogeneration according to ref 22 (GJ) electricity from cogeneration according to ref 22 (MWh) producer gas consumed (×106, N m3) wet biomass consumed (tons) biomass energy consumed (GJ) saved coal (tons) CO2 emission reduced (tons) nonrenewable energy saved (GJ) number of certificates of electricity origin (MWh) “green certificates” “yellow certificates” “red certificates”

A.1

A.1.1

A.1.2

A.2

A.2.1

A.3

A.3.1

47925 9142 38783 127352 110436 23380 65.248 44278 498635 6896 52092 543134

60101 10594 49507 247608 247608 34934 105.072 71300 802937 13409 76334 797030

44029 9064 34965 178752 100190 44029 65.248 44278 498635 9680 54360 567641

7884 46657 3442 43215 125393 125393 27925 65.336 41898 471833 6790 56136 585071

40284 3321 36963 178951 126330 40284 65.336 41898 471833 9691 56308 587861

45485 5703 39782 130247 77654 16500 27.608 41936 472257 7053 53390 556655

39579 5585 33994 175562 97835 38105 27.608 41936 472257 9507 53056 554040

47925 0 23380

60101 0 34934

44029 44029 0

46657 0 27925

40284 40284 0

45485 0 16500

39579 39579 0

energy utilization factor. These two design alternatives also lead to high values of nonrenewable energy replacement index (ERI) and specific global CO2 emission reduction within the regional energy system (calculated per gigajoules of biomass energy consumed). The simple-cycle configuration with the waste heat recovery water boiler offers slightly better energy and emission savings. The weakest performance of the plant is represented by the alternative design A.1.1 (AFB gasification technology integrated

with combined cycle plant with supplementary firing). All indices that are taken into account have the lowest value in this case. Although the configuration A.1.1 leads to the highest electric power of the system, the performance is poor because of the high demand for wet biomass, significant drying requirements, and relatively high fraction of electricity generated at the low-efficiency steam cycle. An interesting conclusion is that the FICFB gasification technology offers the energy and environmental effects better 6461


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Figure 11. Profitability indices of the sample investment project if no subsidies are available.

Figure 12. Profitability indices of the sample investment project located in Poland.

than the AFB technology but slightly worse than the PFB technology. The FICFB technology offers a relatively high calorific value of the product gas. On the other hand, the high demand for gas recirculation in the combustion zone of the reactor results in the net value of cold gas efficiency at the level of other gasification technologies. It has been noticed that, in each design case, the value of ERI is greater than 1.0 and the specific CO2 emission reduction is higher than the specific emission from hard coal (WEcoal = 94.85 kg/GJ48). It means that replacing coal-fired plants by the BIGCHP technology offers relatively high net energy and environmental effects. Table 6 presents the results of an annual mass and energy balance of the plant. The values given in the table have been used to calculate the annual cash flow CF and to assess the financial performance of the proposed system. Economic profitability analysis of the proposed technology shows that it is not able to compete effectively with fossil-fuelfired technologies without effective financial support. Because of the high initial investment cost, significant maintenance requirements, and shorter availability of the plant, the profitability indices are usually negative. Results of calculations of the NPV and break-even point of the electricity selling price in the case when no financial support is available are presented in Figure 11.

Poor economic effectiveness classifies the proposed solution as a potential technology of the future. It is foreseen that the attractiveness of projects will become better as a result of increasing prices of electricity and decreasing investment cost because of technology development and scale effects. Nowadays, however, the technology can be financially justified if the costs of development are paid by the society. In Poland, the effective policy promoting electricity generation from renewable resources currently results in a relatively good profitability of investment projects. The economic performance is highly influenced by a significant economic value of tradable certificates of electricity origin and CO2 emission reduction. The main economic indices of a potential investment project in Poland are shown in Figure 12. The best values of NPV, IRR, and DPB have been obtained for design alternatives A.1.2 and A.2.1 (GT simple cycle integrated with AFB and PFB gasification technology). The best financial performance of these two configurations are due to the fact that the generated electricity is eligible for the certificates of origin from the gaseous fuelfired cogeneration. The simple-cycle plant integrated with the FICFB gasification technology offers worse economic performance because of the high initial investment cost. The combined cycle plants integrated with either AFB or PFB gasification technology lead to worse effects because of high investment costs and lower income from the sale of the certificates of electricity origin. 6462


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Figure 13. Income structure of the sample investment project located in Poland.

