Thermodynamic and economic evaluation of a solar aided sugarcane bagasse cogeneration power plant

Energy xxx (2016) 1e13

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Thermodynamic and economic evaluation of a solar aided sugarcane bagasse cogeneration power plant Eduardo Konrad Burin a, *, Tobias Vogel b, Sven Multhaupt b, Andre Thelen b, €rner b, Edson Bazzo a Gerd Oeljeklaus b, Klaus Go a b

Laboratory of Combustion and Thermal Systems Engineering (LabCET), Federal University of Santa Catarina (UFSC), Florianopolis, Brazil Chair of Environmental Process Engineering and Plant Design (LUAT), University of Duisburg-Essen, Leimkugelstr.10, Essen, 45141, Germany

a r t i c l e i n f o

a b s t r a c t

Article history: Received 30 October 2015 Received in revised form 9 June 2016 Accepted 11 June 2016 Available online xxx

This work evaluated the integration of Concentrated Solar Power (CSP) with a sugarcane bagasse cogeneration plant located in Campo Grande (Brazil). The plant is equipped with two 170 t/h capacity steam generators that provide steam at 67 bar/525
C. Superheated steam is expanded in a backpressure and in a condensing-extraction turbine. The evaluated hybridization layouts were: (layout 1) solar feedwater pre-heating; (layout 2) saturated steam generation with solar energy and post superheating in biomass steam generators and (layout 3) superheated steam generation in parallel with biomass boilers. Linear Fresnel and parabolic trough were implemented in layouts 1 and 2, while solar tower in layout 3. The exportation of electricity to the grid was increased between 1.3% (layout 1/linear Fresnel) and 19.8% (layout 3) in comparison with base case. The levelized cost of additional electricity was accounted between 220 US$/MWh (layout 3) and 628 US$/MWh (layout 1/linear Fresnel). The key factor related to layout 3 was the improvement of solar field capacity factor due to the solar-only operation of this approach. These aspects demonstrate that the combination of solar and bagasse resources might be the key to turn CSP economically feasible in Brazil. © 2016 Elsevier Ltd. All rights reserved.

Keywords: Sugarcane Bagasse Cogeneration Concentrated solar power Hybridization

1. Introduction Solar and biomass are both renewable energy resources which contribute to the electricity generation at low CO2 emission levels. One important problem related to the biomass power plants operation, however, consists on the availability of fuel along the year. This is also true for the sugarcane bagasse power plants in Brazil that are operated mainly during the sugarcane harvest period [1,2]. In this regard, the Concentrated Solar Power (CSP) hybridization of biomass plants has been studied under different configurations [3e6]. The central idea consists on displacing fuel consumption during sunny hours and providing power supply on a biomass only mode during hours of no solar irradiation incidence e the so-called fuel economy hybridization mode. Solar heat load can also be used to provide power boosting during sunny hours e the

* Corresponding author. E-mail addresses: [email protected] (E.K. Burin), [email protected] (T. Vogel), [email protected] (S. Multhaupt), [email protected] (A. Thelen), [email protected] (G. Oeljeklaus), klaus.goerner@ € rner), [email protected] (E. Bazzo). uni-due.de (K. Go

so-called power boosting hybridization mode. These approaches can be applied to new plants and also to existing ones. Sharing common infrastructure turns possible the reduction of solar energy implementation costs. Distinct integration layouts of CSP and conventional plants based on Rankine steam cycles are possible. The most explored scheme in literature is the solar aided feedwater heating concept (SAFWH) which can be performed by the displacement of bleed-off steam extractions of the regenerative feedwater heating system by solar heat load. Several works demonstrated that the higher the steam parameters of bleed-off steam extraction displaced, the higher is the efficiency in converting solar heat into electricity or in terms of fuel economy [7e10]. Furthermore, solar-to-electricity efficiency levels greater than for solar-only power plants operating under the same solar field heat transfer fluid average temperature can be achieved as the exergy destruction inherent to the conventional feedwater heating process is avoided [11,12]. As drawbacks of the SAFWH approach, nevertheless, it can be mentioned that: (i) the annual solar share is generally reduced [6,13,14] and (ii) the solar-only operation is not possible once steam generation is performed in the conventional boiler.

http://dx.doi.org/10.1016/j.energy.2016.06.071 0360-5442/© 2016 Elsevier Ltd. All rights reserved.

