DOI: 10.3303/CET25117091 Paper Received: 10 December 2024; Revised: 6 April 2025; Accepted: 27 April 2025 Please cite this article as: Romero M.J., Arato E., 2025, Assessment of the Techno-economic Viability to Produce Biohydrogen from Biowaste, Chemical Engineering Transactions, 117, 541-546 DOI:10.3303/CET25117091 CHEMICAL ENGINEERING TRANSACTIONS VOL. 117, 2025 A publication of The Italian Association of Chemical Engineering Online at www.cetjournal.it Guest Editors: Fabrizio Bezzo, Flavio Manenti, Gabriele Pannocchia, Almerinda di Benedetto Copyright © 2025, AIDIC Servizi S.r.l. ISBN 979-12-81206-17-5; ISSN 2283-9216 Assessment of the Techno-Economic Viability to Produce Biohydrogen from Biowaste Max J.A. Romero*, Elisabetta Arato DICCA, Department of Civil, Chemical and Environmental Engineering, University of Genoa. Via Opera Pia, 15, 16145 Genoa, Italy max.romerorivas@unige.it The adoption of effective strategies to reduce the production costs of renewable H2 and increase its competitive position compared to fossil-based H2 in hard-to-abate sectors is a priority of the European Union. One of these strategies can be to diversify the use of renewable electricity by using other renewable resources such as biomass to produce biohydrogen. The aim of this paper was to assess the technical and economic performance of H2 production by steam reforming (SR) of natural gas as well as three biohydrogen production systems using the levelized cost of H2 (LCOH) as a methodology. Based on a 2,700 Kg H2/h facility, LCOH results showed that bio-oil reforming (€ 3.56/kg) is the least expensive way to produce biohydrogen compared to biomass gasification (€ 4.08/kg) and biogas reforming (€ 4.52/kg). Furthermore, the bio-oil reforming pathway provided an LCOH quite similar to the LCOH obtained by SR of natural gas (€ 3.52/kg), indicating that its use could be viable hard-to-abate sectors. 1. Introduction In 2022, Italy produced around 0.60 Mt of H2, of which 98.65% was obtained from fossil fuels via conventional technologies such as steam methane reforming (SMR) and as by-product of ethylene and styrene production. Another minor amount (1.15%) was obtained as a by-product of chlorine and sodium chlorate production via electrolysis, while water electrolysis accounted for only 0.05% of total production (EHO, 2023). A major factor limiting the growth of renewable H2 production is its high average levelized cost (LCOH), which depends on capital and operational expenditures (CAPEX and OPEX). The CAPEX represents the project's initial investment expenditures and mainly includes the costs of equipment, installation, engineering procurement and construction (EPC) and contingencies and owner costs (C&OC). While OPEX refers to the fixed (e.g. maintenance and insurance) and variable (e.g. raw material, electricity, fuel gas and water consumption) operation expenditures. In Italy in 2023, the H2 production from unabated fossil-based sources offered a cheaper LCOH (€ 3.70/kg H2, excluding CAPEX because it is assumed that SMR plants are already operational) than both the use of fossil fuels with carbon capture utilization and storage (CCUS) (€ 4.40/Kg H2) and the use of electrolysis with a direct connection to a renewable energy source (€ 6.70/kg H2) (EHO, 2024). In line with the Hydrogen Strategy for a Climate-Neutral Europe, Italy intends to promote the production and use of renewable H2 through mechanisms such as the National Hydrogen Strategy (NHS) and the National Recovery and Resilience Plan (NRRP). The preliminary NHS guidelines proposed a target of covering 2 % of final energy consumption with H2 by 2030 (approximately 0.70 Mt H2/year), which would be partially met by the installation of 5 GW of electrolysers (MISE, 2020). While the NRRP recognized the importance of developing projects to produce renewable H2 in brownfield sites and hard-to-abate sectors (such as