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Article Cite This: Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

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Systematic Synthesis and Evaluation of Thermochemical Conversion Processes for Lignocellulosic Biofuels Production: Total Process Evaluation and Integration Paola Ibarra-Gonzalez and Ben-Guang Rong* Department of Chemical Engineering, Biotechnology and Environmental Technology, University of Southern Denmark, Campusvej 55, DK-5230 Odense M, Denmark S Supporting Information *

ABSTRACT: Thermochemical conversion of lignocellulosic biomass and downstream processing represents an attractive alternative in biomass-to-liquid fuels (BtL) production. There are several thermochemical conversion routes that not only can produce fossil-like fuels but also can simultaneously produce a wider range of fuels in terms of gasoline and diesel profiles. In this work, synthesis, evaluation, and integration of conversion of softwood biomass to liquid transportation fuels are investigated within a systematic framework. Five BtL conversion processes were presented by combining promising thermochemical conversion, upgrading, and separation technologies. Process flowsheet setups and simulations are performed with Aspen Plus version 8.8. The total production processes are evaluated with both products profiles and costs indicators for capital, energy, and total annual costs. Finally, opportunities for process integration to improve the process performance are explored for four integration scenarios. The base case processes with and without integrations were compared to quantify the effect of the integrations on the total annual cost (TAC) and emissions. It was obtained that energy and mass integration could reduce the TAC of the gasification-LTFT-fractional upgrading-fractionation process by 25% and liquid and gas emissions by 97% (wt) and 43% (wt), respectively.

1. INTRODUCTION The transportation sector accounts for more than half of the world oil consumption and is one of the largest contributors to worldwide greenhouse gas emissions. By the end of 2016 in the United States 95% of petroleum usage went directly to transportation fuels and only 5% of liquid transportation fuels production originate with renewable resources such as ethanol and biodiesel.1 Thus, the transportation industry is an opportune sector for replacing petroleum consumption, and it is imperative that alternative methods of producing liquid transportation fuels are investigated. The U.S. Energy Information Administration (EIA) has identified “non-petroleum”-derived sources as the means for satisfying the supply demand gap, with a particular focus on biomass.2 Biomass is particularly attractive because it is the only current renewable source of liquid transportation fuel, which can also reduce the petroleum dependence3,4 and unlike fossil fuels does not increase atmospheric carbon dioxide content.5 First generation biofuels are generally focused on corn-based ethanol and soybean-based diesel, but the use of these feedstocks has led to concerns regarding the impact on the price and availability of these feedstocks as sources of food or feed.6 Lignocellulosic biomass resources, such as wood and wood wastes, agricultural crops and their waste byproducts, grasses and energy crops,7 could be a more sustainable source © XXXX American Chemical Society

of biofuels in the future. The wood residues potential is especially important in countries where forests cover a considerable part of the whole land area, e.g., North America and the Nordic countries.8 Biomass is already used to meet a variety of energy needs, including generating electricity, heating homes, fueling vehicles, and providing process heat for industrial facilities.9 The process to produce biofuels from biomass through a thermochemical route is called biomass to liquid (BtL), and it is currently recognized as one most promising solution in pursuing the global sustainability in terms of energy, economy, and climate change. The objective is to produce fuels that are similar to those of current fossil-derived gasoline and diesel and hence can be used in existing fuel distribution systems and with standard engines.10 Thermochemical conversion processes can be subdivided into gasification, pyrolysis, supercritical fluid extraction, and Special Issue: 2017 European Symposium on Computer-Aided Process Engineering Received: Revised: Accepted: Published: A

December 29, 2017 February 22, 2018 February 28, 2018 February 28, 2018 DOI: 10.1021/acs.iecr.7b05382 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

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Industrial & Engineering Chemistry Research direct liquefaction,9 by which biomass is converted to syngas, bio-oil, char, and gaseous products. From these, bio-oil can be used as an intermediate step to convert it into higher energydense transportation liquid fuels such as diesel and gasoline or the syngas can be directly burned. In this sense, thermal or chemical conversion of biomass is very similar to that of coal.11 However, the biofuels’ success, market share, and speed to replace the fossil fuels to a large extent depend on the production technology and the total production costs. Biofuels cost takes into account feedstock production and transport, conversion to final fuel, separation and purification to reach the final products, fuel transport and storage to the point of refueling. The estimated biofuel production costs can show significant differences depending on factors such as scale of the plant, technology complexity, and feedstock costs. For instance, for first generation biofuels today, the main cost factor is feedstock, which accounts for 45−70% of total production costs, whereas for advanced biofuels the main factor is capital costs (35−50%), followed by feedstock costs (25−40%).12 Synthesis and integration of new thermochemical production systems can contribute to reduce BtL-fuel’s manufacturing costs and increase their viability. However, the majority of the papers on thermochemical conversion processes focus on the experimental reactions and their modeling, with little attention on synthesis of the total production process including the upgrading and separation technologies. Likewise, several authors (Baliban et al., 2013; Wright et al., 2010) have proposed thermochemical-based refineries paying particular attention to a specific thermochemical conversion process without simultaneous comparison with other conversion processes. Moreover, the BtL refinery unit operations are calculated using discrete sources to estimate operating and capital costs for the evaluations. For that reason, in this study, we propose a process synthesis framework for the conversion of softwood into transportation fuels, where five thermochemical production systems were explored. The goal is on one hand to synthesize and evaluate the total production processes within the same framework and on the other hand to determine the optimal process technologies for liquid fuel production that present the minimum overall system cost and that could increase the transportation fuels production. The novelty of this work relies on the systematic synthesis of BtL processes of combined thermochemical conversion, upgrading and separation technologies specifically for softwood BtL fuels, and the use of rigorous simulations to predict thermodynamic and physical properties, energy consumption, and equipment designs and costs for the base cases’ unit operations within the same framework. Moreover, we defined several scenarios involving mass integration and energy integration to quantify their effects on the conversion processes total annual cost and emissions reduction.

Figure 1. Systematic methodology for synthesis, simulation, integration, and evaluation of the total thermochemical process for BtL fuels.

as a systematic procedure to analyze distinct process designs to convert softwood to liquid fuels and evaluate the impact of the feedstock, thermochemical conversion, upgrading technologies, and separations units in the total annual cost and to finally determine the alternative for BtL fuels production that presents the minimum overall system cost and highest conversion to biofuels. For each process, the synthesis and simulation setup are focused on the three distinct sections which formulate the distinct total thermochemical process alternatives. In total, five base case processes consisting of the combination of different thermochemical conversion routes, upgrading technologies, and separation units were proposed: pyrolysis-hydroprocessing-separation (BC1-PHS), pyrolysiscatalytic cracking-fractionation (BC2-PCCF), gasificationHTFT-fractional upgrading-fractionation (BC3-GHTUF), gas-

2. METHODOLOGY The aim of this paper is twofold: first, to apply process synthesis for the setup of the individual conversion processes of softwood into transportation fuels followed by simulation and evaluation to understand the basic features of the processes; second, explore different process integration scenarios to study mass and energy integration for reduction of total production costs and emissions. The methodology for synthesis, simulation, integration, and evaluation of the total thermochemical process for BtL fuels is illustrated in Figure 1. The overall methodology was formulated B

DOI: 10.1021/acs.iecr.7b05382 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

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Industrial & Engineering Chemistry Research ification-LTFT-fractional upgrading-fractionation (BC4GLTUF), and gasification-HTFT-hydroprocessing (BC5GHTH). The unit operations, operating conditions, conversions, reactions, products obtained (pyrolysis oil, syngas, hydrocarbons, biocrude, and syncrude) and model compounds were taken from literature and experimental data when available. Then, each base case process was divided into three sections, namely, (1) thermochemical conversion, pyrolysis or gasification followed by low temperature and/or high temperature Fischer−Tropsch (LTFT and HTFT, respectively); (2) upgrading technology, hydroprocessing, catalytic cracking, FT syncrude fractional upgrading (aromatic alkylation, oligomerization, naphtha hydroisomerization, aromatization, hydrotreating, hydrocracking, and hydrogenation), and HTFT syncrude hydroprocessing, and (3) separation section. The process simulator Aspen Plus version 8.8 was used to perform rigorous simulation of the base cases’ sections. The rigorous simulations and experimental data were used to predict thermodynamic and physical properties, capital, and utilities costs of the unit operations. Likewise, the base case processes were compared in terms of product distribution and complexity of the processes. Simultaneously, liquid, solid and gas emissions were quantified, and from the total emissions different possibilities of mass (water, chemicals, and noncondensable gases) and energy (heat and power selfgeneration) integration were explored. Four integration scenarios were proposed and compared with the initial base case processes results. In terms of mass integration, a detailed wastewater, chemicals, and noncondensable gases network was considered to minimize the freshwater usage and the wastewater and noncondensable gases emissions. In terms of energy integration, gases produced through the processes, such as methane and propylene, were sent to a cogeneration plant for heat and power self-generation. In the initial base case processes, mass and energy integration was not considered. With the proposed scenarios, the effects of the integrations and cogeneration in the capital, utility, and total annual costs were evaluated. Finally, the most cost-effective base case process was selected.