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Power plants can also be hybridized by considering the integration of CSP in parallel with conventional steam generators based on coal, natural gas or biomass combustion. It is turned possible, thereby, to increase the solar share of hybridization. Peterseim et al. [3] and Nixon et al. [15] evaluated the operation of conventional steam generators in parallel with CSP where both systems were able to produce superheated steam with the same temperature and pressure parameters. This approach was implemented commercially in the 22.5 MW capacity Borges power plant where the solar field and biomass steam generator systems were designed to provide the annual solar share of around 50% under the local weather conditions of Lleida in Spain. Finally, the hybridization of CSP and systems based on coal or biomass combustion was also evaluated in order to increase the temperature of steam after its generation in the solar field. As examples, Peterseim et al. [4] evaluated the post superheating of steam produced with a parabolic trough solar field with a biomass fired superheating system, while Zhao [16] proposed the production of saturated steam to displace the load of a coal fired steam generator. Produced saturated steam in solar field was then injected into the conventional steam generator drum for post superheating. The installed capacity of sugarcane bagasse power plants in Brazil reached 10.6 GW in the first quarter of 2016 e representing 7.1% of the Brazilian electricity installed capacity [17]. Traditionally the bagasse power plants are cogeneration unities directly located in the sugarcane factories in order to deliver the on-site electricity and heat demands. This explains the large total amount of 410 bagasse fueled unities under operation today in Brazil [17]. In the last decades, due to a relevant increase in the Brazilian electricity demand and also due to the Brazilian electricity sector decentralization in 2000, the focus has changed from fulfilling the on-site sugarcane factories demand to exporting electricity to the grid. Considering the period 2005e2013, the electricity exportation was raised each year by 34% on average, so that in 2013 a total amount of 15,067 GWh was produced by bagasse fueled power plants [18]. The potential for improvements in terms of electricity exportation to the national grid by the sugarcane sector is yet significant once it is estimated that it could reach 193,596 GWh until the year 2022 [18]. The operation of the sugarcane bagasse power plants occurs mainly during the sugarcane harvest that extends from April to December in the center-south region of Brazil [1,2]. In the rest of the year, most plants remain out of operation and no electricity is produced. Therefore, the concept related to the hybridization of cogeneration plants of sugarcane sector with CSP was presented in Ref. [19]. In that preliminary work, the authors evaluated the SAFWH integration layout with parabolic trough collectors under thermodynamic and economic aspects. The main idea consisted on providing the solar integration in a fuel economy mode during harvest to economize bagasse to be then used to operate the power plant during off-season. It was identified, nevertheless, that the proposed hybridization layout was expensive in terms of electricity generating costs and further hybrid configurations and CSP technologies could be tested in order to find more feasible alternatives. In this regard, the aim of this work consisted on extending the cogeneration power plants hybridization concept presented in Ref. [19] through the comparison of three distinct integration layouts, namely: (layout 1) solar feedwater pre-heating; (layout 2) saturated steam generation with solar energy and post superheating in biomass steam generators and (layout 3) generation of superheated steam in parallel with biomass steam generators. Three CSP technologies were also considered according to the steam cycle injection point temperature requirement of each hybridization scenario. The linear Fresnel and parabolic trough collectors were implemented for integration layouts 1 and 2, while solar tower with direct steam generation was implemented in layout 3. The scope

was here limited to the retrofit of a conventional cogeneration plant aiming minimal modifications on original installations. 2. Method 2.1. The solar aided cogeneration plant concept Bagasse is the fibrous residue which remains after the sugarcane juice extraction process. The bagasse consists of cellulose, hemicellulose and lignin. Due to the on-site electricity and heat demand of sugarcane processing factories, the bagasse is directly used as fuel in cogeneration power plants. The hybrid operation of a cogeneration power plant in a fuel economy mode during the harvest period is here proposed and evaluated under different layouts. The stored bagasse can be then used to run the power plant during off-season. This concept is shown in Fig. 1. Whereas sugarcane cannot be stored, the operating time of the process factory is coupled to the sugarcane harvesting period, which typically ranges in the center-south region of Brazil from April to December. Outside this period, most of the cogeneration power plants are out of operation and no electricity is exported to the grid. In contrast to sugarcane, bagasse is storable. Hence, by replacing partially bagasse with solar energy during normal operating season, the overall power plant operating period can be extended to off-season through the use of the stored bagasse. 2.2. Tested hybridization layouts The ways of concentrating solar energy can be divided into linear and point focusing technologies. Parabolic trough and linear Fresnel collectors belong to the linear focusing technologies, whereas the main point focusing technologies are the central receiver (solar tower) and the parabolic reflectors (Dish). Considering the market availability and the current state of development, the following technology options were chosen for the present case study: Linear Fresnel (LF); Parabolic Trough (PT) and Solar Tower (ST). An overview for the three named CSP options is presented in Table 1. In this work the analysis was limited to the technology options

Fig. 1. Schematic of process and illustration of the solar aided cogeneration plant concept.

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Table 1 Overview to the three considered CSP technologies. Unit LF Heat Transfer Fluid (HTF) Concentration ratio Maximum HTF temperature Ratio of current installed capacity Max. gross capacity (operational plants)

e e
C % MW

PT

ST

Source

Water/steam and molten salts Thermal oil, water/steam and molten salts Water/steam, molten salts and air [20e23] 60e70 70e80 >600 [20] 270e550 390e550 565/1.000(GT) [20e23] 1 86 13 [24] 31.4 140 133 [24]

GT: Gas turbine.

