Improved syngas processing for enhanced Bio-SNG production: A techno-economic assessment

1 Improved syngas processing for enhanced Bio-SNG production: A 1 techno-economic assessment 2 Pedro Haroa,*, Filip Jonhssonb, Henrik Thunmanb 3 a Andalusian Association for Research & Industrial Cooperation (AICIA), Camino de los 4 Descubrimientos s/n, 41092 Seville, Spain 5 b Energy Technology Division, Energy and Environmental Department, Chalmers University of 6 Technology. SE-412-96 Gothenburg, Sweden 7 * corresponding author. Current address: Universidad de Sevilla, Bioenergy Group, Chemical 8 and Environmental Engineering Department, Escuela Superior de Ingeniería, Seville, Spain. E- 9 mail: [email protected] 10 11 Abstract 12 This study analyzes the modification of an existing process configuration train for 13 Bio-SNG production using an indirectly-heated circulating fluidized bed gasifier. 14 Taking the process design of the Gothenburg Biomass Gasification (GoBiGas) 15 project, we investigate four modifications to the process design in order to 16 analyze what the potential effect from implementation of the results from state- 17 of-the-art research activities on bio-syngas conversion is. Firstly, aromatic 18 compounds are converted into Bio-SNG. Secondly, olefin hydration and 19 hydrodesulfuration units are combined in a high-temperature hydrodesulfuration 20 unit. Thirdly, the methanation section is modified and the pre-reformer unit in the 21 syngas conditioning section is eliminated. Finally, H2S and CO2 removal are 22 combined in the same unit. In order to provide a comprehensive comparison of 23 current GoBiGas process and the configuration investigated in this work, process 24 flowcharts and energy and material balances are provided. The study reveals that 25 the investigated configuration has the potential to reduce capital investment and 26 operating costs. Considering Phase II of GoBiGas project, a potential reduction 27 of 29% of the capital investment and 7 €/MWh of produced Bio-SNG could be 28 achieved comparing planned and investigated configurations. The results prove 29 that investigated modifications can have a large impact in the future 30 commercialization of Bio-SNG. 31 2 Keywords: Bio-SNG; biomass; process optimization; techno-economic 32 assessment 33 3 1. Introduction 34 To substitute natural gas with gas from lignocellulosic biomass (Bio-SNG) is an 35 important contribution to the reduction of greenhouse gas (GHG) emissions, 36 providing that the biomass can be regarded as a renewable carbon source. Bio- 37 SNG can be used as a substitute of diesel provided car-engines are adopted for 38 natural gas as a fuel. The main strengths of Bio-SNG compared to other biofuels 39 (diesel-FT and ethanol) are its versatility (domestic, heating and transportation 40 fuel) and it can be directly injected to the European natural gas grid. Considering 41 the high prices of natural gas in Europe (30-40 €/MWh) [1], the substitution of 42 natural gas by Bio-SNG seems to be the most favored option. 43 44 The development of plants for Bio-SNG production is in progress mainly in 45 Europe and there are currently three active demonstration projects: the Milena- 46 SNG plant in The Netherlands, and the Gothenburg Biomass Gasification 47 (GoBiGas) project and the Biomass-to-Gas (Bio2G) project in Sweden. Figure 1 48 shows the main difference between the projects with respect to Bio-SNG 49 generation, prior to the gas upgrading steps. The Milena-SNG project has been 50 proposed by the Energy Research Center of The Netherlands (ECN) for the 51 production of 10-12 MWBio-SNG. The plant will use the Milena technology for 52 biomass gasification and the OLGA technology for gas cleaning [2]. The GoBiGas 53 project is a two-step project initiated by the local utility Göteborg Energi AB for 54 the production of Bio-SNG. The first phase (Phase I), which is in operation, is a 55 20 MWBio-SNG plant and a second phase (Phase II) of 100 MWBio-SNG is under 56 planning. The Phase I plant is located in Gothenburg (Sweden) and it uses a dual 57 bed indirectly-heated circulating fluidized bed (i-CFB) gasifier developed by 58 REPOTEC [3]. The Bio2G project is under planning by E.ON and it targets the 59 production of 200 MWBio-SNG. The plant will be located in Malmö (Sweden) and 60 will use a pressurized oxygen blown direct fluidized bed (d-FB) gasifier developed 61 by the Gas Technology Institute (GTI) connected to a tar-reformer. Both projects 62 use wood pellets (for start-up) and forest residues as biomass feedstock. A 63 previous project was coordinated by the German Biomass Research Centre 64 (DBFZ): a demonstration plant of 1 MWBio-SNG in Güssing (Austria) using 65 REPOTEC gasifier [4,5]. 