The average area of forest and wooded land per inhabitant varies regionally. The area varies between 6.6 ha in Oceania, 0.2 ha in Asia, and 1.4 ha in Europe (3.4 ha in the Nordic countries).15 Mixed stands are the most frequent type of stand in Nordic countries. A mixture of Scots pine (Pinus sylvestris L.) and Norway spruce (Picea abies) is the most common stand type in the region.16 In Finland and Sweden the percentage of forest area is 86% and 51%, respectively.17,18 In Denmark only 11% of land area is covered by forest and in Norway 20%.16 Due to the availability of softwood in the Nordic countries, spruce and pine (forest residues chips and bark) were selected as feedstock in this work, which were defined based on their ultimate analysis and proximate analysis. An ultimate analysis of dry wood yields carbon, hydrogen, oxygen, sulfur, and nitrogen. The proximate analysis of wood shows the volatile matter, fixed carbon, and ash. In this specific case of study, the characteristics of the selected softwoods are presented in Table 1. Table 1. Feedstock Proximate and Ultimate Analyses dry base

pine19

Proximate Analysis, wt % 1.33 Ultimate Analysis, wt % carbon 51.30 hydrogen 6.10 nitrogen 0.40 sulfur 0.02 oxygen 40.85 Calorific Values net calorific value (LHV), MJ/kg 19.34 gross calorific value (HHV), MJ/kg 20.67 HHVMilne,aMJ/kg 20.59 ash content

a

spruce20 2.50 50.10 6.30 0.32 0.02 40.70 18.65 19.89 20.45

Calculated from the elemental composition using the Milne formula.

3.2. Biomass Handling and Pretreatment. In the pyrolysis and gasification reactors, short residence times in the order of seconds are required, which means that a feed relatively dry and with a small particle size is needed. Mechanical particle-size reduction and drying are commonly used in thermochemical processes.21 3.2.1. Feed Drying. Feedstock drying is very important for thermochemical processes. Unless a naturally dry material such as straw is available, drying is usually essential, as all the feedwater will be included in the liquid product.22 As well, to get the maximum energy, the plant materials should be air-dried because the amount of energy contained in the plant varies with the amount of moisture content. If the combustible materials are required for the energy recovery process, the amount of water in the plant material will affect the recoverable energy.9 For reasonable pyrolysis performance, moisture content of less than 7−10% is recommended.23,24 3.2.2. Grinding. Particles must be very small to fulfill the requirements of rapid heating and to achieve high liquid yields. Feed specifications range from less than 200 mm for the rotating cone reactor to less than 2 mm for fluid beds and less than 6 mm for transported or circulating fluid beds.22 On the basis of these considerations, the softwood biomass (500 kg/h of spruce and pine forest residues) is assumed to contain 30% moisture by weight when received and is dried to 7−10% moisture content and ground from 25 mm to 2−6 mm before it can be injected in the pyrolysis or gasification reactor.

3. PROCESS SYNTHESIS, CONCEPTUAL DESIGN, AND SIMULATION FOR THERMOCHEMICAL BTL PROCESSES 3.1. Feedstock Selection. The selection of the feedstock is a crucial step, since it can affect the overall performance of the plant. Depending on the type of biomass, different technological processes are employed, and different products are obtained. The average majority of biomass energy is produced from wood and wood wastes (64%), followed by municipal solid waste (24%), agricultural waste (5%), and landfill gases (5%).13 About 55% of wood is used directly as fuel, e.g., as split firewood, mainly in developing countries. The remaining 45% is used as industrial raw material, but about 40% of this is used as primary or secondary process residues, suitable only for energy production, e.g., for production of upgraded biofuels. About 70−75% of the global wood harvest is used or potentially available as a renewable energy source. Vast quantities of logging residue are left behind on clear-cut areas. Given the suitable transportation distance and environmental and economic circumstances, they provide a possible alternative for fossil fuels.14 C


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Figure 2. Overall processes diagram for thermochemical process routes to BtL.

3.3. Base Case Process Conceptual Design. As initial analysis of the conceptual designs of the thermochemical processes for liquid biofuels production, each technological route consists of three distinct process sections: (1) thermochemical conversion section, (2) upgrading technology section, and (3) separation section, as depicted in Figure 2. Section 1 converts softwood biomass into pyrolysis oil via pyrolysis or syngas via gasification. Then, the syngas from gasification is sent to the Fischer−Tropsch reactor for hydrocarbon production via two types of FT reactions (HT and LT). In section 2, the pyrolysis oil is upgraded to biocrude via catalytic cracking or hydroprocessing. On the other hand, the FT product is sent to the fractional hydrocarbon upgrading units (aromatic alkylation, oligomerization, naphtha hydroisomerization, aromatization, hydrotreating, hydrocracking, and hydrogenation) to produce syncrude. Alternatively, the HTFT product fractions can be upgraded by hydroprocessing: wax hydrocracking and distillate and naphtha product hydrotreating.25 Finally, in section 3, the biocrude or syncrude is fractionated into gasoline, diesel, gases, and aqueous products. In section 4, we will show that the distinct process sections not only define the different thermochemical-based processes but also determine the process technologies in terms of production costs as well as the final product profiles. 3.4. Process Synthesis and Simulation Setups for the Alternative Processes. The process simulator Aspen Plus version 8.8 was used to perform the rigorous simulation of the pyrolysis, gasification, upgrading, and separation sections. The thermodynamic package Soave−Redlich−Kwong equation of state with Kabadi−Danner mixing rules for the gasification routes and Peng−Robinson for the pyrolysis routes was selected. The first thermodynamic model was chosen as it provides high accuracy in water−hydrocarbon systems over a wide range of temperatures and predicts the instability of the liquid phase.26 And the latter is recommended for synthetic fuels applications,27 since it is more suitable for VLE calculations, hydrocarbon systems, high hydrogen and crude

systems, and it is applicable over a wide range of temperature and pressure conditions. The components not included in the Aspen database, such as spruce, pine, and ash, were defined as nonconventional components based on their ultimate analysis including C, H, O, N, S, Cl, and ash elements and proximate analysis. The biomass lower heating value (LHV) was also specified with the HCOALGEN and DCOALIGT property models chosen to estimate the biomass enthalpy of formation, specific heat capacity, and density based on the ultimate and proximate analyses given in Table 1. MCINCPSD stream class was selected because it is recommended when both conventional and nonconventional solids with particle size distribution are present. Char and sand were defined as conventional solid components. Char was assumed to be 100% carbon, and sand was represented by silicon dioxide; both were assumed to have a particle size of 1 mm. The rigorous simulations were used to predict the thermodynamic and physical properties, energy consumption and equipment designs and costs of the unit operations of the five processes. The capital and utilities cost (electricity, heating, and cooling) of the unit operations, as well as the feedstock conversion into gasoline and diesel, were calculated for a fixed capacity of 500 kg/h of spruce and pine. For the flowsheet setup in Aspen Plus, first, each of the five process alternatives was divided into three process sections, i.e., thermochemical conversion section, upgrading section, and separation section as introduced in section 3.3. Then, for each section a rigorous simulation and an economic analysis was performed. In total 15 simulation flowsheets were set up and implemented. The Aspen Plus RYield reactor was used to simulate the decomposition of the feed, where biomass is converted into its constituting components. Assumptions and operating conditions are taken from the literature and experimental data when available. In the following sections, the flowsheets setups along with the main assumptions for the process alternatives are presented. D


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Figure 3. Softwood conversion to pyrolysis oil in the BC1-PHS process.