and components listed in Table 2. In case of LF and ST, the Direct Steam Generation (DSG) was implemented. This concept has the advantage of avoiding the use of the HTF-water/HTF-steam heat exchangers once steam is generated (or water is preheated) directly in the receivers. As an important remark, however, it should be noted that the transient behavior of solar irradiance and the occurrence of two-phase flow in the receivers constitutes a challenge that might be addressed by the implemented control system [25]. In case of PT, on the other hand, thermal oil was used as HTF once this is the most widely used concept. Certainly, additional combinations would be possible, as for example LF operated with molten salts HTF [22]. Nevertheless, it was aimed here to reduce the number of simulations to be made while bringing subsidies to the analysis of the solar aided cogeneration plant concept. Three integration layouts between CSP and cogeneration plant were evaluated, namely: (layout 1) solar feedwater pre-heating; (layout 2) saturated steam generation with solar energy and post superheating in biomass steam generators and (layout 3) generation of superheated steam in parallel with biomass steam generators. Layouts 2 and 3 were applied aiming to increase the solar share of hybridization in comparison with layout 1. Specifically in case of layout 3, the solar-only operation mode was turned possible once the solar field was operated in parallel with biomass steam generators by generating superheated steam with the same required temperature and pressure parameters. The CSP technologies were applied to each hybridization scenario according to the steam cycle injection point temperature requirement. Thus, the linear Fresnel and the parabolic trough technologies were implemented in layouts 1 and 2, while solar tower was implemented in layout 3. The simplified process flow diagrams of the three integration layouts are shown in Fig. 2, where it is also identified the CSP technology applied in each case. 2.3. Problem modeling The simulations of proposed layouts were performed considering two distinct approaches. In case of cogeneration power plant assisted by linear Fresnel and solar tower, the power plant calculation program Ebsilon®Professional (version 10.05) distributed by STEAG GmbH was used. In case of cogeneration power plant assisted by parabolic trough solar field, the simulations were performed using the calculation software Engineering Equation Solver (EES®), version 9. This allowed comparison of obtained results regarding the cogeneration power plant components performance. The list of references of implemented models is presented in

Table 3. In both considered approaches the steam cycle and solar field steady state part load performance was predicted as weather conditions were changed along the year. Regarding steam generators simulation in EES®, performance data were imported from Ebsilon®Professional by using the lookup table function [31]. A detailed in-house simulation model for the bagasse steam generators is under development and might be presented as a next step. The proposed integration layouts of parabolic trough and cogeneration power plant are presented in Fig. 3. The solar feedwater heating (Fig. 3-a) was performed considering the inline approach in which feedwater was pre-heated upstream the bleedoff steam feedwater heater. On-off type valves were used to divert feedwater to solar pre-heater as heat transfer fluid temperature reached the minimum required level. In case of saturated steam generation (Fig. 3-b), the diverted feedwater was pre-heated and boiled to be then re-introduced to biomass steam generators for post-superheating. The performance of the HTF-water heat exchangers was predicted using the Ɛ-NTU method [34]. The feedwater pre-heaters consisted on shell-and-tube counter flow heat exchangers with HTF in the shell side. The overall heat transfer coefficient-area product, UAeco [kW/K], was dependent on mass flows of water and HTF, as represented by Eq. (1) [35]. The subscripts fw and htf refers to feedwater and thermal oil, respectively, and ref refers to design point condition.


m_ 0:8 $ m_ 0:8  m_ 0:8 þ m_ 0:8 UAeco fw htf ref ;fw ref ;htf $ ¼ 0:8 0:8 0:8 UAeco;ref _ _ _ $ m þ m m_ 0:8 m ref ;fw ref ;htf fw htf

! (1)

The evaporation process was performed by considering an evaporation section composed of a bundle of tubes exposed to a cross flow of boiling water. The HTF was in the tubes side [36]. The overall heat transfer coefficient-area product UAevap [kW/K] of CSP boiler was updated regarding the ratio of actual HTF mass flow to its design reference value, as represented by Eq. (2) [35]. This equation considers that UAevap is relatively less sensible to the steam mass flow variation.

UAevap ¼ UAevap;ref

m_ htf m_ htf ;ref

!0:8 (2)

Table 2 Selected technology options for the present case study.

Solar field/heliostats model Solar receivers Heat Transfer Fluid (HTF)

LF

PT

ST

NOVA-1 [26] Supernova [27] Water/steam

LS-2 [28] Luz CERMET [28] VP-1 oil [29]

(10.93  10.93) m2 heliostats DSG receiver [30] (150 m over ground) Water/steam

DSG: Direct Steam generation.

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Fig. 2. Simplified process flow diagrams of the three studied integration layouts and CSP technologies applied in each case.

Table 3 List of references of implemented models.

Steam cycle components Bagasse steam generators LF PT ST

Ebsilon®Professional (version 10.05)

Engineering equation Solver® (version 9)

Ebsilon implemented components [32] Ebsilon implemented components [32] Ebsilon implemented components [32,33] e In-house model [30]

In-house model [19] Performance data imported from Ebsilon®Professional e In-house model [19] e

2.4. Thermodynamic and economic analysis The performance indexes implemented in this work to evaluate the integration of base case plant with CSP are described in this section. The additional power generated off-season, AE [MWh], due to the economized amount of bagasse during harvest and due to the

solar-only operation in case of layout 3 was quantified by Eq. (3),

AE ¼

X

_ W h

(3)

offseason

_ [MW] is the net power output during off-season for the where W h hybrid plant. This represents the solar equivalent electricity.

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Fig. 3. Integration of PT with cogeneration power plant: (a) solar feedwater heating (Layout 1); (b) saturated steam production (Layout 2).

The economic feasibility of hybrid systems was performed considering the Levelized Cost of Electricity (LCOE) [US$/MWh] according to the methodology proposed in Ref. [37]. The LCOE was calculated for the additional power generated off-season, AE [MWh], by comparing it to the capital and annual costs due to solar integration (Eq. (4)),

Plt LCOE ¼

þ LC þ O&MÞ$ð1 þ rÞt Plt t t¼0 AE$ð1 þ rÞ

t¼0 ðCC

(4)

where CC, LC and O&M [US$] are the capital, land and annual operation and maintenance costs. The parameter r represents the interest rate and lt is the lifetime of plant.