66 4 67 68 Figure 1. General overview of active demonstration projects for Bio-SNG 69 production (Europe) [2,3,6,7]. 70 71 Regarding literature on Bio-SNG, Kopyscinski has reviewed SNG production 72 from coal and biomass gasification [8]. Van der Maijden et al. provide a 73 comparison of three different biomass gasification technologies (entrained flow, 74 d-FB and i-CFB) on Bio-SNG production [9]. Gassner and Maréchal, Heyne and 75 Harvey and ECN have recently published different techno-economic 76 assessments for Bio-SNG production [10-13]. However, these works cannot be 77 compared with any of the demonstration Bio-SNG projects from Figure 1. Hence, 78 some technical aspects of these projects on bio-syngas cleaning and conditioning 79 were not included. 80 81 The main bottlenecks for the commercialization of Bio-SNG are the operating 82 cost and capital investment since these are higher than today’s fossil fuel 83 alternatives for which there is basically no capital cost. For the operating cost, the 84 biomass price contributes most and, thus, any increment of Bio-SNG production 85 (i.e. energy efficiency) is important in order to reduce the impact of biomass price. 86 The energy efficiency can be increased either by enhancing the conversion of 87 char in the gasifier or reducing the energy losses during syngas conditioning. The 88 capital investment can be reduced if some process units can be eliminated or if 89 their size and complexity can be reduced. 90 91 In this study, we compare the production of Bio-SNG from lignocellulosic biomass 92 taking the Phase II of the GoBiGas project and a modified configuration 93 investigated in this study as a basis for the design. The comparison is carried out 94 in terms of a techno-economic assessment. The investigated modifications have 95 the potential to enhance Bio-SNG production and reduce capital and operating 96 costs. The biomass pretreatment and gasification process are excluded from the 97 5 study, being the focus on the syngas treatment steps (cleaning and conditioning). 98 We describe the fundamentals of each modification and the implications in the 99 process design and economics. 100 101 2. Methodology 102 2.1. Description of GoBiGas process 103 Phase II of GoBiGas project considers the construction of a 100 MWBio-SNG plant. 104 Figure 2 shows an overview of the process, where both wood pellets and forest 105 residues can be used as feedstock. The gasification technology is by means of 106 an i-CFB gasifier operating at atmospheric pressure and at a temperature of 800- 107 900 ºC. The produced gas is de-dusted and cooled and heavy tars removed in 108 an oil scrubber using rapeseed-oil methyl ester (RME). Light tar (aromatic 109 compounds) along with chlorine and nitrogen compounds are removed 110 downstream using an adsorption bed with activated carbon. The tar-free bio- 111 syngas is compressed up to approximately 35 bar. The bio-syngas enters the 112 olefin hydrogenator, where olefins are converted into alkenes, and the 113 hydrodesulfuration (HDS) reactor, where organic sulfur is converted into H2S. 114 Downstream, H2S is removed and the H2/CO molar ratio adjusted in a water-gas- 115 shift (WGS) reactor to meet the requirements of the methanation section. The 116 pre-reformer (pre-methanator) unit converts all alkenes into methane, but also 117 produces a CO2-rich gas. The CO2 content of the cleaned bio-syngas is reduced 118 before methanation. The methanation is carried out using in-series adiabatic 119 reactors. Finally, the raw Bio-SNG meets natural gas standards after water 120 removal. 121 122 123 Figure 2. Planned Phase II GoBiGas process (100 MWBio-SNG) overview. 124 125 2.2. Process modeling 126 6 Material and energy balances for planned GoBiGas and investigated 127 configurations are obtained using Aspen Plus® process simulator (version 8.4). 128 Biomass pretreatment, gasification, de-dusting and oil scrubber sections are not 129 included in the study since they are not affected by the process modifications in 130 the investigated configuration. Both the investigated and the planned GoBiGas 131 configurations are designed to have the same Bio-SNG production (100 MWBio- 132 SNG). The Soave-Redlich-Kwong (SRK) thermodynamic model is applied for the 133 simulation of both configurations. Details of the modeling of process units for both 134 configurations are given in Annex A. 135 136 2.3. Description of process modifications 137 The modifications to the GoBiGas syngas cleaning and conditioning investigated 138 in this work have the aim to: 139 • Enhance the energy efficiency of the plant, reducing the amount of 140 biomass feedstock (reducing operating cost). 