refining, steelmaking, chemical, transport, heating and cooling in buildings, electricity generation) as well as to improve its supply with the creation of H2 valleys (H2 supply chains) (Gandiglio and Marocco, 2024). In fact, building optimal H2 supply chains across industrial zones is critical to minimize the overall cost of the energy systems (Fadhil et al., 2024). Despite the various mechanisms developed, increasing the economic competitiveness of renewable H2 in key industrial sectors compared to fossil-based H2 remains a priority of the European Union. On this basis, one strategy for reducing H2 production costs can be to diversify the use of renewable electricity with the use of other renewable resources such as biowaste (e.g. biodegradable garden and park waste, food and kitchen waste 541 from households, restaurants, caterers and retail premises, and wastes from food processing plants) and biomass residues (e.g. lignocellulosic materials generated by the agricultural, forest, and agro-industrial sectors). These materials can be used to produce biohydrogen via various primary biochemical (e.g. anaerobic digestion and fermentation) and thermochemical pathways (e.g. pyrolysis and gasification) (Yagüe et al., 2024). In anaerobic digestion microorganisms break down organic materials under oxygen-free conditions to produce biogas, which is mainly composed of CH4 and CO2. While, pyrolysis is typically carried out at temperatures ranging from 300 °C to 500 °C in the absence of reagents such as O2 (combustion) or H2O (hydrolysis) to convert biomass into a gaseous mixture of various condensable oxygenated compounds that, after cooling, form a liquid product known as bio-oil, a solid fraction known as biochar and small amounts of non-condensable gases (CO, CO2, CH4, and H2). Biomass pyrolysis can be categorized as slow or fast depending on the heating rate. While slow pyrolysis generates a high amount of biochar, fast pyrolysis produces much more bio-oil (around 60–70 % by mass) (Situmorang et al., 2020). Unlike pyrolysis, the biomass gasification occurs at temperatures ranging from 700 °C to 1200 °C in the presence of a gasifying agent such as air, O2, steam or their mixtures, resulting in the production of syngas which is mainly composed of CO and H2 and minor amounts of CH4,CO2 and N2, as well as tar and char. Based on the H2 percentage in the gas (40 vol %) and reduced impurities, steam gasification appears to be most suitable for H2 production than air gasification (Lepage et al., 2021). In a further step, intermediate products must be improved using processes such as steam reforming (SR) and water gas shift (WGS), followed by purifying processes such as pressure swing adsorption (PSA) to recover high-purity H2. Usually SR process occurs on light hydrocarbons in the presence of H2O to produce CO and H2 as in the case of SMR described in Eq(1), but it can also occur on oxygenates, according to Eq(2). CO produced during SR can react with H2O in the WGS process, increasing the amount of H2, according to Eq(3). Recently, it was proposed to produce H2 from biogas via reforming integrated with membrane-based CO2 (Cormos et al., 2024). Also, it was proposed to transform condensable oxygen compounds (in gaseous state) obtained from fast pyrolysis of biomass into biohydrogen by a continuous SR process (Leijenhorst 2016), however in this paper we focused on the SR of bio-oil (Zhang et al., 2013). 