3. Base case power plant The sugarcane processing factory location, crushing capacity, operational parameters and TMY data (dry bulb temperature DB [
C], wet bulb temperature WB [
C], direct normal irradiance Gbn [W/m2], rain precipitation rp [mm] and wind velocity vw [m/s]) used for the cogeneration power plant design and simulation are described in Table 4. The state of Mato Grosso do Sul consisted on the focus of this work due to the high incidence of new greenfield cogeneration power plants. It might be noted, nevertheless, that the code and approach here developed can be extended to other regions and power plants of interest. The layout and main results related to the simulation of cogeneration plant at design point operation are presented in Fig. 4. The steam cycle is equipped with two 170 t/h capacity steam generators that produce superheated steam at 525
C/67 bar (point 1). The base case scenario is operated during harvest burning 142.5 t/h of bagasse prevenient from sugarcane crushing station. The major part of superheated steam (point 2, 220 t/h) is expanded in the back-pressure turbine (BPST) until 2.5 bar as required by the process heat demand. In parallel, roughly one third of the

superheated steam (point 6, 117.4 t/h) is expanded in the condensing-extraction turbine (CEST). Three extractions are implemented in CEST turbine (17.5 bar e point 7; 5 bar e point 8 and 1.8 bar e point 9) to preheat feedwater to 200
C (point 20). The CEST exhaust steam (point 10) is condensed in a wet-cooled condenser. The properties of sugarcane bagasse considered in simulations are presented in Table 5. To calculate the amount of produced bagasse at the sugarcane crushing station output, the fibers to stalk ratio of sugarcane was considered equal to 0.125 [38]. Based on this assumption, 250 kg of wet bagasse with a moisture content of 50% was produced for each ton of crushed sugarcane. It was considered that 95% of wet bagasse was directly burned in steam generator, while the remaining 5% was stored as a back-up to start-up the plant on next coming season. Two identical natural circulation subcritical water tube steam generators composed of furnace, boiler (boiling occurring in water tube walls enclosing furnace), convective superheating system with a desuperheater positioned in between the sections SH1 and SH2, economizer (ECO) and tubular air heaters AH1 and AH2 with air representing the external flow were modeled. The steam capacity of each unit amounts 170 t/h. In Table 6 the heat exchange area (in squared meters), the longitudinal (sl, in meters) and transversal (st, in meters) spacing of tubes, the diameter (d, in meters) and thickness (e, in meters) of tubes as well as the arrangement of bundle of tubes are presented. In Table 7 are presented the adopted assumptions related to the thermal losses of steam generators at design point. The design point results related to the detailed modeling of steam generators are presented in Fig. 5. As it can be seen, 208 t/h of air was preheated from ambient temperature to 296
C. Additional 23 t/h of air (10% of total) was used as bagasse carrying air. Both streams consisted in 30% air excess as required to optimize the combustion process. Feedwater (173.9 t/h) was heated in economizer from 200 to 276.6
C. Blowdown consisted of 3% of main

Table 4 Input parameters considered for cogeneration power plant design and simulation. Parameter

Unit

Value

Plant site Coordinates TMY data Annual DNI Time resolution Sugarcane crushing capacity Annual sugarcane crushing Effective operation hours in harvest Harvest starting day Process specific electricity demand Process steam demand (heat demand)

e e e kWh/m2-year e t/h Mt H e kWh/t t/h

Campo Grande, Mato Grosso do Sul, Brazil (20.45; 54.62) Meteonorm® 7.0 1502 One-hour time steps 600 3 5000 01st April 28 220 (2.5 bar; x ¼ 1)

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Fig. 4. Base case cogeneration power plant layout and simulation results at design point.

Table 5 Sugarcane bagasse properties [38]. Proximate analysis [wt %, ar]

Ultimate analysis [wt %, daf]

LHV [kJ/kg, ar]

Fixed carbon

Volatile matter

Moisture

Ash

C

H

N

O

S

6.9

41.6

50.0

1.6

45.6

5.8

0.4

48.2

0.0

7162

wt %: percent by weight; ar: as received; daf: dry and ash free. C: carbon; H: hydrogen; N: nitrogen; O: oxygen; S: sulfur; LHV: lower heating value.

Table 6 Configuration of heat exchangers used in steam generators. Parameter

Unit

Superheater 2 (SH2)

Superheater 1 (SH1)

Economizer (ECO)

Air heater 2 (AH2)

Air heater 1 (AH1)

Area sl st d e Arrangement

m2 mm mm mm mm e

520.5 134.0 102.0 44.5 3.8 Aligned

1041.0 134.0 102.0 44.5 3.8 Aligned

1307.5 134.0 100.0 50.8 3.8 Aligned

3030.0 87.0 100.0 63.6 2.3 Scattered

3030.0 87.0 100.0 63.6 2.3 Scattered

Source: Equipment manufacturer data.

steam mass flow in order to maintain impurities concentration under specification limits. Finally, 168.7 t/h superheated steam was produced by heating saturated steam (x ¼ 1/72 bar) from boiler drum until the required final parameters (525
C/67 bar). It is important to notice that 17.2 t/h of saturated water (x ¼ 0/72 bar) was injected in between sections SH1 and SH2 at design point operation. At part load this amount was gradually reduced to keep main steam temperature constant. A simulation for the entire harvest period considering one-hour time steps was performed while keeping the net electricity exported to the grid equal to the reference design point condition

