Article pubs.acs.org/EF
Simulation-Based Study of a Novel Integration: Geothermal− Biomass Power Plant Seethamraju Srinivas,*,†,⊥ Daniel Eisenberg,‡ Navid Seifkar,† Paolo Leoni,§ Marco Paci,§ and Randall P. Field†,* †
MIT Energy Initiative, Massachusetts Institute of Technology, 77 Massachusetts Avenue, Cambridge, Massachusetts 02139, United States ‡ Department of Chemical Engineering, Massachusetts Institute of Technology, 77 Massachusetts Avenue, Cambridge, Massachusetts 02139, United States § Enel Engineering and Research Division, Via Andrea Pisano, 120, 56122 Pisa, Italy S Supporting Information *
ABSTRACT: This work investigates the potential to integrate a biomass combustor with an existing geothermal power plant. The motivation is to identify the most cost-effective approach to boost the geothermal turbine power output using heat from the biomass combustor to superheat the geothermal steam upstream of the turbine inlet. Different alternative integration configurations were identified and simulated using Aspen Plus software to evaluate their performance in terms of incremental power output and efficiency. Of the three different alternatives proposed, only one of them looked promisingthis configuration uses the saturated well-steam for partial preheating of the combustion air. The most promising integration options are compared on the basis of their levelized cost of electricity. The key conclusion is that one should use low-grade heat for low-level heating (well-steam for air preheating) and high-grade heat from the flue gas for steam superheating. Also, the quantity and quality of biomass available dictate the hybrid configuration selected. A proper design of the steam turbine (higher efficiency at higher steam inlet temperatures) is also necessary to enhance the performance of the hybrid geothermal−biomass power plant.
1. INTRODUCTION In today’s carbon-constrained world, producing power in a sustainable manner is a major challenge. One of the options is to combine fossil-fueled power plants with renewables, e.g., cofiring of coal with biomass,1 supplementary firing of biomass in IGCC or NGCC plants,2 combining concentrated solar power or geothermal heat with coal or natural gas-based power plants,3−5 etc. Similarly, one can supplement a renewable source of power with another renewable, e.g., hybrid solar−biomass plants,6 hybrid biomass−wind power,7 hybrid geothermal−solar power,8 etc., when it offers synergies like utilization of low-grade fuel to produce a higher-quality product (electricity or value-added fuels9), boosts the capacity of the existing power plant, adds economic value to material that is otherwise disposed of as waste, reduces intermittency effects, adds load stability, etc. Geothermal energy is one of the renewable sources of energy used to generate electricity worldwide. Different kinds of geothermal plants exist, based on the resource potential and resource type (steam, hot water or brine, etc.), like dry steam plants, flash plants, binary cycle plants, etc.10 Chamorro et al.11 present the current world status of geothermal electricity, including installed capacities, number of units, and energy produced by plant type. Geothermal power plants (including both dry steam and flash plants) utilizing steam turbines contribute to approximately 88% of the installed geothermal power generation capacity. Italy has the advantages of both substantial geothermal resources and strong agricultural productivity. Italy’s installed geothermal power capacity was ∼875 MWe in 2012.12 An existing power plant in Italy, that © 2014 American Chemical Society
currently uses saturated steam from a geothermal source for power generation, forms the basis of this study. The objective is to examine the advantages of combining a biomass combustor with the existing geothermal power plant. Since biomass is considered renewable, utilities like Enel have interest in this combination, which offers renewable energy credits, low carbon solution, etc., as opposed to using oil- or natural-gas-fired combustors which utilize fossil resources. We investigate the merits of this novel hybridization in terms of the following metrics: power output, incremental power output relative to the existing geothermal operations, thermal efficiency of the incremental MWe per MWth of biomass consumed, exergy efficiency, and the levelized cost of the incremental power. To the best of our knowledge, this study is the first of its kind. We demonstrate that integration with biomass combustors can go beyond the addition of superheat to the geothermal steam and a better matching of the heat levels is possibleutilize low-grade heat from well-steam for air preheating and high-grade heat from flue gas for steam superheating. Readers are referred to the work by Bidini et al.,13,14 who suggest another interesting integration of geothermal power and a gas turbine, with the gas turbine combusting the non-condensable gases present in the geothermal steam. Received: July 15, 2014 Revised: November 4, 2014 Published: November 5, 2014 7632
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2. METHODOLOGY
are not considered in this model primarily because this predominantly steam system is most accurately modeled using steam tables, and the use of steam tables requires the stream to be modeled as pure steam. The assumption of using pure steam without any non-condensables does not significantly affect the turbine output performance owing to the low amounts of noncondensable gases (NCGs). NCGs interfere with the heat transfer in the condenser. However, geothermal type condensers are designed to deal with NCGs and also make use of vacuum pumps to remove NCGs from the condenser.21 Most importantly, the condenser performance was outside the scope of this study. Hence, the condenser pressure was not predicted in this study and was fixed at 0.08 bar as per the design basis parameters.