Figure 4. Pyrolysis oil hydroprocessing in the BC1-PHS process.

3.4.1. Synthesis and Simulation Setup of the Base Case Process for Pyrolysis-Hydroprocessing-Separation (BC1-PHS). The softwood conversion to pyrolysis oil is illustrated in Figure 3. In the pyrolysis reactor, the pretreated softwood is thermally decomposed in the absence of oxygen, where the softwood is heated to 500 °C by contacting it with hot sand and a fluidizing agent, and the reaction is done in less than 2 s at atmospheric pressure.24 Fast pyrolysis of biomass yields a wide variety of molecules, which suggests that different reaction pathways can be followed. The residence time is long enough for secondary reactions to occur. Likewise, most of the primary products are fairly reactive at pyrolysis temperatures and can undergo secondary reactions. Oligomerization and decomposition of primary products into gaseous species and low molecular weight compounds (acids and acetol) are prominent secondary reactions.28 The Aspen Plus Yield reactor, RYield, was used to model the pyrolysis reaction, since there is no kinetic and stoichiometric information. The pyrolysis reaction product yields (dry basis) assumed in the model were water 12% (wt), pyrolysis oil 64% (wt), noncondensable gases 12% (wt), and char 12% (wt). Char was assumed to be 100% carbon, and the composition (wt) of the noncondensable gases was 46% CO, 43% CO2, 6% CH4, 1% H2, 4% C2+.24 The pyrolysis products, solid char, noncondensable gases, and pyrolysis vapors, are sent to a cyclone where 99% of solids removal is carried out. The gases are rapidly quenched by indirect water cooling in two quench columns to separate the pyrolysis oil from the noncondensable

gases (NCGs). The NCGs with small amounts of aldehydes, acids, and esters are sent to a demister to completely separate the NCGs and are recycled back to the pyrolysis reactor to be used as fluidizing agent. On the other hand, the recovered char together with the sand removed from the pyrolysis reactor is combusted at 600 °C to provide the necessary process heat to the sand reheater. Then, the hot sand is sent back to the pyrolysis reactor. Finally, the pyrolysis oil, also called bio-oil, still contains some fine char inevitably carried over from the cyclone, which is removed by liquid filtration. The final bio-oil is composed of acids, aldehydes, ketones, alcohols, phenols, esters, sugars, and so on. In the model to represent each functional group, a compound was selected from the main components identified in the chemical characterization of spruce and pine pyrolysis oil done by Gaojin Lyu et al. (2015).29 The model compounds are presented in Table S2 in the Supporting Information. Thereafter, the bio-oil is sent to the upgrading section. The pyrolysis oil upgrading via hydroprocessing is depicted in Figure 4. In the upgrading section, hydroprocessing rejects oxygen as water by catalytic reaction with hydrogen. Multistage processing, where mild hydrotreating is followed by more severe hydrotreating, has been found to overcome the reactivity of the bio-oil and prevent catalyst coking.30 Therefore, bio-oil is first pretreated in a stabilization bed under relatively mild process conditions, 140−180 °C and 82 atm, followed by processing under more severe hydrotreating conditions in the first and second stage hydrotreating reactors.31 The first hydrotreating reactor is designed as a single bed catalytic E


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Figure 5. Hydrotreated oil separation into transportation fuels in the BC1-PHS process.

reactor operated at 180−250 °C and 136 atm. The second hydrotreating reactor is operated at a higher temperature of 350−425 °C.24 In the stabilizer and the first hydrotreater the bio-oil is contacted with a large excess of hydrogen and RuTiO2 catalyst, and in the second hydrotreater CoMo catalyst is employed. The purpose is to convert oxygen in bio-oil to water and carbon dioxide molecules, leaving hydrocarbons that are suitable for internal combustion engines.21 The type of reactors used to model the stabilizer and the hydrotreating reactors were two stoichiometric reactors (RStoic) and a RYield reactor, respectively. Data and simulation setup for the stabilizer and the hydrotreating reactors are based on literature information. For model development purposes, stoichiometric reactions S1−S9 presented in the Supporting Information and experimental results24 were investigated to select representative components for the hydrotreated product. The products from the last hydrotreating stage are gas and two liquid fractions with product yields of hydrotreated oil 51% (wt), gases 20% (wt), and water 29% (wt). The compounds in the gas product are light hydrocarbons (CH4, C2H6), excess hydrogen, carbon monoxide, and carbon dioxide.24 And for the hydrotreaded oil, o-xylene, cyclohexane, hexane, 4-methylnonane, n-dodecane, pentane, 4-methylphenanthrene, pyrene, and 1-phenylnaphthalene were selected. In the aqueous fraction, the carbon content depends upon the degree of bio-oil deoxygenation. In this case, the aqueous phase is mainly water with a low concentration of carbon dioxide. The three products are separated in a three-phase separator. The hydrotreated bio-oil is sent to a lights removal column, where the remaining gases are separated from the oil. Finally, the hydrotreated oil is fractionated in a train of distillation columns (Radfrac block), as presented in Figure 5. In the first distillation column (naphtha splitter) light oil with naphtha range product is separated from the heavy oil. The light oil fraction represents the gasoline. Then, the heavy oil is separated into two fractions: diesel range product and a heavy fraction boiling at a temperature above the final boiling point of diesel. The heavy fraction is recovered and sent to the hydrocracking reactor to be catalytically cracked (750 °C, 88 atm, high pressure hydrogen and CoMo catalyst) to additional fuel.24 The product from hydrocracking is a mixture of liquids spanning the gasoline and diesel range, which is sent back to the first naphtha splitter to be separated.

3.4.2. Synthesis and Simulation Setup of the Base Case Process for Pyrolysis-Catalytic Cracking-Fractionation (BC2PCCF). The pyrolysis reaction and recovery of the pyrolysis oil (bio-oil) section is presented in section 3.4.1. The main difference between the first process alternative and the one described here is that in this alternative the pyrolysis oil is upgraded by catalytic cracking, as depicted in Figure 6. The

Figure 6. Pyrolysis oil catalytic cracking in the BC2-PCCF process.

modeling of the catalytic cracking was done with a RYield reactor where zeolite cracking rejects oxygen as CO2, yielding mainly aromatic hydrocarbons as product but with extensive coke deposition on the catalyst.32 Cracking and dehydration are the main reactions seen. Zeolites produce aromatics at atmospheric pressures without H2 requirements. The final product generally has a low heating value. The upgrading is conducted at a temperature of 450 °C and atmospheric pressure, and HZSM-5 is used as catalyst with a reaction time of 15 min. The catalytic cracking is conducted in the presence of N2 gas to stabilize the product. Excessive carbon production is presented with yields of 18% (wt) solids (coke, char, and tar), and thus catalyst coking is presented. The other products are upgraded oil 29% (wt), gases 25% (wt), and aqueous fraction 21% (wt).33−35 The gases were assumed to consist of (wt) 13.7% CO, 6% CO2, 0.8% CH4, 0.9% C2H4, 1.1% C3H6, and 1.2 C2H6.35 Char was assumed to be 100% carbon, and the organic liquids phase (upgraded product) was represented by cyclohexane, o-xylene, 4-methylphenantherene, phenylnaphthalene, pyrene, propanol, and benzene. After the reaction, the product in gas phase is sent to a cyclone to remove the char, and the remaining product is F


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Industrial & Engineering Chemistry Research cooled down and sent to the fractionation column, modeled using a PetroFrac block. In the fractionation column, the upgraded product is fed at the bottom of the column and an extra stream of steam is added. In this column, the feed is separated into four fractions: light product (gases and a small amount of naphtha range product), water, naphtha range product, and diesel range product as shown in Figure 7. A flash unit is used to separate