141 • Eliminate several operating units in the downstream processing of bio- 142 syngas (reducing capital investment). 143 This is carried out by four process modifications to the planned GoBiGas 144 configuration: 145 1. Replacement of the adsorption beds with activated carbon by a zeolite 146 bed. The modification allows light-tar (aromatics) to remain in the syngas 147 stream and be converted into Bio-SNG in the methanation section. 148 2. Combination of olefin hydrogenation and HDS units in a new high 149 temperature HDS unit. The modification allows the reduction of one 150 processing unit. 151 3. The pre-methanation unit is eliminated in order to avoid the formation of 152 CO2 and, for methanation, the TREMPTM technology from Haldor Topsoe 153 A/S is used, where the excess heat from methanation is balanced with the 154 partial recycle of converted bio-syngas. The modification allows the 155 reduction of one processing unit. 156 7 4. Combined removal of CO2 and H2S using an amine-absorption process. 157 The modification allows the reduction of one processing unit. This 158 modification is possible since the pre-reformer unit is eliminated. 159 160 As indicated in section 2.2, biomass pretreatment, gasification, de-dusting and oil 161 scrubber are not modified in the investigated configuration. Hence, Figures 3 and 162 4 show the flowcharts of downstream processing of the bio-syngas after the 163 removal of heavy tars (oil scrubbing). Figure 3 shows the flowchart of the planned 164 GoBiGas configuration (Phase II) and Figure 4 the flowchart of the investigated 165 configuration incorporating the four modifications described above. Table 1 gives 166 the technical differences between the configurations. There are some process 167 units that have been eliminated in the configuration investigated in this work 168 (adsorption bed, olefin hydrogenation, H2S removal and pre-reformer). There is 169 a new gas compressor for the recycle of bio-syngas in the first methanation 170 reactor. 171 172 173 Figure 3. Process flowchart for the planned GoBiGas configuration. It excludes 174 biomass pretreatment, gasification, de-dusting and oil scrubber. 175 176 177 Figure 4. Process flowchart for the configuration investigated in this study. It 178 excludes biomass pretreatment, gasification, de-dusting and oil scrubber. 179 180 Table 1. Technical aspects and comparison of process units for the planned 181 GoBiGas plant and the configuration investigated in this study. In italics the 182 units that have not been modeled in this study. 183 Unit GoBiGas Investigated in this work 8 Grinding Only for forest residues Unchanged Drying Only for forest residues Unchanged Gasification section i-CFB gasifier operating with steam addition at atmospheric pressure Unchanged Filtering Ceramic filter for dedusting Unchanged Oil scrubber Removal of heavy tars (C6+) using RME. Unchanged Adsorption beds (activated carbon) Removal of light tars (aromatics), Cl and N- compounds. Not present in this configuration Zeolite bed Not present in this configuration Removal of Cl and N- compounds Compression of raw syngas Multi-step (6) compression from atmospheric pressure to 35 bar Unchanged Olefin hydrogenation unit Hydrogenation of olefins It operates at 450 ºC Not present in this configuration HDS unit Conversion of organic sulfur compounds into H2S It operates at 350 ºC Conversion of organic sulfur compounds into H2S and hydrogenation of olefins to alkenes It operates at 550 ºC H2S and CO2 removal It is done in two different units: The first unit removes H2S before the WGS unit A single unit for both H2S and CO2 removal before methanation 9 The second unit removes CO2 before methanation section ZnO guard-bed Removal of H2S and Cl to ppb level Unchanged (only location) WGS unit Correction of H2/CO molar ratio for methanation Unaffected by methane or alkenes presence It is located prior to the zeolite-bed In order to operate under sulfuratmosphere the catalyst should be a Mo-based catalyst [24] Pre-reformer (Premethanation) Outlet methane content is approximately 40% Not present in this configuration Methanation section There are four adiabatic reactors