(46.6 MW) and respecting the ambient weather fluctuations e results are presented in Table 8. The required time to crush 3 Mt of sugarcane was equal to 5000 h, when 750,000 t of bagasse was produced, 710,316 t of bagasse was burned (94.7% of total) and 233,025 MWh was exported to the grid. The plant operation started at 1st April and was finished at 3rd December. The total harvest period was 5921 h, what represented a capacity factor of 84.4%. The total duration of sugarcane harvest was mainly prescribed by rainfall, as during rainy hours as well as during the necessary time for soil drying it was not possible to harvest sugarcane. The procedure used to

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Table 7 Design point assumptions adopted for steam generators simulation. Parameter

Unit

Adopted assumption

Source

Heat loss to ambient Ash collection points (residue mass flow fractions) Furnace bottom Economizer flue gas exit section Between AH1 and AH2 Unburned carbon content in residue Furnace bottom Economizer flue gas exit section Between AH1 and AH2 CO emissiona Blowdowna Air excessa

e

0.8% of (fuel flow  LHV)

[39] [40]

% % %

28 32 40

% % % mg/Nm3 e %

20 15 10 100 3% of SH steam mass flow 30

a

[40]

Equipment manufacturer data.

Fig. 5. Base case steam generator layout and simulation results at design point operation.

Table 8 Summary of results for the base case cogeneration power plant over the harvest period. Parameter

Unit

Value (5000 h of operation)

Produced bagasse Burned bagasse Stored bagasse BPST gross output CEST gross output Net electricity production Auxiliary electricity consumption Process electricity consumption Process heat consumption Net electricity exported to the grid

t t t MWh MWh MWh MWh MWh MWh MWh

750,000 710,316 39,684 211,255 121,325 317,025 15,555 84,000 691,097 233,025

identify the operating days is presented in Ref. [19]. This result matches with the capacity factor of sugarcane cogeneration plants located in the Center-South region of Brazil that normally ranges from 80% to 85% [1,2]. The base case results presented in Fig. 4 and Table 8 were obtained using the EES® model. The results obtained with Ebsilon®Professional model matched accordingly. The deviations in terms of harvest gross electric energy output [MWh], harvest electric energy exported to the grid [MWh] and harvest fired bagasse [tons] were

0.1%, 0.7% and 0.3%, respectively. When simulating the hybrid layouts (Section 4), the improvement in terms of additional electric energy produced in off-season was calculated by using the same simulation approach for each presented layout. Thus, in case layouts 1 and 2 equipped with PT system, the EES® was used to both base case and hybrid plants. In the same way, the cases involving LF and ST were simulated by using the Ebsilon®Professional model. The cogeneration plant configuration and operational parameters presented in this work were defined in cooperation with equipment suppliers aiming to represent the default layout currently applied to the sugarcane sector in Brazil. Commonly, the process steam required by a sugarcane processing factory is provided as the exhaust steam of a back-pressure turbine (BPST). Once the direct burning of available bagasse obtained after the sugarcane juice extraction process turns possible to generate additional steam than the mass flow required by the process, a condensingextraction turbine (CEST) might be used in parallel with BPST to increment the power production. Finally, the cogeneration power plant here evaluated was designed to operate also during offseason period if bagasse is available. This represents an approach currently adopted in the sugarcane sector where electricity production can be improved by purchasing bagasse if market prices are favorable. Results related to the cogeneration power plant offseason operation are presented in Fig. A1 of appendix.

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4. Hybrid layouts

Table 10 Adopted assumptions and cost data used for economic analysis.

4.1. General assumptions

Parameter

The hybridized power plant operation procedure was performed as it follows:  Harvest operation: the solar heat load provided bagasse economy and the amount of economized fuel was stored to be used during off-season;  Off-season operation: the power plant was operated during offseason by burning the economized bagasse;  Solar-only operation: in case of layout 3, superheated steam was generated in ST system and the solar-only operation of CEST turbine was turned possible during sunny hours. The design point weather parameters considered for solar field sizing in all evaluated scenarios are presented in Table 9. The assumptions and cost data used for economic analysis are presented in Table 10.

4.2. Design point analysis In case of layout 1, the solar heat was used to replace the high pressure bled-off steam extraction of the condensing-extraction turbine (CEST) of cogeneration cycle. For this purpose, both LF and PT systems were designed to provide the thermal output of 17 MW at design point. Therefore, the required PT aperture area was calculated as 33,912 m2 in a land area of 14 ha. In case of LF, the required aperture area was calculated as 36,965 m2 in a land area of 7 ha. Due to the displacement of bled-off steam consumption by solar heat, the amount of burned bagasse in steam generators was reduced by 6% (8.3 t/h fuel economy at design). The integration layout 2 enabled the production of saturated steam with solar heat aiming to reduce the bagasse consumption of biomass steam generators. Therefore, part of the main feedwater mass flow was diverted to a typical solar steam generator in case of PT, whereas in case of LF, it was directly fed to the solar field. In both cases, saturated steam at 72 bar (drum pressure) was produced, which was then joined to the main mass flow within the steam generators for superheating. Under this integration layout, a technical boundary condition imposed by the biomass steam generators manufacturer was respected. This consisted on reducing both steam generators load to a minimal level of 85%. This limiting condition was related to the load at which the mass flow of desuperheating system was turned zero. For this purpose, both LF and PT systems were designed to provide the thermal output of 34 MW at design point. Therefore, the required PT aperture area was calculated as 67,824 m2 in a land area of 29 ha. In case of LF, the required aperture area was calculated as 78,550 m2 in a land area of 15 ha. Due to the production of saturated steam by solar heat, the amount of burned bagasse in steam generators was reduced by 15% (21.7 t/h fuel economy at design). Finally, in case of layout 3, superheated steam at 525
C and 67 bar was produced in the solar tower system positioned in parallel with bagasse steam generators. As for integration layout 2, both steam generators load was reduced to the minimum level at Table 9 Design point weather parameters considered for solar field sizing. Design point parameters Direct normal irradiance, Gbn,ref Dry bulb temperature, DBref Wind velocity, vw,ref