The product raw gas is sent to a cyclone to remove the solid particles. The raw gas is then cooled down in a scrubber (RadFrac absorber) by contact with a countercurrent water flow, which also reduces the concentration of ammonia. After cleaning, the gas is sent to a water gas shift reactor (WGSR) to adjust the H2/CO ratio, in which carbon monoxide reacts with water vapor to form carbon dioxide and hydrogen in the presence of an iron catalyst (Fe2O3/Cr2O3).37 Pure water and water with ammonia and carbon dioxide are separated from the gasification product. The gas finally obtained is called syngas. The average mole fraction of the syngas species evolved during the entire steam gasification varies as a function of the temperature. For a temperature of 1000 °C, the amount of each component % (mol) is approximately 0.51 CO, 0.04 CO2, 0.21 CH4, 0.004 CnHm, and 0.23 H2.38 The model was supported by experimental data from previous experiments collected by Hannula and Kurkela (2012).39 Simultaneously, the recovered char together with the sand removed from the gasifier is sent to a combustor (stoichiometric reactor) where the char is burned to provide heat to the sand reheater, and the sand is recycled back to the gasifier. The syngas with the H2/CO ratio adjusted from the WGSR is sent to a high temperature Fischer−Tropsch reactor (HTFT) modeled as a RYield reactor, where the syngas is passed over supported metal catalyst (Fe, Co, Ru, Rh, and Ni) to produce hydrocarbons. The syngas HTFT reaction is carried out at 320−375 °C and over iron based catalyst such as Fe2O3/Cr2O3, which gives shorter chain molecules (gasoline). Circulating fluidized and fixed fluidized bed reactors are only used for HTFT synthesis.40 The softwood conversion to hydrocarbons through HTFT is depicted in Figure 8. The Fischer−Tropsch RYield reactor was modeled considering the compositions of the Fe-based HTFT syncrude, which is presented in Table S1.40 The compounds selected to represent each of the product fractions were taken from the compound class that presents higher compositions; the model compounds selected for the HTFT product are presented in Table S3. The FT synthesis largely produces a mixture of linear hydrocarbons with some similarity to crude oil, which is known as syncrude. In addition to the usual n-alkenes and n-alkanes, a typical syncrude also contains aromatics and oxygenates, such as 1-alkanols, aldehydes, ketones, and carboxylics acids.

Figure 7. Upgraded oil fractionation in the BC2-PCCF process.

the remaining naphtha in the light product from the gases. Then, the recovered naphtha is mixed with the naphtha product stream from the fractionation column (this stream represents the gasoline product). 3.4.3. Synthesis and Simulation Setup of the Base Case Process for Gasification-HTFT-Fractional Upgrading-Fractionation (BC3-GHTUF). The BC3-GHTUF route consists of three sections of gasification and HTFT, FT hydrocarbon upgrading, and upgraded product fractionation into transportation fuels, which are presented in Figures 8, 9 and S1, respectively. In the gasification section, the pretreated biomass is sent to a gasification reactor, where it is reacted with air, oxygen, or steam to produce a gaseous mixture of CO, CO2, H2, CH4, N2, C2H4, C2H6, and ammonia, known as raw gas. The reaction was modeled in a RYield reactor with the following conditions: 800−1000 °C, atmospheric pressure, and residence time of 3− 4 s.36

Figure 8. Softwood conversion to hydrocarbons via gasification and HTFT in the BC3-GHTUF process. G


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Figure 9. FT product fractional upgrading in the BC3-GHTUF process.

Concerning the origins of these other materials, there have been speculations of whether they are primary products or produced by secondary reactions. Aldehydes can also be primary products, whereas ketones are secondary products from the decomposition of carboxylic acids. Aromatic hydrocarbons are secondary products that are produced at higher temperatures; thus, LTFT syncrude contains almost no aromatic compounds, whereas HTFT syncrude contains more aromatics. As well, the ketonization reaction requires high temperature, and fewer ketones are found in LTFT than in HTFT.40 Since the FT syncrude also contains significant amounts of other organics, a different upgrading than the crude oil procedure is therefore needed. Likewise, the syncrude is not present as a single liquid phase but as a multiphase mixture containing three to four different phases.40 To convert most of the syncrude phases into a single “crude oil” product, some upgrading techniques are required. However, before upgrading, the FT product needs to be separated into fractions because each fraction requires a different upgrading technique. The HTFT product is first sent to a distillation column to separate the light product from the heavy oil. Then, the light product is sent to a three-phase separator, where gases, light oil, and aqueous products are obtained. Subsequently, each of the fractions (heavy oil, gases, light oil, and aqueous products) is sent to their respective upgrading unit, as shown in Figure 9. In the upgrading section, the gases fraction is separated into liquefied petroleum gas (LPG) and tail gas. The tail gas is sent to an aromatic alkylation unit operating at 370 °C, where the gases react with benzene in the presence of PtH-MFI catalyst to produce toluene or ethylbenzene.41 The LPG (propylene) is sent to an oligomerization reactor and catalytically reacts over Zr-ZSM-5 to produce naphtha fuel. The reaction conditions are 260 °C and 4 MPa.42 On the other hand, the light oil is sent to an aromatization unit to react with hydrogen on Pt/kLIWI catalyst at 500 °C and atmospheric pressure to produce toluene 22.8% (wt), benzene 27.4% (wt), and C1−C5 34% (wt).43

The heavy oil fraction is sent to a distillation column, where the heavy oil is separated into distillate and wax streams. Successively, the distillate stream is upgraded by reacting with high pressure hydrogen over CoMo catalyst at 340 °C and 34 bar to produce diesel range product.44 The heavy fraction, which contains mainly C20 wax, is catalytically cracked to additional fuel, obtaining mainly diesel and gasoline range product. The reaction conditions are 324 °C and 34 bar, over catalyst Ni-SiO2/Al2O3.45,40 In this work, the wax was represented by n-eicosane and it is hydrocracked to nhexane and n-tetradecane. Finally, the aqueous product (oxygenate-rich product) needs to be partially hydrogenated to be further separated into carbonyl-rich and alcohol-rich products and to convert the ketones and aldehydes into their corresponding alcohols.40 These alcohol products are not blended with the rest of the fractions, as they can sell as byproducts or simply considered as emission. Initially, in this study this stream was assumed emission. The upgrading of the HTFT hydrocarbons into transportation fuels was modeled with a series of RStoic reactors and stoichiometric reactions (S12−S17) from the literature. After being upgraded, all the FT fractions except for the aqueous are blended into a single stream called syncrude, which contains components ranging from C1 to C20+ and which can then be refined into final fuel products with required component profiles. Therefore, the syncrude is sent to a fractionating column (PetroFrac) and is separated into three fractions: water, light product, and diesel. The light product is further separated into gases and gasoline in a flash unit, as presented in Figure S1 in the Supporting Information. The simplified separation process was performed to avoid using similar separation units at different sections for the similar fluids. 3.4.4. Synthesis and Simulation Setup of the Base Case Process for Gasification-LTFT-Fractional Upgrading-Fractionation (BC4-GLTUF). The BC4-GLTUF process also consists of three sections: gasification and LTFT, FT hydrocarbon H


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dehydrogenation. Then isomerization occurs followed by cracking of the compounds, as shown in the Supporting Information reactions S21−S23.47 The typical FT product profile consists of high molecular weight paraffinic waxes and FT fuels in the diesel and naphtha boiling range. Therefore, before upgrading, the FT product is separated into fractions, and two distillation columns are employed (RadFrac blocks). The first distillation column separates the naphtha product from the heavy product, and the second column separates the distillate and wax fractions present in the heavy product. Thereafter, three individual hydroprocessing units, modeled as RStoic reactors, to upgrade the three fractions are needed: for hydrocracking the wax and for hydrotreating the FT distillate and naphtha product.25 The HTFT hydrocarbon production and hydroprocessing process are depicted in Figure 11. The wax hydrocracking unit (324 °C and 34 atm, over catalyst Ni/Al2O3−TiO2) catalytically cracks the FT wax in a highpressure hydrogen environment to yield more desirable naphtha and distillate products.25 Then, the naphtha obtained is sent to an isomerization reactor (300 °C, 1 atm, over sulfated zirconia)48 to increase the stability of the product and to yield a high-octane gasoline blending component. The isomerization was modeled with a RYield reactor assuming a 100% conversion. The distillate hydrotreating unit (340 °C and 34 atm, over catalyst NiMo/Al2O3) catalytically hydrotreats the FT distillate under a hydrogen environment to yield a high-quality diesel blending component.44 Finally, the naphtha product is catalytically hydrotreated (340 °C, 3.4 atm over CoMo catalyst) under a hydrogen environment to yield a saturated naphtha that is further processed in the naphtha reformer to make a high-octane gasoline blending component. The product streams coming from the upgrading section are directly sent to the gasoline and diesel pools, and no further separation is needed.