15
Aspen Plus was chosen as the simulator to perform the analysis on the basis of its flowsheet development capabilities in terms of available components, thermal and physical property methods, plant modules like heat-exchangers, turbines, etc., and convergence algorithms. The equations describing the combustor, heat-exchangers, turbines, etc. can be found in the work of Ibrahim and Rahman,16 and those describing the energy and exergy efficiency of the equipment and the overall plant are available in the works by Coskun et al.17 and Ganjehsarabi et al.18 Suitable components and property methods were chosen, and the flowsheets were developed for the geothermal turbine as well as for the hybrid plant integrating biomass combustion with the steam turbine. Sensitivity analysis on the inlet steam turbine temperature quantified the incremental power output resulting from superheating. In addition to a base case hybrid design (proposed by Enel) which superheated the saturated steam using the combustion heat, three different alternative configurations were examined. Two of these alternatives (Configurations A and B) explored the option of generating high pressure steam to drive a new high pressure turbine, followed by expansion in the existing low pressure turbine. The third option (Configuration C) is similar to the base case hybrid plant except that it uses the saturated wellsteam to do some of the air preheating. Only Configuration C looked promising compared to the base case design in terms of the incremental power output produced. Configuration C and the base case hybrid integration were then evaluated on the basis of levelized cost of electricity (LCOE) using cost data provided by Enel and from estimates using Aspen EDR (Exchanger Design & Rating)19 for the heatexchangers when data were not available. A case-study was also performed to evaluate the possibility of using flue gas for drying the biomass and its effect on the incremental power output and LCOE.
4. SIMULATION STUDIES: GEOTHERMAL−BIOMASS HYBRID OPERATION This section focuses on the integration of the geothermal plant with the biomass combustor. The first subsection illustrates the effect of inlet steam superheating on the power output and the importance of defining the turbine efficiency in the power calculations. The base case hybrid integration is discussed in the next subsection. The succeeding subsections describe the other alternative integration options considered. 4.1. Obtaining Turbine Efficiency at Higher Inlet Steam Temperatures. The power output from the turbine can be increased by increasing the inlet steam pressure, flow or temperature. Higher steam pressure is possible if the steam pressure from the geothermal well itself is higher, or if steam can be generated using heat from other sources (fossil fuel or biomass in the case of this work). The latter option is explored in our HP turbine analysis (see sections 4.5 and 4.6). Steam flow is generally limited by the steam supply and by the physical limits of the turbine. Higher steam temperatures can be realized when there is an additional heat source available to provide the required superheatbiomass, in this case. Using the model described in Figure 1, a sensitivity analysis is performed to study the effect of inlet steam temperature on the turbine output. The results are shown in Figure 2. As the inlet steam temperature to the turbine increases, the power output increases as expected, and the turbine tends to run under “dry” conditions. At temperatures beyond ∼350 °C, the exit vapor fraction is 1. The plot in Figure 2 is generated assuming a fixed dry efficiency of the turbine equal to 0.7513 independent of the inlet temperature (and wet efficiency varies with steam quality per eq 1). However, it is known that the turbine dry efficiency varies with the inlet temperature. We used data from the turbine supplier of the generated power at the new design steam temperature to reconstruct the efficiency as a function of the inlet temperature (not shown here owing to reasons of confidentiality), which indicated a decrease in turbine efficiency with an increase in the inlet steam temperature. A temperature of 370 °C is the target for the superheated steam using flue gas from the biomass combustor in the hybrid plant design envisaged by Enel. For the analysis presented in here, 0.7513 is fixed as the dry efficiency value irrespective of the turbine inlet temperature. Further analysis on the impact of this assumption is presented in section 6.1. To conclude, adding superheat to the steam helps increase the power output as shown in Figure 2. However, the incremental increase in output may be lower than predicted in Figure 2 owing to a potential drop in turbine efficiency with increase in temperature depending on the specific design of the turbine.
3. SIMULATION STUDIES: GEOTHERMAL OPERATION AND DESIGN BASIS PERFORMANCE The existing geothermal plant uses saturated well-steam to drive a condensing turbine. The turbine efficiency is estimated using the Baumann’s rule (eq 1)20 that relates the turbine dry efficiency (only vapor present under exit conditions) and wet efficiency using the average steam quality (vapor fraction): ηwet = ηdry ((ϕin + ϕexit)/2)
(1)
where ηwet and ηdry are the turbine wet and dry isentropic efficiencies, and φin and φexit are the vapor fractions at the turbine inlet and exit, respectively. When the steam quality is 1, it implies that the dry and wet efficiencies are equal. In all the cases of interest in this work, the inlet steam quality (φin) is 1. The existing geothermal plant is modeled at a thermodynamic level of detail. The condensing turbine is followed by a vacuum condenser (Figure 1). The work generated from the turbine is
Figure 1. Process flow schematic of the geothermal plant.
calculated on the basis of the feed conditions, outlet pressure, and isentropic efficiency. Based on an output design basis of 13.5 MW of the plant, we back-calculated the design basis wet isentropic efficiency to be 0.7098. At these conditions, the exit vapor fraction is ∼0.89. The dry efficiency is 0.7513, as specified by Enel in the data provided. Note that the geothermal steam to the turbine inlet has 2% non-condensables present in it. However, the non-condensables 7633
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Figure 2. Effect of inlet steam temperature on turbine output.
Figure 3. Process flow schematic of the base case hybrid configuration.