𝐶𝐻4 + 𝐻2𝑂 = 𝐶𝑂 + 3𝐻2 (1) 𝐶𝑥𝐻𝑦𝑂𝑧 + (𝑥 − 𝑧)𝐻2𝑂 → 𝑥𝐶𝑂 + [𝑦/2 + 𝑥 − 𝑧]𝐻2 (2) 𝐶𝑂 + 𝐻2𝑂 → 𝐶𝑂2 + 𝐻2 (3) Considering the above, this paper focused on assess the technical and economic performance of producing biohydrogen from biogas, bio-oil and syngas using the LCOH as a methodology and compare the outcomes with those of producing fossil-based H2. The LCOH shows the average cost of H2 production per unit of H2 and represent the minimum price at which H2 must be sold to achieve a return of the investment of the project (break- even point) (Wolf et al., 2024). Additionally, given that some refineries in Italy have modified their production setups in the last decade to produce high-quality biofuels from biowaste instead of fossil fuels, but they still use fossil-based H2 for refining, the biorefinery industry was considered as a model in which biohydrogen could be used if technological, economic, and environmental conditions allow it. 2. Biohydrogen production processes and demand of raw materials and energy As showed in Figure 1 System 1 involved the H2 production from natural gas via SR, while the systems for producing biohydrogen were defined as follows: biogas production from biowaste through anaerobic digestion (AD) (biochemical pathway) and its subsequent upgrading via SR, WGS and PSA (system 2); bio-oil production from biomass residues through fast pyrolysis (FP) and its subsequent upgrading via SR, WGS and PSA (system 3); syngas production from biomass residues through steam gasification (SG) and its subsequent upgrade via WGS and PSA (system 4). Considering the biorefinery industry as model, an H2 productivity of 30,000 Nm3/h (2,700 Kg/h) was established for all systems which is the amount required by a biorefinery to process around 600,000 t/y of biowaste and produce 540,000 t/y of biofuels (Eni S.p.A., 2022). Furthermore, it was assumed that the systems operated for 8,760 h/y and have an operational lifespan of 20 years at a 7 % discount rate. The results concerning the demand for raw materials, energy and other inputs to produce 23,652 t H2/y (showed in Table 1) was determined after an extensive literature review and based on data from previously developed simulation models. In general, an H2 recovery efficiency of the PSA unit of 85 % was assumed for all the systems, resulting in an H2 demand of 1.18 kg prior to the PSA process (Yao et al., 2017). 542 Figure 1: Schematic representation of the biohydrogen production systems under analysis Table 1: Raw material and energy demand to produce 23,652 t H2/y via system 1 (Eni S.p.A., 2022), system 2 (Ardolino et al., 2018), system 3 (Zhang et al., 2013) and system 4 (Yao et al., 2017) Description System 1 System 2 System 3 System 4 Intermediates demand (t/y) H2 yield in reforming and WGS (% by mass) 41 41 14 CH4 67,212 67,212 Biogas (28.46 % by mass of CH4) 236,204 Bio-oil 193,059 Syngas (2.60 % by mass of H2) 1,070,844 Raw materials demand (t/y) NG (95.64 % by mass of CH4) 70,276 Biowaste (biogas yield of 17.90 % by mass) 1,319,579 Dry biomass (7.00 % moisture) (bio-oil yield of 60.82% by mass) 317,427 Wet biomass (25.00 wt% moisture) (bio-oil yield of 48.97% by mass) 394,240 Dry biomass (16.00 % moisture) (dry biomass rate of 0.45 Kg/kg syngas) 481,986 Wet biomass (32.00 % moisture) (wet biomass rate of 0.56 Kg/kg syngas) 595,496 Energy and other materials consumption Fuel gas (t/y) 8,754 8,754 0 0 Electricity (MWh/y) 10,884 144,157 47,994 96,971 Water (t/y) 225,4999 238,599 185,224 118,258 3. Economic assessment The LCOH is calculated from the point at which the present value of all income received from H2 sales balances a single present value of overall cost (CAPEX and OPEX), as showed in Eq(4). When H2 price, H2 productivity and OPEX remained constant during the plant lifespan, the LCOH can be determined by Eq(5) (IEAGHG, 2013). ∑ (𝐻𝑦𝑑𝑟𝑜𝑔𝑒𝑛 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛)𝑛 ∗ (𝐻𝑦𝑑𝑟𝑜𝑔𝑒𝑛 𝑝𝑟𝑖𝑐𝑒)𝑛 (1 + 𝑟)𝑛 𝑛 = ∑ [ (𝐶𝐴𝑃𝐸𝑋)𝑛 (1 + 𝑟)𝑛 + (𝑂𝑃𝐸𝑋)𝑛 (1 + 𝑟)𝑛 ] 𝑛 (4) 𝐿𝐶𝑂𝐻 = (𝐶𝐴𝑃𝐸𝑋 × 𝐶𝐶𝐹) + 𝑂𝑃𝐸𝑋 𝑃𝑙𝑎𝑛𝑡 𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑣𝑖𝑡𝑦 (5) The term “levelized” refers to the fact that the single present value of overall cost can be transformed into a series of uniform (level) annuities (although the periods can be other than years) using so-called levelization factors. The levelization factor used in Eq(5) to convert CAPEX into annual values was the Capital Charge Factor (𝐶𝐶𝐹), which can be calculated using the Eq (6). The resource cited here provides additional information about the application of economic factors (Blank and Tarquin, 2012). 