upgrading, and hydrocarbon fractionation into transportation fuels. The gasification section for production of the syngas and FT hydrocarbons is the same as presented in Figure 8. The main differences between the process presented in section 3.4.3 and the one described here are the operating conditions of the FT reactor and the composition of the FT syncrude. In this process, the syngas with the H2/CO ratio adjusted is sent to a low temperature Fischer−Tropsch (LTFT) reactor to produce hydrocarbons. The LTFT reaction is carried out in a multitubular fixed bed reactor at 200−250 °C over cobaltbased catalyst such as Co-ZrO2, which gives long chain molecules (diesel). The composition of FT syncrude is mainly determined by the catalyst type and operating conditions. Generic compositions for different syncrude types are given in Table S1.40 From Table S1, the model compounds selected to represent the Co-LTFT are depicted in Table S4. Before upgrading, the LTFT product is separated into fractions: heavy oil (distillate and wax), gases (LPG and tail gas), light oil (naphtha), and aqueous product as explained in the HTFT product upgrading. Subsequently, each of the fractions are sent to their corresponding upgrading units, as presented in Figure 10.40 However, in this study each of the

4. EVALUATION AND COMPARISON OF THE BASE CASE PROCESSES 4.1. Liquid Biofuels Product Profiles and Properties Comparison between the Base Case Processes. Fundamental understanding of the thermal decomposition behavior of biomass during pyrolysis and gasification is crucial to control the end-product composition. The products from these reactions undergo subsequent upgrading reactions followed by a separation train, which can vary even more the distribution of the products. Furthermore, these reactions are also severely affected by the type of catalysts, temperature, and pressure ranges employed. Therefore, the proper selection of the model compounds for each of the process products (pyrolysis oil, raw gas, syngas, hydrotreated oil, FT product, upgraded oil, noncondensable gases, gasoline, and diesel) is of high importance, since this will have a significant effect on the product profiles and biofuels properties obtained from each alternative. On the basis of an extensive investigation of the behavior of the softwood through the thermochemical conversion processes and upgrading reactions, we have obtained from the rigorous simulations the product profiles and properties of the upgraded product for each base case process, as presented in Figure 12 and Table 2, respectively. The molar composition of the gasoline products and the research octane number (RON) and motor octane number (MON) values published

Figure 10. Fuels refinery design employing LTFT syncrude.

fraction flow rates were quantified and it was found that the production of gases was low compared to the rest of the fractions, and therefore this fraction was not upgraded. The upgrading of the LTFT hydrocarbons into transportation fuels was modeled with a series of RStoic reactors and stoichiometric reactions with reactors setup from the literature for the conversion of each FT product fraction into gasoline and diesel range products.41−46 Finally, the upgraded products are blended and sent to a PetroFrac block and a flash unit for fractionation into diesel, gasoline, gases, and aqueous fractions, as described in BC3GHTUF. 3.4.5. Synthesis and Simulation Setup of the Base Case Process for Gasification-HTFT Hydrocarbon Production− Hydrocarbon Hydroprocessing (BC5-GHTH). The gasification reaction, production of the syngas, and HTFT hydrocarbons production are presented in section 3.4.3. The only difference is the technology implemented for the HTFT hydrocarbons upgrading, which in this case is hydroprocessing. In hydroprocessing, the long chain hydrocarbons are more selectively converted to the desired product, the fuel ranging from C5 to C20. The first step in hydroprocessing is the very fast I


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Figure 11. HTFT product hydroprocessing in the BC5-GHTH process.

(gases and gasoline range products), while the LTFT gives long chain alkane molecules (diesel and wax). Likewise, the conversion of biomass to gasoline and diesel can be increased from 64% to 66% and from 6% to 17%, respectively, if instead of fractional upgrading the FT product is hydroprocessed. By catalytically hydrotreating and hydrocracking the Fischer−Tropsch product under a hydrogen environment (BC5-GHTH), the result will be high quality gasoline and a small amount of diesel blending. On the other hand, if we analyze the pyrolysis-based routes, the main product obtained for both process alternatives is gasoline, with 54% from BC1-PHS and 45% from BC2-PCCF. Again, it can be observed that the amount of gasoline is increased if the product is upgraded by hydroprocessing. Therefore, the hydroprocessing as upgrading technology produces more gasoline in the final product profiles. For the five process routes simulated, the selection of the process alternative in terms of the product distribution should be decided based on the product demand. When the final biofuels profiles prefer more gasoline, process routes BC5GHTH and BC3-GHTUF are the suitable technological routes. On the other hand, when the final biofuels profiles prefer more diesel, process routes BC4-GLTUF and BC1-PHS are the suitable technological routes. Concerning the fuels properties,

Figure 12. Product profiles of the base case processes.

for blending pure components were used to calculate the weighted average octane value (RON + MON)/2. From the base case processes profiles in Figure 12, we observed that for the BC4-GLTUF process route, the biomass produces a relatively even amount of gasoline and diesel with 38% and 49% (wt), respectively. On the other hand, if instead of low temperature FT the syngas is subjected to a HTFT reaction in the base case process BC3-GHTUF, the product will be mainly gasoline with 64% compared to 6% of diesel. This is because the product profile varies through the FT reaction block. The HTFT gives shorter chain alkene molecules Table 2. Alternative Fuels Properties bio-oil

BC1-PHS

BC2-PCCF

BC3-GHTUF

BC4-GLTUF

BC5-GHTH

property

BC1-BC2

BC4

BC3-BC5

gasoline

diesel

gasoline

diesel

gasoline

diesel

gasoline

diesel

gasoline

diesel

density (kg/m3) HHV (MJ/kg) viscosity (cSt) specific gravity, 15 °C molecular weight boiling point (°C) flash point (°C) cetane number avg octane value water content, % (wt)

1014 34 1.62

857 15.37 1.11

902 13.51 0.93

738 46.83 0.68 0.75 90 159 −35

706 45.83 1.75 0.82 135 248 45 42

811 45.35 1.58 1.10 72 209 −18

1091 34 8.02 0.96 188 401 88 13

816 44.25 0.64 0.75 91 125 −18

760 38.14 2.28 0.79 164 355 80 72

787 44.52 0.67 0.77 97 155 −23

771 34 1.92 0.86 184 283 55 82

803 44.60 0.69 0.70 93 134 −15

753 38.95 2.30 0.76 174 271 80 77

30

45

42

60

93

J

104

78

88


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Industrial & Engineering Chemistry Research Table 3. Capital and Utility Costs of the Base Case Processes BC1-PHS conversion section upgrading tech separation tech

861 558 904 703 842 607

conversion section upgrading tech separation tech

48 946 128 754 179 369 617 956

BC2-PCCF

BC3-GHTUF

Capital Cost ($) 861 558 203 561 198 876 313 825 73 400 74 400 Utility Cost ($/year) 48 946 1 287 768 46 314 36 139 36 406 35 936 TAC ($/year) 245 049 1 419 021