4.2. Biomass Combustor Model. The biomass combustor provides the additional superheat to be delivered to the saturated well-steam. The combustor model gives flue gas containing fly ash as the main output stream. The exit flue gas is predicted to be at 977 °C which is the inlet temperature to the first superheater (SH3) in a series of three superheaters. The given lower heating value of the biomass is 2503 kcal/kg (wet basis). Using the specified biomass feed rate of 5501 kg/h, the LHV energy of biomass at the inlet is 16.0 MWth which is used as the basis for calculating the efficiency in incremental power generation for the biomass. Formation of combustion pollutants like NOx or SOx is not included in the combustion modeling. The ash in the flue gas is separated before the flue gas is recycled to the combustor. No entrainment of ash in the flue gas exhaust is assumed. 4.3. Base Case Hybrid Design. Sections 3 and 4.2 described the geothermal turbine and the biomass combustor model,
respectively. In the base case hybrid configuration, the idea is to provide superheat to the inlet steam of the turbine using the heat of combustion from the biomass with flue gas as the heat transfer medium. To accomplish this, a three-stage superheater is proposed whose design parameters were provided by Enel. The three superheaters (SH1, SH2, and SH3) are modeled as counter-current shell-and-tube heat exchangers to transfer heat from the hot flue gas to the well-steam. Enel provided the nominal values for the pressure drops and heat losses in the duct work. The exit flue gas after superheating leaves at 266 °C and preheats the combustion air to 195 °C. Air preheating is modeled using data provided by Enel, including air leakages. Figure 3 shows the schematic of the base case hybrid configuration. Figure 4 presents an overview of the heat-exchanger configuration. The LP heater shown is modeled as the three7634
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vi. In the cases where HP steam is considered, its temperature is fixed at 600 °C (a typical value used in power plants). The alternatives considered use flue gas for generating superheated steameither LP or HP or bothand preheat air with flue gas alone (the base case hybrid design) or with saturated well-steam followed by the flue gas. 4.5. Configuration A. Figure 5 shows the alternate hybrid integration option “Configuration A”. In this case, a part of the Figure 4. Overview of the base case hybrid configuration.
stage superheater, and the air preheating block has a series of mixers and heaters to bring the air to the required temperature of 195 °C (part of the preheated air is recycled back to the air preheating block in order to maintain the block temperature above 65 °C and prevent any condensate formation on the flue gas side). After this integration, the inlet steam to the turbine is at 370 °C and 4.73 bar (110 TPH). The resulting power output from the turbine in the base case hybrid design is thus 18.2 MW. Compared to the geothermal only plant output of 13.5 MW, the incremental output due to biomass combustion is 4.7 MW. Hence, the efficiency of the biomass derived power for this hybrid configuration is 29.4% (4.7 MW/16 MW). This does not include the parasitic loads like electricity consumption by the air, flue-gas recirculation blowers, etc. Enel has indicated the air circulation and flue gas recycling power to be ∼130 and ∼90 kW, respectively. This translates to a power requirement of ∼1.5% of the inlet biomass energy and a slight drop in the calculated efficiency to 28%. The calculated efficiency for the biomass combustor is close to the typical values suggested for biomass Rankine steam cycles (30−35% on a LHV basis for a 5−25 MW power plant22). Comments on the costs will be made in a later section dealing with the economic analysis. 4.4. Strategy and Assumptions Used To Design Alternate Hybrid Options. In the following subsections (4.5−4.7), we explore alternative configurations that may have the potential to produce higher gross power at a higher efficiency. The following strategy is used to design such configurations: a. Use part of the condensate to make high-pressure (HP) feedwater. b. Low-grade heat utilizationuse low-temperature steam (from the well) to preheat air and HP feedwater. c. High-grade heat utilizationuse high-temperature flue gas to superheat HP steam. d. Expand the HP steam in a HP turbine. The work from the HP turbine in addition to the expansion work from the LP turbine is expected to increase the gross power output. For the purpose of rapid analysis of the alternate options, the combustor and superheater models are decoupled, and the model is simplified by fixing the boundaries for the heatexchangers and turbine using the following assumptions: i. No changes are made to the biomass combustor and the amount of heat recovered from the flue gas. ii. The flue gas enters the superheating stage at 979 °C and leaves it at 266 °C. iii. The Baumann rule is implemented on the LP turbine to penalize wet conditions, if any, that arise during expansion. iv. Inlet pressure to the LP turbine is fixed at 4.73 bar, and exit pressure is 0.08 bar in all cases. v. The cases represented here are illustrative and not optimized.
Figure 5. Overview of Configuration A.
condensate is used to generate HP steam and expand it in a HP turbine. The cold condensate is pumped to the desired pressure and preheated in two stages using the saturated well-steam. In preheater 2, the well-steam exchanges heat in a “condensing” mode and is then subcooled in preheater 1 to 45 °C (∼5 °C above the typical condensate temperature), leaving some driving force for heat transfer. The preheated condensate then exchanges heat with the incoming hot flue gas in the HP heater to produce HP steam. The HP steam after expansion in the HP turbine joins the superheated LP steam from the LP heater, both of which then undergo expansion through the LP turbine. The flue gas leaving the LP heater is fixed at 266 °C to take care of the air preheating requirements. The decision variables are the flow rate of condensate going to the HP branch and the pressure of the HP steam. The saturated well-steam is divided into two by the splitter such that there is enough preheating for the HP condensate. A sensitivity analysis on the two decision variables is performed to analyze the performance in terms of the output from the HP and LP turbines and the effect of HP steam pressure on the gross output. The results are shown in Figure 6, which indicates that the LP turbine output decreases as the HP steam flow increases. As the HP steam flow increases, more well-steam is needed to preheat the HP condensate lowering the flow to the LP turbine. Further, the increased HP condensate flow recovers more heat from the flue gas to reach 600 °C leaving lower amounts of heat available for superheating the LP steam. LP turbine output, thus, decreases due to the reduction in flow as well as the level of LP steam superheat. However, the loss in output from the LP turbine is more than offset by the increase in HP turbine output leading to an increase in the gross output. The effect of the HP steam pressure on turbine output will be discussed in the next subsection. 4.6. Configuration B. Figure 7 shows another alternate hybrid integration option, “Configuration B”. The condensate processing unit in Figures 5 and 7 is not simulated in the model; however, it is envisaged to be implemented in the real plant. Configuration B is similar to 7635
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Figure 6. Effect of HP steam flow on turbine output.