543 𝐶𝐶𝐹 = 𝑟 × (1 + 𝑟)𝑛 (1 + 𝑟)𝑛 − 1 (6) The factor (1 + 𝑟)𝑛 showed in Eq(4) and Eq(6) is known as the compound amount factor, where 𝑟 is an interest rate (7 %) and 𝑛 the plant lifespan (20 years) (Richard et al. 2024). On the other hand, to estimate the CAPEX, the total direct plant costs (TDPC) for each of the installations that are part of the biohydrogen production systems were first calculated using the cost-to-capacity method according to the Eq(7) (Yao et al., 2017). In Eq(7), the terms “reference capacity” and “reference capital” refer to the process capacity and investment capital of a known plant (data obtained from previous studies). While the terms “scaling capacity” and “scaled capital” refer to the process capacity and investment capital of the plant that will be implemented. Because the calculations in Eq(7) concern a whole plant, a scale factor of 0.80 was used (Arfan, et al., 2023). Prior to applying the cost-to-capacity method, the known plant costs that have a specified reference year were adjusted for inflation using the chemical engineering plant cost index according to the Eq(8). 𝑆𝑐𝑎𝑙𝑒𝑑 𝐶𝑎𝑝𝑖𝑡𝑎𝑙 = 𝑅𝑒𝑓𝑒𝑟𝑒𝑛𝑐𝑒 𝐶𝑎𝑝𝑖𝑡𝑎𝑙 ∗ ( 𝑆𝑐𝑎𝑙𝑖𝑛𝑔 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝑅𝑒𝑓𝑒𝑟𝑒𝑛𝑐𝑒 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 ) 𝑆𝑐𝑎𝑙𝑒 𝐹𝑎𝑐𝑡𝑜𝑟 (7) 𝑅𝑒𝑓𝑒𝑟𝑒𝑛𝑐𝑒 𝐶𝑎𝑝𝑖𝑡𝑎𝑙 = 𝑂𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝐶𝑜𝑠𝑡 ∗ 𝑃𝑟𝑒𝑠𝑒𝑛𝑡 𝐶𝑜𝑠𝑡 𝐼𝑛𝑑𝑒𝑥 𝑂𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝐶𝑜𝑠𝑡 𝐼𝑛𝑑𝑒𝑥 (8) The resulting scaled capitals showed in Table 2 highlight that the steam gasification plant (€ 235 M) has the highest capital compared to the other plants. However, this capital is lower when compared to each of the overall biohydrogen production systems, given that system 2 consists of the integration of the biogas production plant and the SMR plant (total of € 206 M), and system 3 consists of the integration of the bio-oil production plant and the bio-oil reforming plant (total of € 287 M). Table 2: Investment estimate for each of the plants that integrate the systems under analysis Description Reference capacity (kg/h) Reference capital (€ M) Scaling capacity (kg/h) Scaled capital (€ M) Source System 1 SR plant (based on CH4 processed) 198 6 7,673 118 (Yao et al., 2017) System 2 AD plant (based on CH4 produced) 287 6 7,673 88 (Yao et al., 2017) SR plant (based on CH4 processed) 198 6 7,673 118 (Yao et al., 2017) System 3 FP plant (based on bio-oil produced) 3,600 40 22,039 170 (Arfan et al., 2023) Bio-oil SR plant (based on bio-oil processed) 50,000 225 22,039 117 (Sarkar and Kumar, 2010) System 4 SG plant (based on syngas produced) 4,080 15 122,242 235 (Yao et al., 2017) The engineering procurement and construction costs (EPC) and the contingencies and owner's costs (C&OC) were then added to the TDPC, using the percentages proposed in the literature (Spallina et al., 2016). The final estimated CAPEX for each of the systems under evaluation are shown in Table 3. These amounts were then converted into annuities using the CCF, as described above. On the other hand, OPEX was estimated considering the annual expenses of raw materials (€ 0.02/MJ NG, € 25/t biowaste, € 60/t wet biomass residues), fuel gas (€ 0.02/MJ NG), electricity (€ 198/MWh), water (€ 2.82/t), maintenance (2% of CAPEX), insurance and taxes (2% of CAPEX). While the plant productivity was calculated as the product of production capacity and the plant’s equivalent working hours (8760 h/y). Figure 2 highlights CAPEX and OPEX per year, while final LCOH results were summarized in Table 4. CAPEX and raw material costs are the most important factors influencing LCOH in all the systems analyzed, for example, in system 1 the cost of NG accounted for 67% of the total annual costs. Consequently, the LCOH of system 1 is equal to the LCOH of system 3 only when CAPEX was not considered. On the other hand, energy consumption (electricity and fuel gas) has a significant impact on the LCOH of system 2, but it is reduced in system 3 and system 4 since secondary products such as char are used to cover part of the energy requirement. 