BC4-GLTUF

BC5-GHTH

221 642 161 744 73 000

203 561 226 000 250 576

84 345 34 751 33 609

1 287 768 35 686 77 790

198 343

1 469 258

capital and utility costs are calculated for each section. Table 3 presents the capital and utility costs along the total annual costs for the processes. The distinct calculations are explained in the following sections. 4.3.1. Capital Cost. The capital cost and utility costs (electricity, heating, and cooling) were estimated with Aspen Economic Evaluation version 8.8 for a fixed capacity of 500 kg/ h of softwood (spruce and pine residues). The capital cost of a process is based on the sum of the individual cost of the unit operations. The material was selected depending on the operating conditions. The base material selected for the majority of the unit operations was carbon steel (A285 C, A515, and A214), and in the case of the hydrocrackers where the temperatures and pressures were higher than supported by the material, then A-240 grade fabricated from 16 Cr-12Ni-2Mo was chosen. The capital cost of the base case processes is depicted in Figure 13. The base

most of the alternative diesel fuels obtained from the different process routes can be used as blending components because of its very high cetane number. Some of their properties can be leveraged at refineries when preparing blendings, and the high centane number could reduce the use of cetane number improver additives.49 On the other hand, the upgraded product from BC2-PCCF contains mainly aromatics, which directly induces a low cetane number of diesel oil and delivers a high octane number for gasoline. 4.2. Complexity of the Process Routes and Operating Conditions. The analysis of the complexity of the processes was based on the number of units and the operating conditions employed by each of the technological routes evaluated. Concerning the number of units, BC3-GHTUF process is the most complex, since it requires the largest number of unit operations. First, it is necessary to subject the variety of components obtained from the FT reaction to a preseparation section to separate into similar functional groups, and then the fractions are sent to the corresponding upgrading units, hydrotreating, hydrocracking, aromatization, oligomerization, and alkylation, for conversion into liquid fuels. On the other side, BC2-PCCF process was as the least complex, employing only one reactor for the upgrading of the pyrolysis oil to transportation fuels, followed by BC4-GLTUF, which produces less tail gas and LPG compared to the other gasification-based routes, and therefore less units are required for the upgrading of the FT product. From the gasification based routes (BC3, BC4, and BC5), BC4 presents the advantage that when the reaction is carried out in under mild conditions, further secondary reactions are minimized. Regarding the operating conditions, BC2-PCCF process was again as the least complex, since all the units are working at atmospheric pressure and temperatures up to 450 °C in the upgrading section. In contrast, BC1-PHS and BC5-GHTH technological routes require more severe operating conditions since it is necessary to employ hydrogen at high pressure in the upgrading section to stabilize the bio-oil obtained in both processes. Besides, in the BC1-PHS alternative, the stabilizer, the first and second hydrotreaters require as well high pressure conditions around 80−136 atm. The number of units and operating conditions will not only affect the equipment and operating costs in the final process and plant design but also tend to demand more in terms of equipment materials and process operations. 4.3. Economic Evaluation and Comparison of the Base Case Processes. The costs comparison of the base case processes is evaluated in terms of utility and capital costs, as well as the total annual costs. In order to observe the costs distribution among the sections of the base case processes, the

Figure 13. Capital cost of the base case processes (thousands of dollars).

capital cost of the reactors was calculated by Aspen considering a base residence time (τbase) of 300 s (default value taken by Aspen in its calculations), which was then adjusted according to the residence times (τadj) for each specific reaction involved in the base case processes. The adjusted residence times were found in the literature. Equation 1 gives the adjustment of the capital cost estimated from Aspen.50 ⎛ τadj ⎞0.5 costadj = costbase⎜ ⎟ ⎝ τbase ⎠

(1)

From Figure 13, we can observe that the gasification-based routes (BC3, BC4, and BC5) present the lowest costs in the conversion section because the conversion of softwood via gasification does not require cooling down the product syngas K


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separation section, which is related to the less amount of heating needed to separate the light products since more heavy products are produced. Contrarily, the thermochemical conversion section for BC3GHTUF and BC5-GHTH presents the highest costs, due to the gasifier temperatures and the need to increase the temperature of the syngas up to 375 °C for the HTFT reaction and then to separate the gases and light oil from the heavy FT product before its upgrading. Regarding the upgrading and separation section, BC1-PHS requires more electricity and heating, which is highly related to the complexity of the process, due to the high pressures employed in the hydrotreaters and the train of distillation columns with reboiler temperatures up to 330 °C. Overall, the base case processes consume significantly different utility costs; the BC2-PCCF requires the lowest and the BC5-GHTH the highest. 4.3.3. Total Annual Cost. The total annual costs (TAC) for the processes were evaluated considering 10 years for recovering the investment. Equation 2 presents the TAC calculation.

and all the reactions are carried out in gas phase. Therefore, there is no need of quench columns as it is in the pyrolysisbased routes. Likewise, the upgrading section also presents low costs because the bio-oil is first fractionated and then the fractions are upgraded in different reactors with smaller capacities. Overall, BC4-GLTUF presents the smallest capital costs because less upgrading units are required due to the small amount of gases produced, and it is not convenient to add a reactor to upgrade this fraction. As well, in the separation section the recovery of the liquid fuels only requires a fractionation column and a flash unit. On the contrary, BC1-PHS presents the highest capital cost in each of the sections. In the thermochemical conversion section, the pyrolysis gases need to be rapidly quenched to improve the separation of the bio-oil from the noncondensable gases, and the two quench columns employed increase the capital cost. On the other hand, in the upgrading section, all the pyrolysis oil is upgraded in reactors in series, and therefore the capacity of the reactors is greater compared to the FT product upgrading. Lastly, in the separation section, a train of distillation columns is employed to recover each of the transportation fuels fractions. Additionally, the hydrocracking reactor operates at high temperatures and high pressures, and thus, different materials to support those conditions are required. All these factors increase the capital cost of BC1 process route. 4.3.2. Utility Costs. The costs of utilities are calculated from the amount of electricity, steam, and thermal fluids required in each of the process sections. The utility requirements were calculated with Aspen Economic Evaluation version 8.8 considering the electricity price at 0.08 $/kW, low pressure steam at 0.018 $/kg, intermediate pressure steam at 0.022 $/kg, high pressure steam at 0.026 $/kg, and cooling agents, such as water, ethane, and Freon at 3.17 × 10−5 $/kg, 3.96 × 10−5 $/kg, and 1.88 × 10−4 $/kg, respectively. The final costs presented in Figure 14 are reported in thousands of dollars per hour. It was assumed that a plant is operating 8000 h per year.

TAC =

⎡⎛

∑ ⎢⎣⎜⎝

⎤ ⎞ capital cost ⎟ + utility costs⎥ ⎦ time of investment ⎠

(2)

From Table 3, we can observe that the processes with the low total annual costs are BC2-PCCF and BC4-GLTUF. In the pyrolysis-based processes, the main difference between BC1PHS and BC2-PCCF in terms of the total annual cost is related to the upgrading and separation section. In the upgrading section of BC2-PCCF only one reactor is employed to upgrade the bio-oil via catalytic cracking, and for BC1-PHS the upgrading of the bio-oil is carried out in a series of reactors. Likewise, in the separation section, the recovery of the fuel fractions in BC2-PCCF is done in a fractionation column and a flash unit, and contrarily BC1-PHS requires a series of distillation columns to recover the different range of transportation fuels. Therefore, for all these reasons BC2-PCCF presents lower capital, utility, and total annual costs compared to BC1-PHS. Regarding the gasification-based processes, BC4-GLTUF presents the lowest total annual cost, even though it has the highest capital cost in the conversion section due to the longer residence time in the LTFT and thus requires a larger reactor capacity. However, BC3-GHTUF and BC5-GHTH present high utility cost in the conversion section because the HTFT requires high temperature and a distillation column is used to recover the high amount of light products produced. Overall, BC4-GLTUF presents the lowest cost among the processes due to the lower temperatures employed in the reactors, the less number of units in the upgrading section, and the less amount of energy required for the separation of the syncrude fractions. On the contrary, BC5-GHTH requires higher reactor temperatures and capacities, excess hydrogen, and more energy for the separation of the gasoline product from the heavy product and therefore presents the highest total annual cost among the processes. 4.4. Liquid, Gas, and Solid Emissions Comparison. Furthermore, it was also important to observe and compare the emissions from the different processes, as emissions from the processes are not only relevant to the environment concerns but also can be considered for process integration to further improve the process performance. Liquid, gas, and solid emissions were quantified for each of the process alternatives

Figure 14. Utility costs of the base case processes (thousands of dollars/year).