Figure 8. Effect of HP steam pressure and air preheating by well-steam on gross output. Figure 7. Overview of Configuration B.
results in an increase in the gross output since the temperature levels at which heat transfer occurs is matched in a much better manner. As observed in Figure 6, increase in the HP steam flow also increases the gross output (compare the two continuous curves with symbols indicating flows of 15 and 18 TPH of HP steam). Though a few other alternative configurations were also tested to examine reheating between the HP and LP stages of the turbine, reheating was not effective in increasing the gross output under the given conditions. The alternate configurations evaluated approached the output of the proposed Enel configuration and will be compared at the end of the next subsection. To summarize, condensing steam to preheat the air helps to boost the output marginally. It is not effective to use hot flue gas for preheating air, if there is an alternate low-grade heat source available. 4.7. Configuration C. The third alternative, “Configuration C”, is similar to the proposed base case hybrid design except that part of the air preheating is done using saturated well-steam, as shown in Figure 9. In this case, there is no HP steam generation or HP turbine. The flue gas leaving the LP heater, which superheats the saturated well-steam, leaves at 205 °C. The combustion air is preheated in two stages: first by the well-steam and then by the flue gas. The saturated steam is distributed into two parts by the splitter such that the air preheating requirement is met. The
Configuration A, except that the saturated well-steam is used to preheat both the HP condensate and the combustion air in Configuration B. The flue gas leaving the LP heater is fixed at 205 °C, which is 10 °C above the combustion air temperature (195 °C) to take care of the driving force needed for heat transfer. The decision variables are the flow rate of condensate going to the HP branch and the pressure of HP steam. The saturated well-steam is divided into three parts by the splitter: two of them used for condensate and air preheating, and one for generating superheated LP steam. The effects of HP steam pressure on the turbine output as well as that of air preheating by well-steam are illustrated in Figure 8. In all the curves in Figure 8, the gross output increases with the HP steam pressure. Thus, generating HP steam at the maximum possible pressure will result in increased gross output. This pressure is limited by the mechanical design and cost of components like tubes and tubesheets in the heat-exchangers used to transfer heat from the flue gas to the steam and other practical considerations. The curves represented by the dotted line and the continuous line with triangles depict the same flow for HP steam (15 TPH). While the dotted line is representative of Configuration A, using only flue gas for air preheating, the continuous lines depict Configuration B, using both saturated steam followed by flue gas for preheating air. As expected, using steam to preheat the air 7636
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4.8. Flue Gas for Biomass Drying. The efficiency of the biomass combustor can be improved if the wet biomass feed can be dried using waste heat available from the process.23 The exit flue gas from the base case design and Configuration C is at 160− 170 °C, and provides the opportunity for utilizing this low-grade heat to dry the biomass. The use of flue gas for this purpose can be either through direct or indirect methods. In the indirect method, the flue gas transfers its heat to a heat-transfer medium like steam which in turn dries the biomass. Such a practice would need two additional heat exchangers, and preliminary simulations showed that the additional improvements in efficiency were not justifiable to follow this approach. Tables 2 and 3 show the results of using flue gas directly for drying biomass in the base case hybrid design and Configuration C, respectively. In generating these results, it is assumed that the air flow to the combustor remains unchanged from the base case, i.e., when there is no drying. Also, enough biomass is fed such that the flue gas exit temperature is ∼980 °C since this is the temperature for which the combustor is designed. It is a common practice in drying biomass to avoid high temperatures which can generate volatile organic compounds. This can be accomplished by diluting the flue gas with aira detail that we have not simulated. As expected, the amount of biomass feed decreases in both configurations with the increase in drying, viz., reduced moisture content in biomass at the dryer exit (see Tables 2 and 3). For both the base case design and Configuration C, the lowest moisture content possible is 10%, at which the exhaust gas temperature is still above its dewpoint and is the conventional limit used in practice. Drying to less than 10% increases the heat-transfer requirements quite significantly due to decreased driving forces. Owing to the lower amounts of biomass combusted, there is a slight reduction in the flue gas flow rate (∼3%) leading to lower level of superheat on the inlet steam to the turbine. As a result, the turbine output drops by ∼2.5%. However, the net result is an overall increase in the efficiency of the biomass derived power since the reduction in output is offset by the reduction in the biomass energy input. To conclude, utilizing flue gas for biomass drying seems attractive based on efficiency calculations for both of the cases considered, with Configuration C having a slightly higher efficiency.