544 Table 3: CAPEX estimation for the implementation of the systems under analysis (€ M). Equipment System 1 System 2 System 3 System 4 Total direct plant cost (TDPC) 118 206 287 235 Indirect Cost (IC) (14 % of TDPC) 17 29 40 33 Engineering procurement and construction (EPC) (TDPC + IC) 135 235 327 268 Total contingencies and owner's costs (C&OC) (15 % of EPC) 20 35 49 40 CAPEX (EPC + C&OC) 155 270 376 308 Figure 2: Estimate of the annualized CAPEX and OPEX of the systems under analysis Table 4: LCOH results obtained for the systems under analysis. Description System 1 (without CAPEX) System 1 System 2 System 3 System 4 LCOH (€/Kg) 3.52 4.14 4.52 3.56 4.08 4. Conclusions In this paper the technical and economic performance of three biohydrogen production systems were analysed and the results were compared to typical H2 production from NG reforming. Based on a 2,700 Kg H2/h facility, preliminary LCOH results showed that bio-oil reforming (€ 3.56/kg) is the least expensive way to produce biohydrogen when compared to biomass gasification (€ 4.08/kg) and biogas reforming (€ 4.52/kg). In fact, the LCOH of the bio-oil reforming pathway was quite similar to the LCOH of the natural gas SR pathway when CAPEX was not considered (€ 3.52/kg) and even lower than the LCOH of fossil-based H2 production with CCUS (€ 4.40/Kg H2, as reported in the introduction). This result indicates that the H2 production from bio-oil reforming could be economically competitive and viable in hard-to-abate sectors. On the other hand, although biohydrogen production from biogas reforming appears to be less-cost effective mainly due it requires a large amount of raw material as well as energy (electricity), its economic performance, as well as that of the other biohydrogen production systems can improve if the raw material is available at no economic cost. Additionally, from an environmental perspective combining biohydrogen production with CCUS could be an option to develop negative emission systems. Although the preliminary LCOH analysis can still be improved by considering additional costs (e.g. catalysts, operation labor, waste disposal and environmental impact costs), the results showed that biohydrogen production can be competitive compared to H2 production from NG. In fact, a future study could include in addition to financial costs also environmental impact costs, considering as suggested by the ISO standard ISO15686-5 (life-cycle cost) the economic loss of well-being (e.g., human health and biodiversity) due pollutant emissions of each system as well as the mitigation cost of any necessary intervention. Overall, the results are positive to encourage the reduction of fossil-based H2 consumption in hard-to-abate sectors, improving waste and residual biomass management, and promoting a net zero greenhouse gas emissions economy in Italy and Europe. 545 Acknowledgments This research was developed within the project ‘Network 4 Energy Sustainable Transition—NEST’ funded under the National Recovery and Resilience Plan (NRRP), Mission 4 Component 2 Investment 1.3—Call for Tender No. 1561 of 11.10.2022 of Ministero dell’Università e della Ricerca (MUR); funded by the European Union— NextGenerationEU. 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Zhang Y., Brown T., Hu G., Brown R., 2013, Comparative techno-economic analysis of biohydrogen production via bio-oil gasification and bio-oil reforming, Biomass and Bioenergy, 51, 99–108. 546 36romerorivas.pdf Assessment of the Techno-Economic Viability to Produce Biohydrogen from Biowaste