Unit

Value 2

W/m
C m/s

953 (solar noon, 23rd September) 28 9.5

Parabolic trough Solar fielda Economizer Boiler Fresnel Solar fielda Solar Tower Heliostats field Receiver General EPC and contingencyb Site improvements Land investmentc Material replacement Employee chargeb,c Interest rate, r Life time of plant, lt a b c

Unit

Adopted assumption

Source

US$/m2 US$/kW US$/kW

400 27 47

[41] [41]

US$/m2

360

US$/m2 US$/kW

200 250

[42] [42]

US$ US$/ha US$/ha US$/year US$/year e Years

20% of DC 250,000 20,000 1% of DC 40,000 8% 25

[14] [43] [44]

Quoted cost. Considered not dependent on solar field area. Estimated cost.

which the mass flow of the desuperheating system was turned zero. This consisted on reducing both steam generators load to the minimum level of 65%. For this purpose, the ST system was designed to provide the thermal output of 79.4 MW at design point. Therefore, the required heliostats aperture area was calculated as 234,480 m2 in a land area of 77 ha. Due to the production of superheated steam by solar heat in parallel with bagasse steam generators, the amount of burned bagasse was reduced by 35% (49.9 t/h fuel economy at design). It is also important to notice that the ST thermal load turned possible to operate the CEST turbine of cogeneration plant in the solar-only mode. The results for solaronly operation of power plant at design point condition are presented in Fig. A2 of appendix. 4.3. Annual simulations The three hybridization layouts were simulated for different Solar Multiples (SM) in order to perform a sensitive analysis according to solar field aperture area. The simulations performed for each integration layout are described in Table 11. The Levelized Cost of Electricity (LCOE) was the criteria used to identify the most feasible solar field area of each evaluated layout. This parameter was calculated for the additional electricity produced due to the hybridization. In Fig. 6 the solar field area sensitive analysis is exemplified for layout 3 equipped with ST e the same general pattern was observed for layouts 1 and 2 as well as for PT and LF technologies. As it can be seen, the additional electricity generated was increased asymptotically as the solar field aperture area was increased. The larger the area of solar field e here represented by the factor SM, the higher the number of hours in which defocusing was applied. This caused degradation of solar field and solar-to-electricity efficiencies. Regarding economic analysis, the costs related to EPC, contingency and employees charge were considered weakly correlated with solar field size for the evaluated SM range (assigned as constant costs and equal to the SM ¼ 1.0 case). The parameter LCOE, as a consequence, showed to be a function of SM and the most feasible option was identified for each layout and solar field technology. The additional electricity produced for all evaluated integrations for the identified optimum SM are presented in Fig. 7. In layouts 1 and 2 the PT technology provided a higher solar electricity output when compared with LF. This was related to the higher annual solar field efficiency of PT which was caused mainly by the smaller incidence angles observed in the beginning and in the end of the

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E.K. Burin et al. / Energy xxx (2016) 1e13

Simulated layouts

CSP technology

Simulated solar multiples (SM)

Overall number of simulations

Layout 1

PT LF PT LF ST

0.9e1.4 0.8e1.4 0.9e1.3 0.8e1.4 0.8e4.0

6 7 5 7 10

Layout 2

LCOE [US$/MWh]

Layout 3

350

80

310

60

270

40

230

20

LCOE [US$/MWh] AE [MWh]

190 0.0

1.0

2.0

3.0

0 4.0

5.0

Add. Electricity produced [GWh]

Table 11 Number of simulations performed for each layout.

Solar Multiple (SM) Fig. 6. Additional solar equivalent electricity and LCOE for different solar multiples in case of layout 3 hybrid system.