Concerning the utility costs, the pyrolysis-based processes (BC1 and BC2) present low costs in the conversion section, due to the lower temperature required in the pyrolysis reactor of up to 520 °C compared to 800−1000 °C for the gasificationbased processes. On the other hand, in the upgrading section, BC4-GLTUF presents the lowest cost since it requires less number of units and thus less heating and electricity. Additionally, BC4-GLTUF presents the lowest cost in the L


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5.1.2. Ammoniacal Water Integration. Additionally, in the gasification-based routes, the impurity stream coming from the scrubber, which contains ammonia and CO2 (referred as ammoniacal water), is sent to a stripper where an air stream is added to remove the ammonia and CO2. After the treatment, the purified stream is sent back to the scrubber. 5.1.3. Aqueous Products. In BC3-GHTUF and BC5GHTH, the water streams that contain ethanol, and referred as aqueous products, are first sent to a flash column to remove the remaining gases and then to a distillation column to remove the ethanol. These streams after being treated (final concentration of ethanol 0.17% (wt) and CO2 0.1% (wt)) are sent to a water container to be directed to the cogeneration plant. Regarding BC4-GLTUF, the aqueous products, which are water and propanol, are sent to a liquid−liquid extraction column to remove the propanol from the water, by adding CO2 in supercritical conditions and then redirecting it to the cogeneration plant. 5.2. Chemical Integration. As observed in Table S6, besides the water and alcohols emissions, benzene is also produced in the gasification-based processes (BC3 and BC4). Benzene is a byproduct from the aromatization of the light oil produced in the FT reactor (in both HT and LT) and can be recycled to the alkylation reactor to react with tail gas to produce toluene or ethylbenzene. 5.3. Gases Integration. In addition to the liquid emissions, there is an important amount of gases produced through the processes. The gases produced are mainly CO, CO2, CH4, H2, C2H4, C3H6, which are referred to as noncondensable gases (NCGs). The NCG stream produced in the thermochemical conversion section from BC1-PHS and BC2-PCCF is recycled to the pyrolysis reactor, to be employed as fluidizing agent. On the other hand, the fuel gas streams (methane, ethane, and propylene) coming from all the process routes are respectively sent to their cogeneration plants for power generation. 5.4. Cogeneration: Electricity and Steam Integration. To produce steam and electricity, a cogeneration plant was added to the base case processes. The possibilities of heat and power integration are described next: In the cogeneration plant, pure water coming from the processes is sent to the steam generation section. In this section, the pure water stream is sent to an intermediate pressure boiler to produce steam at 100 psi and then is splitted into two streams. One stream is sent to provide the steam at 100 psi for the process use, and the remaining is sent to the steam turbine to produce electricity. Moreover, in the gas turbine section, the total fuel gas stream (methane, ethane, and propylene) is compressed and burned with air in a combustion reactor, where the heat produced is used to increase the temperature of the water from the processes and simultaneously produce the steam at 100 psi. Then, the gases are further sent to a gas turbine to generate electricity. The electricity produced in the cogeneration can supply the electricity required in the process.

and are presented in Table S6. Process integration opportunities to reduce the emissions are introduced in section 5. From the data collected in Table S6, it was found that the highest amount of emissions is related to the flows of water and gases, and this gives the opportunity to further explore the mass and energy integration to reduce the emissions. In terms of mass integration, it is possible to consider water, noncondensable gases, and benzene integration. And if we consider fuel gases such as methane and propylene, then energy integration is also an option.

5. PROCESS INTEGRATION FOR TAC AND EMISSION REDUCTION The goals of the process integration are to integrate materials and energy for reuse and to minimize the generation of emissions and wastes. Moreover, the effect of the integration in the total annual costs can be evaluated. To reduce the total annual cost and the liquid, gas, and solid emissions quantified in each process route, we have considered mass (water, chemicals, and gases) and energy (heat, power self-generation) integration. These integrations are based on process simulation results for the mass and energy balance with full streams information. Then, it is possible to design process integration scenarios considering water, chemicals, and energy integrations. In the following sections, first, the feasible mass and energy integrations are examined and discussed, and then different integration scenarios are implemented and evaluated. 5.1. Water Integration. To reduce the liquid emissions of the process alternatives, a mass integration considering the water streams was performed. The data collected from the simulations allowed us to evaluate the possibilities of recirculation of the water streams. On the basis of the compositions, the water streams were classified in aqueous products (alcohols and water), ammoniacal water, and pure water. For this purpose, it was also considered the unit operations’ requirements to add extra pumps, heat exchangers, or water treatment units to fulfill the purities and temperatures needed. The thermodynamic package Electrolyte NRTL model with Redlich−Kwong equation of state was selected for the simulation of the water treatment units. This method is recommended for aqueous and mixed solvent applications, as well as systems consisting of ammonia, carbon dioxide, and water.27 5.1.1. Pure Water Integration. For BC1-PHS and BC2PCCF, it was found that water coming from the quench columns located in the pyrolysis section could be sent back to the same quench columns. Two extra heat exchangers were added to reach the desired temperatures of the quench columns. The first quench column requires a water flow at 60 °C, and the second quench column requires it at 40 °C. Moreover, a cogeneration plant can be considered so that it can receive the pure water stream from the three-phase separator in the separation section of the BC1-PHS. Likewise, in BC2PCCF, pure water leaving the fractionation column in the separation section can be sent to the cogeneration plant. These streams are considered as pure water since traces of CO2 (0.02% (wt)) are the only contaminants. In all the gasification-based routes (BC3, BC4, and BC5), pure water coming from the thermochemical conversion section and from the fractionation column in the separation section is used as cooling water in the process and the surplus is considered emission or sent to the cogeneration plant.

6. INTEGRATION SCENARIOS DESIGN AND EVALUATION On the basis of the different possibilities of integrations described before, four integration scenarios were proposed. Each integration scenario was applied individually to each base case process. The capital and utility costs of each scenario were M


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Figure 15. Total annual cost comparison: water integration vs without integration (thousands of dollars).

Figure 16. Total annual cost comparison: cogeneration and energy integration vs without integration (thousands of dollars).

73% due to the liquid−liquid extraction column working with CO2 in supercritical conditions required to recover the alcohol. 6.2. Scenario 2: Cogeneration (SCN2). In this scenario, only the pure water flows that were considered as emissions in the water integration scenario are sent to the steam generation section of the cogeneration plant. Moreover, the fuel gases produced in the base case process are sent to the gas turbine section to produce heat and electricity. Intermediate pressure steam and electricity are produced in the cogeneration plant, which provides the power and part of the heat required in the process. The capital, utility, and total annual costs with energy integration include the cogeneration plant and water containers costs. Figure 16 presents the total annual cost comparison with and without energy integration. From the results reported in Figure 16, we can observe that there is a considerable reduction in the TAC of each base case process. BC3-GHTUF presents the lowest TAC reduction and BC4-GLTUF the highest reduction, with 9% and 43%, respectively. The total annual cost reduction in BC4-GLTUF is achieved due to the possibility to generate and provide all the electricity and intermediate pressure steam needed in the process, meaning that the final utility cost is only the cooling costs. 6.3. Scenario 3: Pure Water Integration and Cogeneration (SCN3). In this scenario, only pure water is recycled to the process. Part of the pure water flow is recycled to the conversion section in the base case process, and the rest is directed to the cogeneration plant. The aqueous products and ammoniacal water produced in BC3-GHTUF, BC4-GLTUF,

compared with the results from the base case processes without mass and energy integrations. All the scenarios included noncondensable gases integration for the BC1-PHS and BC2PCCF and chemicals integration for BC3-GHTUF. The main variances between the scenarios were the different levels of water, heat, and power integration. The scenarios evaluated are described in the following sections. 6.1. Scenario 1: Water Integration (SCN1). This scenario evaluates the integration of all types of water. Pure water integration was considered for the pyrolysis-based processes (BC1 and BC2), and pure water, ammoniacal water, and aqueous products integration was considered for the gasification-based processes (BC3, BC4 ,and BC5). After the integration, in all the base case processes, the remaining pure water without possibilities of integration was considered as emission. For the economic evaluation of the gasification-based processes with water integration, the capital and utility costs of the alcohol recovery plant (stripper and/or extraction column), pure water containers, and heat exchangers needed to achieve the unit operations’ temperatures are included. On the other hand, for the pyrolysis-based processes, only the inclusion of heat exchangers and containers is considered in the evaluation of the capital cost and utilities cost. In Figure 15, the total annual costs were compared with the initial base case processes results. As observed in Figure 15 the total annual costs for the base case processes with water integration present an increment instead of a reduction compared to the results without integration. We found that the TAC of BC4-GLTUF increased N


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Figure 17. Total annual cost comparison: pure water, cogeneration, and energy integration vs without integration (thousands of dollars).