Figure 9. Overview of Configuration C.
decision variable in this case is the flue gas temperature leaving the LP heater. Results of a sensitivity analysis on this temperature are elaborated in detail in section 6.2. Table 1 compares the designated best cases from each of the configurations described. The flow rates of HP steam in Configurations A and B are fixed at 16 and 18 TPH, respectively, based on the sensitivity study. The pressure of the HP steam was chosen as 80 bar since the incremental increase in gross power output with further increase in pressure is not significant. The reason for a temperature of 600 °C for the HP steam temperature was explained earlier. Thus, the conditions for inlet HP steam shown in Table 1 for Configurations A and B are close to the maximum possible output and, hence, are designated as the best cases. For Configuration C, the best case is when the maximum amount of heat is provided to superheat the LP steam, i.e., the exit flue gas from the superheater is at the lowest possible temperature. This is set to be 205 °C to have a 10 °C approach with the exit combustion air leaving the air preheater which is a reasonable approach temperature. On the basis of the results in Table 1, it can be concluded that Configurations A and B do not show much promise under the given constraints on temperature of the flue gas leaving the combustor (979 °C), the flue gas entering the air preheater (205 °C), and the air entering the combustor (195 °C). The temperature values that are specified and those that are calculated in the various heat-exchangers can be found in the model documentation provided as Supporting Information. The addition of the HP turbine cannot be justified on the basis of the marginal gain in gross power. These configurations are perhaps more beneficial if there is a substantially greater biomass supply and, therefore, a higher quantum of heat available. Further, the base case configuration is simpler, having fewer heat exchangers and no HP turbine, and is less expensive. Configuration C looks promising, with a marginally higher output of 0.25 MW compared to the base case design, and is considered for further analysis. Figure 10 shows the schematic of Configuration C.
5. ECONOMIC ANALYSIS As shown in the previous section, two potential hybrid designs of the geothermal−biomass integrated plant look promising: the base case hybrid design and Configuration C. This section analyzes these two alternatives in terms of the LCOE and comments on their economic viability.
Table 1. Comparison of the Best Cases from Different Configurations conditions at HP turbine inlet
conditions at LP turbine inletc
gross output (MW)
incremental output (MW)a
biomass efficiency excl. parasitic load (%)b
geothermal only base case hybrid design Configuration A
not present not present
110 TPH, 5.2 bar, 154 °C 110 TPH, 4.73 bar, 370 °C
13.5 18.2
4.7
29.4
16 TPH, 80 bar, 600 °C
18.04
4.54
28.4
Configuration B
18 TPH, 80 bar, 600 °C
18.3
4.8
30.0
Configuration C
not present
123.3 TPH, 4.73 bar, 166 °C 123.6 TPH, 4.73 bar, 160 °C 108.7 TPH, 4.73 bar, 389 °C
18.45
4.95
30.9
a
Incremental output from biomass. bLHV basis using 16 MW as the biomass input energy. cTurbine dry efficiency is 0.7513 in all cases. 7637
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Figure 10. Process flow schematic of Configuration C.
Table 2. Effect of Using Flue Gas for Biomass Drying in the Base Case Hybrid Design flow rate
biomass dryer
output
exit moisture (wt %)
exhaust gas dewpoint (°C)
exhaust gas temperature (°C)
biomass (kg/h)
flue gas (kg/h)
turbine (MW)
incrementala (MW)
biomass inputb (MW)
biomass efficiencyc (%)
35.5 25 20 15 10
59 57 57 56 56
174 106 93 82 72
5501 5015 4898 4797 4702
57 130 56 113 55 749 55 440 55 170
18.19 17.95 17.88 17.82 17.76
4.69 (370 °C)d 4.45 (361 °C)d 4.38 (358 °C)d 4.32 (355 °C)d 4.26 (353 °C)d
16.01 14.6 14.26 13.96 13.68
29.3 30.5 30.7 30.9 31.1
a Incremental output due to biomass. bLHV basis. cEfficiency based on biomass contribution, LHV basis. dIndicates the steam inlet temperature to the turbine.
Table 3. Effect of Using Flue Gas for Biomass Drying in Configuration C flow rate
biomass dryer
output
exit moisture (wt %)
exhaust gas dewpoint (°C)
exhaust gas temperature (°C)
biomass (kg/h)
flue gas (kg/h)
turbine (MW)
incrementala (MW)
biomass inputb (MW)
biomass efficiencyc (%)
35.5 25 20 15 10
59 57 57 56 56
167 103 92 81 72
5501 5031 4896 4791 4700
57 130 56 127 55 747 55 436 55 168
18.45 18.19 18.09 18.03 17.97
4.95 (389 °C)d 4.69 (380 °C)d 4.59 (377 °C)d 4.53 (374 °C)d 4.47 (371 °C)d
16.01 14.64 14.25 13.94 13.68
30.9 32.0 32.2 32.5 32.7
a
Incremental output due to biomass. bLHV basis. cEfficiency based on biomass contribution, LHV basis. dIndicates the steam inlet temperature to the turbine.