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It can be observed in Figure 13 that the biggest portion of an annual income is generated by sale of “green”, “yellow”, and “red” certificates of electricity origin. Without the income from the certificates, the project is not financially justified. The calculated values of the investment capital discounted payback period are at the level of 6−14 years. When that is taken into account, the conclusion can be made that the current supporting mechanisms should be available at least within this time span. Within the Polish energy market, the uncertainties related to the legal regulations are nowadays one of most important barriers of the technology development.

■

CONCLUSION Using biomass in medium-scale GT-based integrated gasification cogeneration plants leads to very favorable energy and environmental effects. The advanced Mercury 50 GT offers high electricity generation efficiency, high savings of nonrenewable energy, and considerable global CO2 emission reduction. The design alternatives based on the GT simple cycle and heat recovery water boiler lead to better effects than the combined cycle arrangements. This is an important conclusion considering the relatively small power output of the plant. Nowadays, the BIGCHP technology is an economically attractive option only if there is an available effective financial stimulation. In such cases, although the initial investment costs are high, a potential investment project reaches positive values of profitability indices in all of the proposed alternative designs. The best effects are again obtained in the case of simplecycle plants integrated with either atmospheric or pressurized fluidized-bed gasification reactors.

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AUTHOR INFORMATION Corresponding Author *E-mail: [email protected].

■

ACKNOWLEDGMENTS This work was carried out within the frame of research project N N513 004036, titled Analysis and Optimization of Distributed Energy Conversion Plants Integrated with Gasification of Biomass. The project is financed by the Polish Ministry of Science. 6463

NOMENCLATURE c1 and c2 = cost-scaling coefficients CFt = annual cash flow DC = direct investment cost (PLN) gi = mass fraction of mixture component i EC = equipment purchase cost (USD) ECP = equipment characteristic parameter EIC = cost of electric interconnection and power output (USD) EUF = fuel energy utilization factor Eel = electric energy exported into the grid (MWh) Eel,gen = electric energy measured at the generator output (MWh) Eel,fss = electric energy consumption within the fuel supply sub-system (MWh) hi0 = standard enthalpy of pure component i (kJ/kmol) Ḣ = enthalpy flow (kg/s) GTC = gas turbine cost (USD) IDC = indirect investment cost (PLN) LHV = lower calorific value of solid fuel (kJ/kg) ls = number of gaseous components m = mass (kg) ṁ = mass flow (kg/s) ni = number of moles of component i (kmol) N = project lifetime p = pressure (kPa) PR = compressor pressure ratio PF = power factor r = discounted cash flow rate R = universal gas constant (8.314 kJ kmol−1 K−1) STC = steam turbine cost (USD) T = temperature (K) TEC = total equipment cost (PLN) Q = heat production (GJ) Q̇ out = heat lost from the drying process (kW) V = producer gas yield (N m3 kgdb−1) VLHV = volumetric lower heating value of the gas (kJ N−1 m−3) w = moisture content of wood (kg of H2O/kg) WEcoal = CO2 emission index for coal (WEcoal = 94.85 kg/ GJ48) WEref = CO2 emission index for the average system power plant (WEref = 963.36 kg/MWh48) dx.doi.org/10.1021/ef201624h | Energy Fuels 2012, 26, 6452−6465