Figure 18. Total annual cost comparison: cogeneration and pure and ammoniacal water integration vs without integration (thousands of dollars).

Table 4. Base Case Processes with and without Integrations Results: TAC and Emissions BC1-PHS

BC2-PCCF

BC3-GHTUF

BC4-GLTUF

BC5-GHTH

TAC ($/y) without int SCN1 SCN2 SCN3 SCN4

617 956 742 826 415 436 473 005 473 005

without int SCN1 SCN2 SCN3 SCN4

19 254.9 554.4 18 953.1 252.5 252.5

without int SCN1 SCN2 SCN3 SCN4

598.0 358.4 428.0 428.0 428.0

245 049 1 419 021 369 919 1 568 269 167 440 1 296 343 225 096 1 295 590 225 096 1 332 647 Liquid Emissions (kg/h) 19 040.0 13 885.5 339.4 482.4 18 804.9 13 562.2 104.3 10181.6 104.3 542.5 Gas Emissions (kg/h) 647.1 338.5 407.5 338.5 523.3 388.0 523.3 388.0 523.3 388.0

and BC5-GHTH are not treated or recycled. And these streams are considered emissions. Therefore, the costs related to the wastewater treatment plant are not considered. The capital and utility costs presented in Figure 17 include the heat exchangers added in the conversion section for BC1-PHS and BC2-PCCF to meet the temperature requirements and allow its recirculation, as well as the water containers and cogeneration plant costs.

198 343 347 591 113 989 113 236 150 293

1 469 258 1 664 317 1 307 878 1 307 098 1 344 155

13 781.6 365.4 13 362.8 10 058.5 396.2

13 684.8 464.2 13 699.5 10 299.5 660.4

255.3 255.3 145.4 145.4 145.4

460.5 460.5 745.1 745.1 745.1

The results from this scenario are close to the results obtained in SCN3, which means that including the water integration does not have a significant effect in the total annual cost basically because the highest costs of utilities are related to the electricity and heating. To illustrate this, we can observe that for BC2-PCCF the total annual cost still presents a small reduction of 9% but it is not as significant as in SCN3 in which a 34% reduction was achieved. This is because including the O


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total of 15 rigorous simulations were implemented to predict the capital and utility costs of the base case processes. The results from the simulations together with existing experimental data were used to evaluate and compare the base case processes and to determine the process for liquid fuel production that presents the minimum total annual cost and the highest conversion of softwood to liquid fuels. It was found that BC4-GLTUF was the most cost-effective among all the base case processes when simultaneous diesel and gasoline production is preferred, achieving a conversion of softwood to liquid fuels of 87% (wt). Additionally, the operating conditions of BC4 minimize the secondary reactions and the gasoline and diesel products can be considered as blending components due to its physical properties. Moreover, to evaluate the effects of the different levels of integration on the capital, utilities, and total annual costs, four integration scenarios were explored. Liquid, gas, and solid emissions were quantified for each scenario. For SCN4, it was found that energy and mass integration in BC4-GLTUF could reduce the total annual cost by 25% and the liquid and total gas emissions by 97% and 43% (wt), respectively. On the other hand, SCN2 could reduce its total annual cost by 43% and the liquid and total gas emissions by 5% and 43% (wt), respectively. The results show that change and improvement of one section will significantly affect the other process sections and thus the total process technology of the thermochemical conversion routes. Furthermore, intensification like for the BC1-PHS separation section can reduce the number of units, as well as the capital and utilities cost.

water integration means that heat exchangers are required in the thermochemical conversion section, which increases significantly the heating costs, and furthermore there is no more possibility of water integration in this base case process. 6.4. Scenario 4: Pure Water Integration, Ammoniacal Water Treatment, and Cogeneration (SCN4). In this scenario, pure water is collected and recycled back to the base case process. Additionally, in the gasification-based processes (BC3, BC4, and BC5), the ammoniacal water produced is treated to remove the ammonia and then the water is sent back to the conversion section. The pure water not integrated, and the fuel gases produced in each base case process are sent to the cogeneration plant for heat and power generation. The capital and utilities cost calculation for BC1-PHS and BC2-PCCF include the heat exchangers added in the conversion section to reach the water temperature requirements, the water containers, and the cogeneration plant. On the other hand, for BC3GHTUF, BC4-GLTUF, and BC5-GHTH, the ammonia stripper, water containers, and cogeneration plant capital and utility costs are included. The economic evaluation and comparison are presented in Figure 18. The most significance difference between SCN3 and SCN4 is the inclusion of the ammoniacal water treatment and integration, which only affects the gasification-based processes. The main achievement in this scenario is the reduction of water emissions in 95−99%, which will be discussed in the next section.

7. BASE CASE PROCESSES RESULTS WITH AND WITHOUT INTEGRATIONS: TAC AND EMISSIONS COMPARISON The base case processes were finally evaluated in terms of the different possibilities of integration. The analysis was done to quantify the effect of the integrations in the total annual costs. At the same time, liquid and gas emissions were quantified. The results are reported in Table 4. From Table 4, it is seen that power and heat integration (SCN2) have a considerable effect on the total annual cost of the processes, achieving a reduction from 9% for BC3-GHTUF to 43% for BC4-GLTUF compared to the base case processes without integration. However, SCN2 also presents the highest water emissions, with only up to 5% (wt) possible reduction. On the other hand, power, heat, and water integration in SCN4 can reduce significantly the TAC of BC4-GLTUF with 25%, and the water and gas emissions with 97% and 98% (wt), respectively. Nevertheless, in the cogeneration scenarios (SCN2, SCN3, and SCN4), the amount of gas produced in the conversion routes was reduced, but the reduction of the final total gas emission was compensated by CO2 generation in the cogeneration plant, which results in a reduction in the final total gas emission for BC4-GLTUF of 43% (wt) as observed in Table 4.

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ASSOCIATED CONTENT

* Supporting Information S

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.iecr.7b05382. Detailed information regarding model compounds selection, FT syncrudes compositions, supplementary model reactions, and liquid, gas, and solid emissions (PDF)

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AUTHOR INFORMATION

Corresponding Author

*Tel: +45 65 50 74 81. E-mail: [email protected]. ORCID

Ben-Guang Rong: 0000-0001-8730-5058 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors acknowledge financial support from CONACYTThe Mexican National Council for Science and Technology (Grant 326204/439098)) and the University of Southern Denmark.

8. CONCLUSIONS A systematic synthesis framework for the conversion of softwood BtL transportation fuels was presented, and different levels of heat, power, water, gases, and chemicals integration were investigated within the same framework. Multiple existing technologies including softwood gasification, pyrolysis, Fischer−Tropsch, water gas shift reaction, raw gas cleanup, upgrading technologies, and separation units were evaluated and combined into five different conversion process routes. A

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ABBREVIATIONS τadj = adjusted residence time τbase = base residence time avg = average BC = base case BC1-PHS = pyrolysis-hydroprocessing-separation BC2-PCCF = pyrolysis-catalytic cracking-fractionation DOI: 10.1021/acs.iecr.7b05382 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

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BC3-GHTUF = gasification-HTFT-fractional upgradingfractionation BC4-GLTUF = gasification-LTFT-fractional upgradingfractionation BC5-GHTH = gasification-HTFT-hydroprocessing BtL = biomass to liquid Co-LTFT = cobalt-based low temperature Fischer−Tropsch EIA = Energy Information Administration Fe-LTFT = iron-based low temperature Fischer−Tropsch Fe-HTFT = iron-based high temperature Fischer−Tropsch FT = Fischer−Tropsch HHV = higher heating value HTFT = high temperature Fischer−Tropsch LHV = lower heating value LPG = liquefied petroleum gas LTFT = low temperature Fischer−Tropsch MJ = megajoule MON = motor octane number NCG = noncondensable gases RON = research octane number SCN = integration scenario TAC = total annual cost VLE = vapor−liquid equilibrium WGSR = water gas shift reactor

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