5.1. Incremental Cost of Preheater for Configuration C. The main difference between the base case design and
Configuration C is the use of well-steam to preheat combustion air partly, viz., the addition of an extra heat exchanger in the 7638
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Table 4. Comparison of Air Preheater Designs allowable pressure drop (bar)
a
heat exchanger
shell
tube
area calculated by EDR (m2)
costa calculated from EDR (€b)
air preheater (base case) air heater 1 air heater 2 air preheater (Configuration C)
0.05 (air) 0.2 (steam) 0.05 (air)
0.03 (flue gas) 0.015 (air) 0.03 (flue gas)
∼1089 ∼499 ∼1600 ∼2099
∼178 098 ∼144 464 ∼265 173 ∼409 637
Bare equipment cost only. b€1 = US$1.35.
process. To perform the costing of this heat exchanger, Aspen EDR is used. The preheater configurations for the base case and Configuration C are compared in Table 4. The new air preheating arrangement in Configuration C has a higher area (∼1.9 times) and a higher cost (∼2.3 times) than the air preheater in the base case design, as seen from Table 4. The higher area is because of the lower mean temperature difference across the second stage air preheating in case of Configuration C. The temperature approach at the hot end of air heater 2 is 10 °C only (flue gas entering at 205 °C and combustion air leaving at 195 °C). This difference is illustrated in the schematic in Figure 11.
vi. Enel provided values for the combined cost of the combustion grate and superheater. [As an order of magnitude estimate, this combined cost is ∼14 times more than the cost of the superheater (SH1, SH2, and SH3 together) calculated using EDR (∼€730 000). Since the intent here is to compare the base case hybrid design with Configuration C, only the difference in the total cost of the heaters between the two cases is added to the total capital cost of the biomass plant (value provided by Enel). The installation costs associated with the additional heater alone are not considered, and are not expected to change the results significantly. Thus, the capital cost difference between the base case and Configuration C arises from the cost of the preheaters and the cost of the superheater SH1. All other capital costs are assumed to be the same for both these cases.] vii. No revenue is generated in the first year. viii. The entire capital cost is incurred in the first year. The capital cost is approximately twice the cost of the combustion grate and superheater together. LCOE values for the base case hybrid plant and Configuration C are compared in Table 5. The incremental outputs due to the biomass used for the LCOE analysis are the values shown in Table 1, 4.7 and 4.95 MW for the base case design and Configuration C, respectively. Table 5. Comparison of LCOE Values LCOE (€/kWh)
Figure 11. Comparison of preheater arrangements showing the log mean temperature difference (MTD).
Owing to its importance in deciding the heat exchanger area and hence the net air preheater cost, the exit flue gas temperature is an important decision variable. A detailed analysis of its variation is discussed in section 6.2. 5.2. Levelized Cost of Electricity Using Net Present Value Analysis. The LCOE is typically used to compare alternative designs for their economic viability in the case of power plants, and the same approach is followed in this study. LCOE is calculated using the net present value (NPV) method, setting the NPV to zero at the end of the plant life considered. The following assumptions are used in the LCOE calculations: i. The cost of biomass is €50/t on a wet basis. ii. The biomass combustor is available for an average of 329 days per year (∼7900 h, or 90% availability factor). iii. The internal rate of return (IRR) is fixed at 9% (the minimum value suggested by Enel). iv. The plant lifetime is 25 years. v. The analysis is based only on the incremental power output resulting from the biomass combustor and the incremental costs of the biomass system.
cost of biomass (€/t)
base case hybrid design
Configuration C
37 44 50 59 67
0.113 0.121 0.127 0.139 0.147
0.107 0.116 0.121 0.132 0.141
It can be inferred from Table 5 that the LCOE for Configuration C is less than the base case design by ∼5%, giving it a slight advantage. Also, the LCOE scales almost linearly with the cost of biomass. It is observed that the capital cost is dominated by the cost of the preheaters; the SH1 cost differential has no noticeable impact on the LCOE for Configuration C. Based on IEA estimates from 2007,22 the typical capital cost for a dedicated steam cycle using biomass is ∼€2222 for 3704/kW, and the electricity cost is ∼€0.08/kWh when the biomass cost is €40/t. Based on the Enel data, for the current case, the capital cost is ∼€3507/kW. The biomass cost in the IEA case, however, is possibly on a dry basis, while the Enel specification of €50/t is on a wet basis. Further, the numbers mentioned in the previous lines from the 2007 report were converted from US$ to € using a conversion factor of 1.35. Nevertheless, the capital cost and LCOE values calculated for the present plant can be considered 7639
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6. DISCUSSION An underlying assumption in the analysis of Configuration C is that the turbine dry efficiency is 0.7513. It should be noted that the steam inlet temperature to the turbine for Configuration C is 389 °C which is beyond the temperature range of the curve provided by the vendor. Therefore, there is an uncertainty associated with using the same efficiency value at different temperatures. The first part of this section looks at ways to extrapolate this value from the given data. The second subsection looks at the effect of varying the flue gas exit temperature from the superheater and its impact on the LCOE for Configuration C, considering different efficiency values for the turbine. 6.1. Extrapolating Turbine Efficiency at Higher Inlet Temperatures. Based on the data provided by the vendor, the turbine efficiencies are back-calculated, and they showed that efficiency decreases with increasing inlet temperature. Outside the temperature range of the data provided, one may extrapolate using a linear trend or a polynomial. Table 7 compares the