related to the bagasse steam generators and solar field thermal energy outputs for base case and hybrid layout 3 (ST solar field) are exposed in Fig. 9. As it can be observed, in layout 2 the total solar field thermal energy output (purple line, Fig. 8) was exclusively used to manage part of bagasse from harvest to the off-season period (compare the blue and red lines in Fig. 8) e the same operation strategy was adopted for PT and LF technologies as well as in layout 1. In layout 3, on the other hand, the solar field thermal energy output (purple line, Fig. 9) was not only used to displace bagasse consumption (compare the blue and red lines in Fig. 9), but also to provide the steam cycle operation during off-season in a solar-only mode (green line, Fig. 9). Under this scenario, the economized bagasse during harvest was preferentially used at night or in rainy days and solar-only operation was performed during sunny hours. This was an important aspect once the capacity factor of solar field was maximized by its operation regardless of the availability bagasse. This leaded to the improvement of electricity exportation to the grid by 19.8% under layout 3 in comparison with base case. Another aspect evaluated in this work consisted on the required mirrors aperture area and total land area for solar field installations (Fig. 10). For layouts 1 and 2, the aperture area required by LF was higher when compared with PT due to the lower peak efficiency of LF when compared with PT technology. Regarding land area, on the other hand, LF showed a significant advantage in comparison with PT, requiring 54% and 49% land respectively for layouts 1 and 2. The compactness of LF might be of great importance to enable the implementation of CSP in areas where the land is used for crop plantation and, as a consequence, its cost is high. Finally, ST aperture and land areas were higher in comparison with the other evaluated scenarios due to the higher solar thermal load required by layout 3. Regarding economic analysis, the capital and O&M costs of studied scenarios are presented in Fig. 11, while in Fig. 12 the LCOE results are showed. The adopted assumptions for equipment and O&M costs were based on consultations with equipment suppliers and literature survey. The life time, lt, of evaluated layouts was 25 years as it is normally stated in literature for the economic evaluation of stand-alone and hybrid CSP plants [6,14,37,46]. In case of interest rate, it is higher if risks involved are higher. Investments in regulated electricity markets, for instance, might have lower risks in comparison with investments in open and competitive markets [37]. In this work, the interest rate parameter, r, was set as 8% as a preliminary hypothesis adopted by the authors. In both layouts 1 and 2 the capital and O&M costs were lower for LF in comparison with PT technology (14% and 11%, respectively, for capital cost). Observing LCOE, nevertheless, LF presented similar or even higher electricity generating costs in comparison with PT due to its lower annual efficiency. The same aspect was identified by Morin et al. [44] when comparing the economic feasibility of CSP power plants equipped with PT and LF. Under the presented

50

250

40

200

Bagasse (hybrid)

150

Solar field

Bagasse (base case) Thermal load [MW]

Add. electricity produced [GWh]

days when compared with LF. This is in accordance with results presented in Refs. [44] and [45], where the PT and LF technologies were compared for electricity production. Layout 2 provided higher solar electricity output when compared with layout 1 due to the higher thermal load required to reduce the evaporator thermal load of bagasse steam generators. Similarly, the solar share of solar feedwater heating approach was also low in other cases presented in literature e generally limited to around 1% of annual electricity generation [6,13,14]. In this work, the electricity exported to the grid under layout 1 was increased by 1.7% in case of PT and by 1.3% in case of LF. Finally, it is clear that layout 3 provided a significantly higher solar electricity output when compared with the other evaluated cases. This was not only due to the higher thermal load associated with the reduction of steam generators load to 65% in peak solar irradiance hours, but also due to the possibility of solaronly operation under the specific characteristics of the case study here presented (see Fig. A2 of appendix for the results for solar-only operation of power plant at design point condition). In order to clarify the advantage of solar-only operation, the duration curves related to the bagasse steam generators and solar field thermal energy outputs for base case and hybrid layout 2 (PT solar field) are exposed in Fig. 8. Likewise, the duration curves

9

30 20 10

100 50 0

0 PT

LF Layout 1

PT

LF Layout 2

ST

0

2000

4000

6000

8000

Time [h]

Layout 3

Fig. 7. Additional solar equivalent electricity generated due to solar hybridization.

Fig. 8. Thermal energy transferred to water-steam cycle related to bagasse and solar energy inputs for base case and hybrid layout 2 equipped with PT solar field.

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10

E.K. Burin et al. / Energy xxx (2016) 1e13

700

Solar-only

Bagasse (hybrid)

150

Solar field

100 50

0

2000

4000

6000

8000

300 200

PT

250

80

200

60

150

40

100

20

50

Thousands

100

Mirrors apperture area [m²] (markers)

Fig. 9. Thermal energy transferred to water-steam cycle related to bagasse and solar energy inputs for base case and hybrid layout 3 equipped with ST solar field.

0

0 PT

LF

PT

Layout 1

LF

ST

Layout 2

Layout 3

Fig. 10. Comparison of mirrors aperture area and land area required for solar field installation.

900

100

750

80

600

60

450

40

300

20

150

0

0 PT

LF

Layout 1

PT

LF

Layout 2

O&M costs [US$] (markers)

120

Thousands

configurations, the authors identified that LF solar field specific cost [in US$/m2] should be 50e80% of PT solar field specific cost to break even the generating costs e where 80% was found after improvements in LF system. The LCOE results reached the range of 500e630 US$/MWh in case of hybridization layouts 1 and 2 e well above the LCOE range of 70e170 US$/MWh indicated by Refs. [6,14,46] for the SAFWH approach of biomass and coal fired power plants. It should be noted, however, that according to the TMY data used in simulations, the DNI incidence during the eight months of sugarcane harvest was limited to 1034 kWh/m2-harvest. This represented 69% of total annual DNI incidence of 1502 kWh/m2-year for the city of Campo Grande, MS. Thus, at least 31% of solar DNI was not used in

Millions

400

0

Time [h]

Required land area [ha] (bars)

500

100

0

Capital cost [US$] (bars)

600

Bagasse (base case)

200

LCOE [US$/MWh]

Thermal load [MWth]

250

ST Layout 3

Fig. 11. Investment and O&M costs of solar hybridization for the distinct evaluated layouts.