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(11) Brown, D.; Gassner, M.; Muchino, T.; Maréchal, F. Thermoeconomic analysis for the optimal conceptual design of biomass gasification energy conversion systems. Appl. Therm. Eng. 2009, 29, 2137−2152. (12) Zwart R. Technical, Economic and Environmental Potential of Cofiring of Biomass and Waste in Natural Gas Fired Turbines and Combined Cycles. Energieonderzoek Centrum Nederland (ECN): Petten, The Netherlands, 2003; ECN Report ECN-RX-03-003 (http://www.ecn.nl). (13) Franco, A.; Giannini, N. Perspectives for the use of biomass as fuel in combined cycle power plants. Int. J. Therm. Sci. 2005, 44, 163− 177. (14) Zogłowek, J.; Kalina, J.; Górny, K. Wooden biomass feedstock availability analysis and optimization of biomass supply system for energy production. In Proceedings of the 13th International Symposium on Heat Transfer and Renewable Sources of Energy (HTRSE 2010); Stachel, A. A., Mikielewicz, D., Eds.; Szczecin-Mied̨ zyzdroje, Poland, Sept 9−12, 2010; ISBN: 978-83-7663-035-9. (15) Decree of the Ministry of Economy issued on 14th August 2008 on a particular obligation of abtaining and submitting for cancelation the certificates of origin of electricity and heat from renewable energy sources, and obligation of confirmation of the data about the amounts of electricity and heat produced from a renewable source. Polish Journal of Law 156/2008, position 969 (in Polish). (16) Solar Turbines Incorporated. Mercury 50 Product Brochure; Solar Turbines Incorporated: San Diego, CA (www.solarturbines.com). (17) Fant, D. B.; Jackson, G. S.; Karim, H.; Newburry, D. M.; Dutta, P.; Smith, K. O.; Dibble, R. W. Status of catalytic combustion R&D for the department of energy advanced turbine systems program. J. Eng. Gas Turbines Power 2000, 122, 293−300. (18) Lundberg, W. L.; Holmes, R. A.; King, J. E.; Israelson, G. A.; Zafred, P. R.; Kothmann, R. E.; Moeckel, M. D.; Veyo, S. E. A High Efficiency PSOFC/ATS-Gas Turbine Power System; National Energy Technology Laboratory, U. S. Department of Energy: Pittsburgh, PA, Feb 2001; Contract DE-AC26-98FT40455 Final Report by Siemens Westinghouse Power Corporation (http://www.osti.gov/bridge/ product.biblio.jsp?osti_id=859228). (19) Song, T. W.; Sohn, J. L.; Kim, T. S.; Ro, S. T. Performance characteristics of a MW-class SOFC/GT hybrid system based on a commercially available gas turbine. J. Power Sources 2006, 158, 361− 367. (20) Schwarzbözl, P.; Buck, R.; Sugarmen, C.; Ring, A.; Crespo, M. J. M.; Altwegg, P.; Enrile, J. Solar gas turbine systems: Design, cost and perspectives. Sol. Energy 2006, 80, 1231−1240. (21) Rabovitser, J.; Nester, S.; Wohadlo, S. Development of a partial oxidation gas turbine (POGT) for innovative gas turbine systems. Proceedings of the American Society of Mechanical Engineers (ASME) Turbo Expo 2007: Power for Land, Sea, and Air; Montreal, Canada, May 14−17, 2007; Paper GT2007-27539, pp 261−269, DOI: 10.1115/ GT2007-27539. (22) Paterson, B.; Weeks, A. Progress achieved in the ARBRE BIGCC project and prospects for the future. Proceedings of the International Conference on Renewable BioenergyTechnologies, Risks, and Rewards; Institution of Mechanical Engineers (IMechE) Headquarters, London, U.K., Oct 29−30, 2002; Paper C611/030/2003, ISBN: 1-86058-403-9. (23) Bolhàr-Nordenkampf, M.; Hofbauer, H. Biomass gasification combined cycle thermodynamic optimization using integrated drying. Proceedings of American Society of Mechanical Engineers (ASME) Turbo Expo 2004: Power for Land, Sea, and Air; Vienna, Austria, June 14−17, 2004; ASME Paper GT2004-53269. (24) Ragland, K. W.; Aerts, D. J.; Baker, A. J. Properties of wood for combustion analysis. Bioresour. Technol. 1991, 37, 161−168. (25) Ståhl, K.; Neergaard, M.; Nieminen, J. Progress report: Varnamo biomass gasification plant. Proceedings of the 1999 Gasification Technologies Conference; San Francisco, CA, Oct 17−20, 1999. (26) Bolhàr-Nordenkampf, M.; Rauch, R.; Bosch, K.; Aichernig, C.; Hofbauer, H. Biomass CHP plant GüssingUsing gasification for power generation. Proceedings of the International Conference on Biomass

zi = molar fraction of mixture component i Greek Symbols α = power plant own needs factor (assumed value for the GT base plant is 0.02) Δhi|298Ti K = physical enthalpy of component i at its temperature Ti (kJ/kmol) Δm = mass reduction (Mg) ηb = heating system boiler efficiency ηq and ηq,ref = heat production efficiency and reference efficiency (ηq,ref = 0.90 for NG, and ηq,ref = 0.86 for wood37) ηel and ηel,ref = heat production efficiency and reference efficiency (ηq,ref = 0.524 for NG, and ηq,ref = 0.327 for wood37) ηref,system = reference electricity generation efficiency in fossilfuel-fired plants (ηref,system = 0.3648) σ = power/heat ratio of the cogeneration plant Subscripts coal = related to coal CO2 = carbon dioxide db = dry basis dm = drying medium H2O = water i = element indicator max = maximum value out = outlet value ref = reference value wb = wet basis wood = related to wood

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