reasonably consistent with the values from the 2007 IEA document. 5.3. LCOE Analysis: Biomass Drying Using Flue Gas. In section 4.8, it was shown that drying biomass using the flue gas is beneficial and helps in improving the efficiency of the process. In this section, we comment on its usefulness based on economics (LCOE analysis). Table 6 shows the results of the analysis for this Table 6. LCOE: Biomass Dried Using Flue Gas LCOE (€/kWh) exit moisture after dryer (wt %)
base case hybrid design
Configuration C
35.5 25 20 15 10
0.127 0.129 0.130 0.130 0.131
0.121 0.124 0.125 0.126 0.127
Table 7. Comparison of Efficiency Values at Different Temperatures
case for the base case hybrid plant and Configuration C. In addition to the assumptions used in section 5.2, it is assumed that a rotary dryer is used in drying the biomass. Based on calculations using Aspen Process Economic Analyzer,24 such a dryer processing 5.5 TPH of biomass has an area of ∼60 m2 and costs ∼€259 260. This is the additional item added to the capital cost of the plant. The installation costs associated with the dryer alone are not considered, and are not expected to change the results significantly. The row with 35.5 wt % moisture corresponds to the base case of no drying. For the base case design as well as Configuration C, there is a reduction in the biomass feed rate with increased drying, as shown in Tables 2 and 3, and, therefore, savings on the fuel costs. However, there is a lowering of revenue from the sale of electricity since the turbine output decreases marginally. Thus, the net result is a slight increase in the LCOE as the extent of drying is increased for both the cases (see Table 6). Configuration C retains its slight advantage over the base case in terms of LCOE too as we move toward lower moisture content in the biomass leaving the dryer. An interesting observation from Table 6 is that the LCOE for Configuration C with the extreme level of drying (10% moisture) is the same as the base case with no drying (35.5% moisture). In other words, the extra capital invested in the form of the additional air-steam preheater and the biomass dryer in the case of Configuration C offers the same returns as the base case hybrid plant without this additional equipment and, more importantly, a wider operational window in terms of the quality/quantity of biomass handled. To summarize, using flue gas for biomass drying offers a higher efficiency but has a worse LCOE compared to the base case having no drying. This is due to the lower quantity of incremental power which offsets the advantage of having a lower biomass flow rate with drying enabled. If a fixed feed rate of biomass is assumed, then the flue gas temperature at the exit of the combustor is expected to increase with an increase in the extent of biomass drying. However, we have limited this exit temperature to ∼979 °C on the basis of calculations from the base case hybrid configuration since this temperature places restrictions on the material of construction, etc used in the heat exchanger which has already been designed. The low incremental power results from this maximum temperature constraint imposed at the exit of the biomass combustor which limits the level of superheat on the inlet steam to the turbine.
temperature (°C) case E1: fixed case E2: linear extrapolation case E3: polynomial extrapolation
370
376
379
383
386
389
0.751 0.750
0.751 0.748
0.751 0.747
0.751 0.745
0.751 0.744
0.751 0.742
0.752
0.749
0.746
0.743
0.740
0.737
efficiencies at different temperatures for three different cases: fixed efficiency (case E1), efficiency calculated by linear extrapolation (case E2), and efficiency calculated by polynomial extrapolation (case E3). In the absence of any validation data, the common practice is to use the linear extrapolation method. While the difference in values in Table 7 does not look significant, the small changes indeed result in a difference of ∼0.4 MW in the turbine output at 389 °C as we go from case E1 to case E3 (see Table 8). Thus, it can be concluded that using the right value of the turbine efficiency at the expected steam inlet temperature is necessary to accurately predict the turbine output. The turbine vendor may be able to modify the turbine to have better efficiency for higher temperature. If so, we would need a revised projection of the performance curve from the vendor. If such a modification is feasible, we assume the efficiency of 0.7513 is possible. 6.2. Sensitivity of Flue Gas Temperature Leaving the Superheating Section. The flue gas temperature leaving the superheating section in Configuration C has an impact on the heat exchange area needed for air preheating, and hence its cost. On the other hand, it dictates the amount of superheat delivered to the LP steam and, thus, the steam inlet temperature to the turbine. Therefore, varying the flue gas exit temperature from the superheater has a trade-off between the air preheater heat exchanger area (capital cost) and the turbine output (revenue generated). The turbine output, in turn, is dependent on the efficiency, which changes with the temperature. The flue gas temperature in question is varied from 205 to 245 °C without varying the other temperature specifications illustrated in Figure 11 (flue gas leaving the air preheater at 170 °C, well-steam entering at 154 °C and leaving at 45 °C, air heated from 20 to 195 °C). Within this temperature range, the LCOE values under 7640
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Table 8. LCOE Analysis as a Function of Flue Gas Inlet Temperature to Air Preheater temperatures (°C), flue gasa/inlet steamb Configuration C 205/389 cost of additional heat exchange area (×1000€)c Case E1: incremental output (MW) LCOE (€/kWh) Case E2: incremental output (MW) LCOE (€/kWh) Case E3: incremental output (MW) LCOE (€/kWh) a
215/386
225/383
base case hybrid plant 235/379
245/376
266/370
246
206
136
130
111
0
4.95 0.121
4.91 0.122
4.87 0.123
4.83 0.124
4.79 0.125
4.7 0.127
4.73 0.127
4.72 0.127
4.71 0.127
4.71 0.127
4.7 0.127
4.68 0.127
4.59 0.131
4.63 0.129
4.67 0.128
4.71 0.127
4.72 0.127
4.71 0.127
Temperature leaving the superheater. bInlet turbine temperature. cDifference with respect to base case design (including preheaters and SH1).