LF Layout 1

PT

LF Layout 2

ST Layout 3

Fig. 12. LCOE of additional solar equivalent electricity for the distinct evaluated layouts.

layouts 1 and 2 once solar field was out of operation during offseason. Under layout 3, in the other hand, LCOE was significantly reduced, reaching 220 US$/MWh e close to the bottom margin of the LCOE range of 200e400 US$/MWh reached nowadays in commercial CSP plants depending on technology, location and level of storage [47]. This is an attractive result if it is considered the relatively low DNI level of 1502 kWh/m2-year incident in the studied site. As exposed before, the solar-only operation (see duration curves presented in Figs. 8 and 9) e which maximized the capacity factor of solar field e was directly linked to the improved economic performance of layout 3 in comparison with layouts 1 and 2. It is important to notice, in addition, that layout 3 could also be possible with PT or LF depending on main steam parameters of cogeneration power plant or even considering the utilization of molten salts as heat transfer fluid. These options might be also evaluated in design phase when planning the hybridization of a specific cogeneration power plant. In the last auctions performed in the Brazilian electricity controlled market in 2015, the electricity produced in thermal power plants (natural gas and biomass in general) was contracted on the average price of 80 US$/MWh. Onshore wind was contracted on the average price of 50 US$/MWh. The commercialization of solar energy was performed exclusively for photovoltaics on the average price of 85 US$/MWh [48]. Thus, independently on the power plant concept, the inclusion of CSP in the Brazilian electricity market would require today alternative subsidized contracts. It should be kept in mind, nevertheless, that there is yet a great room for CSP costs reduction. Despite the recent growth in terms of installed capacity (totalizing today around 4.7 GW), the CSP market is yet in its infancy in comparison with other renewable electricity generation technologies. As an example, the installed capacity of photovoltaics today is around 139 GW, from which about 80 GW is installed in Europe [49]. Specifically in case of Brazil, the combination of solar and biomass resources might be the key to turn CSP economically feasible and to provide base load power supply. 5. Conclusion The hybridization of sugarcane bagasse cogeneration power plants equipped with BPST and CEST with CSP turns possible to improve the annual electricity output of these plants by maximizing their capacity factor while providing additional off-season operation. This represents a gain due to the use of existing infrastructure that otherwise would stay out of operation part of the year when no sugarcane was available. Solar feedwater heating has key the advantage of requiring minimal modifications on the original plant and investment costs related to solar integration are reduced. Nevertheless, the small

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E.K. Burin et al. / Energy xxx (2016) 1e13

solar share and the incapability of solar-only operation limit the additional electricity output and the capacity factor of solar field. Saturated steam production in parallel with bagasse steam generators turns possible to improve the solar share. An important drawback resides in the complexity inherent to the retrofit and operation of biomass steam generators and heat imbalances that might be observed. This integration has also the incapability of solar-only operation. Finally, solar superheated steam generation provides the highest solar share in comparison with other layouts here considered. The power plant operation in a solar-only mode improves the solar field capacity factor and, as a consequence, the economic feasibility of investment. This layout may also not require major modifications in hosting steam cycle as biomass steam generators are operated in normal part load. Regarding CSP technologies, no major difference in terms of economic feasibility was obtained between PT and LF in layouts 1 and 2 for the considered economic assumptions and problem specific characteristics (e.g. plant configuration and operational parameters, site weather conditions, operation seasonality of cogeneration plants). The ST technology under layout 3 provided the best result in terms of LCOE (220 US$/MWh) what can be considered competitive with the CSP power plants currently under operation as reported in Ref. [47]. This is an attractive result if it is considered the relatively low DNI level incident in the plant site (1502 kWh/m2-year). Nevertheless, the results here presented clearly show the advantage inherent to year-round operation of

11

main steam parameters of cogeneration power plant or even considering the utilization of molten salts as heat transfer fluid. Acknowledgments The authors acknowledge the National Council for Scientific and Technological Development (CNPq) and the funders of the program “new partnerships (iNOPA-Solar Power 13)”, namely the German Federal Ministry for Economic Cooperation and Development (BMZ) (project ref. no. 57072739) and the Brazilian Coordination for the Improvement of Higher Education Personnel (CAPES) (project ref. no. 05/14), for the financial support. The authors acknowledge also the companies TGM turbines and Caldema Industrial Equipment Ltda for the technical support. Appendix. off-season and solar-only simulation results The off-season simulation results of power plant under summer weather condition are presented in Fig. A1. The industrial process and BPST are out of operation once no sugarcane crushing is performed. Thus, as superheated steam demand is significantly reduced, one steam generator is operated at part load while the second is turned off. It is important to note that this is the reason why cogeneration plants are normally designed with two steam generators in parallel. If just one unity would be used, too deep part load would be necessary during off-season operation.

Fig. A1. Base case cogeneration power plant simulation results at off-season operation.

solar field and might not be interpreted as a suggestion to exclude the LF and PT technologies of future analysis once they could be also implemented for superheated steam generation depending on

In case of layout 3, the solar tower system was designed to reduce the biomass steam generators load until 65% during harvest. As it can be seen in Fig. A2, the design point thermal load of

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E.K. Burin et al. / Energy xxx (2016) 1e13

79.4 MW of solar field turned also possible to generate superheated steam to operate the CEST turbine at 27.3 MW. As in case of offseason operation, the industrial process and BPST are out of operation once no sugarcane crushing is performed.

Fig. A2. Design point simulation results of hybrid cogeneration power plant at solar-only operation (the bagasse steam generators are not shown to turn the flowchart clearer).

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