inseries Recirculation of syngas is not necessary since the pre-reformer has increased the methane content in the stream There are three adiabatic reactors There is a partial recycling after the first reactor to reduce the temperature rise in the first reactor to 700 ºC 184 2.3.1. Conversion of aromatics into Bio-SNG 185 Table 2 shows the composition of a raw bio-syngas after removal of heavy tar in 186 an oil scrubber. About 18% of the energy in the raw syngas corresponds to olefins 187 (mainly ethylene) and 10% to aromatic compounds (mainly benzene). The 188 presence of olefins and aromatics has been avoided in the planned GoBiGas 189 configuration. However, while olefins are converted into alkenes in the olefin 190 hydration reactor, aromatics (light tar) are removed in the adsorption beds. This 191 removal of aromatic compounds from the bio-syngas implies an important energy 192 loss. 193 16 Figure 7. Composite curve for the configuration investigated in this work (blue: 347 heat sources; orange: heat demands). Biomass pretreatment, gasification, de- 348 dusting and oil scrubber are not included. 349 350 3.2. Process economics 351 Table 4 shows the reduction in the purchase equipment costs of the configuration 352 investigated compared to the planned GoBiGas configuration (Phase II). There 353 is a significant reduction thanks to the lower equipment-size and equipment 354 reduction, except for the WGS reactor. The total capital investment of the 355 configuration investigated is 29.1% lower than in the planned GoBiGas 356 configuration for the production of 100 MWBio-SNG. Total capital investments are 357 91.2 and 64.7 M€2010, respectively. 358 359 In order to analyze the impact of biomass feedstock on both configurations, 360 Figure 8 presents the sensitivity of biomass price on the minimum Bio-SNG 361 selling price. The minimum selling price Bio-SNG strongly depends on biomass 362 price. However, the impact is slightly lower in case of the investigated 363 configuration thanks to the reduction of required biomass feedstock for a constant 364 Bio-SNG production. Considering the comparison between both configurations, 365 the minimum selling price of Bio-SNG would drop 7 €/MWh for a price of 100 € 366 per dry tonne of biomass for the investigated configuration. 367 368 Table 4. Comparison of purchase equipment cost (PEC) of the configuration 369 investigated in this study. 370 Process unit % PEC reduction compared to planned GoBiGas configuration Grinding 8.9 Drying 6.3 Gasification section 6.5 17 Filtering 6.3 Oil scrubber 5.9 Adsorption beds Eliminated Compression of raw syngas 6.3 Olefin hydrogenator Eliminated HDS reactor 6.0 Zeolite bed New equipment H2S removal Eliminated ZnO guard-bed 13.1 WGS reactor -9.1 Pre-reformer Eliminated CO2 removal 9.6 (CO2 and H2S removal) Methanation section 49.8 Compression (recycling in methanation section) New equipment 371 372 Figure 8. Sensitivity of Bio-SNG minimum selling price with biomass price for 373 planned GoBiGas and investigated configurations (100 MWBio-SNG assumed in 374 both cases). 375 376 4. Discussion and conclusions 377 This study demonstrates that there are potential benefits from incorporating 378 process modifications in the downstream processing of bio-syngas for the 379 production of Bio-SNG. Taking the planned 100 MWBio-SNG GoBiGas plant (Phase 380 II) as an example, investigated process modifications could improve energy 381 efficiency while reducing capital and operating costs. The conversion of light tars 382 (aromatics) into Bio-SNG largely increases the process efficiency in the 383 conversion of bio-syngas. Besides, the reduction of process equipment and the 384 combination of some units (olefin hydration/HDS and H2S/CO2 removal) allows 385 18 an important reduction of capital investment (29%). The operating cost, mainly 386 biomass feedstock, is reduced thanks to the higher energy efficiency of the 387 investigated configuration. However, the results presented are based on previous 388 lab or pilot scale investigations that need to be further demonstrated before being 389 applied to commercial Bio-SNG production. The positive results of this study 390 prove the large positive impact that these investigations can have in the future 391 commercialization of Bio-SNG. 392 393 Acknowledgements 394 This work has been supported by the Chalmers University of Technology. Pedro 395 Haro thanks the Spanish Ministry of Economy and Competitiveness for the post- 396 doctoral Grant Torres Quevedo (PTQ-13-06203). 