different efficiency cases are evaluated. The lower limit of 205 °C is based on a temperature approach of 10 °C as described in section 4.7. As the inlet flue gas temperature to the second preheater is increased, the preheat requirement in the first stage is lowered. At inlet flue gas temperatures of 250 and 255 °C, the ΔT values on the air stream in the first preheater (using steam) are only 16 and 6 °C, respectively. Since these ΔT values are not high enough to justify having an additional preheater, 245 °C is fixed as the upper limit of the flue gas inlet temperature in this sensitivity analysis. The results of this analysis are shown in Table 8. It is interesting to observe three different trends in Table 8, based on the efficiency considered. Under the most optimistic assumption of a fixed efficiency (case E1), the LCOE increases with the flue gas temperature and approaches the base case hybrid design value. The benefit from the reduction in heat transfer area is offset by the reduction in gross output in this case. Under the scenario of linear extrapolation of the turbine efficiency (case E2), the LCOE remains constant, and Configuration C does not have any advantage over the base case approach. The trend reverses in case E3 compared to case E1, viz., LCOE decreases with flue gas temperature and approaches the base case design. However, Configuration C under case E3 does not offer promise compared to the base case design. To conclude, it suffices to say that designing the turbine to operate with a higher efficiency (0.7513) at the higher temperature (389 °C) is the best possible way that makes Configuration C beneficial over the base case hybrid plant. 6.3. Exergy Analysis. In evaluating and comparing the performance among different options above, we have considered analysis using the first law of thermodynamics. It is common in the literature to evaluate performance of geothermal power plants using both the first (energy efficiency) and second (exergy efficiency) law calculations. Recent examples are the evaluation of flash-type power plants in Turkey by Ganjehsarabi et al.18 and Unverdi and Cerci25calculations are performed for each individual unit in the plant as well as for the overall plant in terms of energy and exergy. Astolfi et al.26,27 present optimization of binary ORC power plantsthermodynamic and technoeconomic, in their work. Coskun et al. 17 also present exergoeconomic modeling results of a geothermal power plant. We hence performed exergy efficiency calculations for the base case hybrid design and the best case of Configuration C (flue gas entering the preheater has a temperature of 205 °C). The overall plant exergy efficiency values are 37% and 41%, respectively, for
the two cases. These values are not significantly different for the case of the turbine alone (76.37% and 76.52%, respectively, for the two cases). As a result, our conclusion that Configuration C has a slight advantage over the base case hybrid design remains unchanged.
7. CONCLUSIONS The biomass availability and quality are important in the choice of the right integration option. If the biomass availability and quality equal the design scenario under which the integration of the biomass combustor with the geothermal turbine is envisaged, then the base case hybrid approach is recommended as the best solution. It scores over the other options considered because it is simple and less expensive. If the biomass availability is lower or its quality degrades (higher moisture content) compared to the design scenario, then Configuration C is a promising solution. In this case, the lower quantity/quality of biomass reduces the amount of heat available for superheating. However, owing to the option of preheating air with steam in Configuration C, one can still try to get the same amount of superheat from the flue gas as in the base case hybrid configuration. If the biomass availability or quality improves with respect to the design scenario, then implementing Configuration B offers merits. The additional heat available from flue gas at a higher level can be used to generate HP steam and run the HP turbine, while the low-grade heat from the well-steam can be used for preheating purposes (both air and steam). Capital costs need to be considered in taking this decision, and a major contribution to this comes from the biomass combustor. It is important to note that a robust furnace design is necessary to take care of issues in doing biomass combustion, like coking at high temperatures, corrosion, etc., and in increasing the longevity of the hybrid power plant. However, the combustor design was out of the scope of this study and hence was not considered. LCOE analysis suggests that Configuration C is promising under the current scenario, too, if the turbine can be designed to operate under a higher efficiency (0.7513 or more) at the higher temperature (389 °C). Utilizing the flue gas for biomass drying is an attractive option based on efficiency calculations but not based on LCOE analysis. This is subject to the assumption that the flue gas temperature can be lowered and is within the limits specified by the local regulations. If we considered the configurations (A and B) that were eliminated, the exergy efficiency values might look different: one might consider doing this as a part of future work if there is 7641
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sufficient availability of biomass and the turbine efficiency curves are provided for improved accuracy of the turbine calculations both of which are drawbacks in this study. It is recommended that such studies in future might include both energy and exergy calculations to give a complete understanding of the solution. Future work can also focus on performing a sensitivity analysis on the LHV of biomass to determine a range of LHV values (and hence, the kinds of biomass that are viable) that would make any of the suggested hybrid configurations feasible.
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ASSOCIATED CONTENT
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AUTHOR INFORMATION
S Supporting Information *
Model descriptions and three simulation files (created with Aspen Plus v7.3.2) for the stand-alone turbine, the base case, and Configuration C. This material is available free of charge via the Internet at http://pubs.acs.org. Corresponding Authors
*E-mail:
[email protected]. *E-mail: rpfi
[email protected]. Present Address ⊥
Department of Energy Science & Engineering, IIT-Bombay, Powai, Mumbai, Maharashtra 400076, India. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors gratefully acknowledge AspenTech for providing the software used in this work. ABBREVIATIONS Enel= Ente Nazionale per l’energia Elettrica LCOE= levelized cost of electricity IGCC= integrated gasification combined cycle NGCC= natural gas combined cycle ORC= organic rankine cycle EDR= Exchanger Designer & Rating NCG= non-condensable gas LHV= lower heating value HP= high-pressure LP= low-pressure MW= Megawatt MWe= Megawatt electric MWth= Megawatt thermal NPV= net present value IRR= internal rate of return IEA= International Energy Agency TPH= tons per hour kWh= kilowatt hour
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REFERENCES
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