397 398 399 Annex A. Modeling of process units and Bio-SNG specifications for both 400 configurations 401 The process units have been modeled using Aspen Plus®. The name in brackets 402 is the corresponding name in the process simulator. 403 404 • Heat exchanger [Heater]: pressure drop 3 psi 405 • Pump [Pump]: η = 90% 406 • Knock-out drum [Flash2]: adiabatic, no pressure drop 407 • Compressor: isentropic stage efficiency, η = 72% 408 • Adsorption beds (activated carbon): 100% HCl recovery, 100% HCN 409 recovery, 10 ppm benzene slip 410 • Zeolite-bed [Sep]: 100% HCl recovery, 100% HCN recovery, 10% N2 recovery 411 • Amines [Sep]: 95% CO2 recovery or 95% H2S recovery, 1% H2 slip, 2% CO 412 slip, 2% CH4 slip, 2% C2 slip, 20% C3+ slip. Power consumption 4.5 MJ/kg 413 19 CO2 or H2S equivalent. There is no CO2 compression or conditioning for 414 sequestration. 415 • Olefin hydrator [RStoic]: T= 450 ºC (isothermal), pressure drop 5 psi, reactions 416 (3-6) at equilibrium 417 • HDS reactor [RStoic]: pressure drop 5 psi, isothermal 418 o Planned GoBiGas configuration (T=550 ºC): Equilibrium of reactions 419 (1-6) 420 o Investigated configuration (T= 350 ºC): Equilibrium of reactions (1-3) 421 • WGS reactor [RStoic]: T= 250 ºC (isothermal), pressure drop 5 psi, reactions 422 (1,3) at equilibrium 423 • Pre-reformer [RGibbs]: (adiabatic), pressure drop 5 psi, steam/C (able-to-be 424 reformed) ratio of 3, minimization of Gibbs free energy 425 • Methanation [RGibbs]: 426 o Planned GoBiGas configuration: 4 in-series adiabatic reactors with 427 inter-cooling. Minimization of Gibbs free energy. 428 o Investigated configuration: 3 in-series adiabatic reactors with inter- 429 cooling. There is a partial recirculation of the outlet stream from the first 430 reactor (15.7%). Minimization of Gibbs free energy. 431 • ZnO guard-bed [Ideal Sep]: 99.99% recovery of H2S, 95% recovery of COS 432 and other organic sulfur. T = 45 ºC 433 434 • Composition of the SNG (specifications) for both configurations: 435 o T = 45 ºC 436 o CH4 content (molar) = 99.46% (GoBiGas), 98.41% (investigated) 437 o CO2 content (molar) = 0.08% (GoBiGas), 1.16% (investigated) 438 o H2 content (molar) = 0.46% (GoBiGas), 0.42% (investigated) 439 o Upper Wobbe index (MJ/Nm3)= 52.8 (GoBiGas), 51.6 (investigated) 440 20 441 Annex B. Calculation of total capital investment, operating cost, and 442 discount cash flow analysis 443 444 The data for the calculation of the purchase and installation of equipment is 445 shown in Table B.1. The TCI is calculated from the costs of installed equipment 446 and indirect costs (21.9% of installed equipment) [27]. The data for the calculation 447 of the operating cost is shown in Table B.2. The economic assumptions for the 448 calculation of the IRR are shown in Table B.3. 449 450 Table B.1. Data for capital cost calculations of the most important equipment.a 451 Unit Base purcha se cost Referen ce year Scale facto rb Units Base scale Installati on factorc Referen ce Grinding 0.13 MUS$ 2003 1 dry tonne/d ay 2140 2.47 [27] Drying 0.39 MUS$ 2008 0.70 dry tonne/d ay 1100 2.47 [27] Gasificatio n section 10.7 MUS€ 2010 0.72 MWth of biomass (LHV) 100 2.47 [11] Filtering 2.7 MUS$ 2008 0.70 MWth of biomass (HHV) 500 2.47 [27] Oil scrubber 18.5 M€ 2010 0.65 Nm3/h 13549 7 1 [27] Water scrubber 3.4 MUS$ 2010 0.70 m3/s 9 2.47 [11] Compressi on of raw syngas 5.85 MUS$ 2009 0.70 MWe 5.44 1.32 [27] 21 Olefin hydrator 3.45 kUS$ 2007 0.67 t/h 65.77 2.47 [28] HDS unit 3.45 kUS$ 2007 0.67 t/h 65.77 2.47 [28] Zeolite bed 22.6 kUS$ 2002 1 Nm3/s 8 3 [27] CO2 and H2S removal 15.4 MUS$ 2001 0.65 lb/s of eq. CO2 27.83 2.47 [27] ZnO guard-bed 22.6 kUS$ 2002 1 Nm3/s 8 3 [27] Prereformer 41 MUS$ 2002 0.60 kmol/h reforme d 1277 1 [27] WGS unit 0.32 MUS$ 2002 0.56 lb/s 98.45 1 [29] Methanatio n 43.8 kUS$ 2007 0.67 kg/s 1st reactor 149.6 9 2.47 [28] a A conversion rate of 1.35 US$/€ has been used in this study. 452 b Scaling equation: Cost/Costbase = (Scale/Scalebase)n. 453 c The installation factor is 1 if the base cost already includes the indirect costs. 454 455 Table B.2. Data for calculating operating costs (assuming 7500 operating hours 456 per year). 457 Fixed operating costs (% TIC) Labor 1.56 Maintenance 1.50 General expenses 3.07 Management and operation services 0.44 Cost of goods sold, marketing, logistics and others 1.32 Insurance 0.50 Total 8.39 Variable operating costs 22 Biomass 50-150 €/dry tonne Chemicals and absorbents (CO2 and H2S removal) 2.4 €/t CO2 eq. 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