Stepping toward Efficient Microreactors for CO2 Methanation: 3D-Printed Gyroid Geometry

Depósito de Investigación de la Universidad de Sevilla https://idus.us.es/ This document is the Accepted Manuscript version of a Published Work that appeared in final form in ACS Sustainable Chemistry & Engineering, Vol. 9, copyright © 2021 American Chemical Society after peer review and technical editing by the publisher. To access the final edited and published work see https://doi.org/10.1021/acssuschemeng.1c01980 1 Stepping towards a low-carbon economy. Formic Acid from biogas as case of study Francisco M. Baena-Moreno a,b *, Laura Pastor-Pérez b, Zhien Zhang c, T. R. Reina b a Chemical and Environmental Engineering Department, Technical School of Engineering, University of Seville, C/ Camino de los Descubrimientos s/n, Sevilla 41092, Spain b Department of Chemical and Process Engineering, University of Surrey, GU2 7XH Guildford, United Kingdom c William G. Lowrie Department of Chemical and Biomolecular Engineering, The Ohio State University, Columbus, OH 43210, USA *Corresponding author. E-mail address: [email protected] (Francisco M. Baena-Moreno) Abstract The European Union has set an ambitious plan for addressing the Global Challanges in the coming years. One of these challenges is the use of biomass and the production of biomass-derived products following the spirit of a circular economy. Biogas obtained from biomass anaerobic digestion could play a pivotal role in this strategy. Herein an innovative strategy for synergizing biogas upgrading to biomethane and formic acid production from CO2 is presented. A profitability analysis of the combined biogas upgrading – CO2 utilization process was conducted to assess the economic viability of this novel approach. The profitability study focuses mainly on net present value and profitability index. Even though the process is environmentally favourable, negative profitability results are obtained. To revert the negative outputs, out of the market formic 2 acid prices (1767-3135 €/t) would be needed to achieve a net present value equal to zero. The alternative of feed-in tariffs biomethane subsidies needs high values (121.1- 269.4 €/MW) to reach profitable scenarios. These unsuccessful profitability results are ascribed to high consumables costs, mainly associated with the catalytic conversion of a CO2-rich feedstock. A 80% reduction of catalysts costs can considerably improve net present value up to 50%. This result indicates that further research is needed to find econimocally appealing catalysts to perform this process. The effect of biomethane subsidies as percentage of investment was also considered, evidencing encouraging results for small scale plants. Keywords Biomethane production; Biogas upgrading; CO2 utilization; Green energy production; Waste valorization; Formic Acid 1. Introduction The main forthcoming challenges that policy-makers need to face during the next decade are natural resources consumption, climate change and energy security [1,2]. Currently, the European Union (EU) is planning new strategies to address the aforementioned issues through the new programme Horizon Europe (HE) [3]. The first strategic plan of HE gives some orientations for breaking-down the dependence on non-renewable resources and pursues the transition towards a bio-based economy. The achievement of these goals demands progress on technical solutions for transforming our present manufacturing processes into climate-neutral options [3,4]. Among the different alternatives, the first strategic HE plan contemplates the use of biomass and waste to produce biofuels, renewable chemicals and materials. Undoubtly, biomass utilization will promote the creation of bio-based supply chains for the establishment of bioeconomy policies [5,6]. 3 One of the potential uses of biomass is its anaerobic digestion to produce biogas [7], which is mainly composed by CH4 (60%) and CO2 (40%) [8,9]. Biogas is a very versatile resource with multiple potential outcomes for green energy and clean chemicals production [10]. Typically, there are three alternatives to exploit biogas namely, its utilization in a combined heat and power (CHP) unit to produce electricity and heat [11]; its conversion in a solid oxide fuel cell (SOFC) for direct electricity generation with a high energy efficiency [12,13]; or its upgrading to produce biomethane [14]. The use of biogas for the production of electricity in a CHP or SOFC enhances the energy security as well as it reduces the dependence of fossil fuels [15]. Nevertheless the CO2 contained in the biogas mixture would be released to the atmosphere, affecting negatively to the climate change. The third path consists on upgrading biogas to biomethane, which is also considered a synthetic natural gas [16]. This option avoids the consumption of natural resources while simultaneously producing an added value product from organic waste. However, the CO2 separated from biogas needs an ending-use to transform biogas upgrading process in a 100% environmentally friendly option [17]. Carbon capture and utilization technologies (CCU) have been widely studied in this regard [18,19]. In this vein, some works examined the potential of synergizing biogas upgrading and carbon utilization [20,21]. Mineral carbonation process is one of the studied alternatives [22], which leads to calcium and magnesium carbonate as added value products [23,24]. There are also works examining the potential of power-to-X, where X can refer to chemicals, liquid, fuel or gas, among others [25,26]. Within this topic, the concept of power-to-gas and power-to-liquid has gained attention during the last decade [27,28]. Nevertheless, there is a substantial knowledge gap and lot of room to develop CO2- derived products in a biogas upgrading configuration. The future directions of the scientific community are devoting great efforts to pursue alternatives to supply the future demand of chemicals and fuels. This is a global effort which will hopefully lead to a new sustainable energy paradigm. Figure 1 represents the alternative for biomass valorization to produce biomethane and CO2-based products. 4 Figure 1. Simplified road-map for the conversion of biomass to added value products using biogas as a key resource. This work aims to integrate biogas upgrading and CO2 utilization towards formic acid (FA) production. We decided to explore FA as added value product from CO2 for many reasons. The production of FA from CO2 has been proved to produce 10 time less CO2 emissions than traditional FA manufacturing process, being a promising climate-neutral alternative [29]. In this sense, our work would help to extend the research of the aforementioned challenges. Furthermore, producing FA from biogas avoids the of CO2 emissions penalty since biogas comes from renewable sources. The traditional FA manufacturing process emits about 2.18 t CO2/t FA [29]. For a 12000 t/y FA plant, at current CO2 penalty prices (approximately 24.6 €/t [30–32]), about 644 k€/y would be saved. Indeed, under the future estimations for carbon emissions penalty (55 €/t by 2030 [33]), the savings can reach 1439 k€/y. Thus, it is attractive to explore the economic performance of this new approach. FA is a widely used chemical in food or textile industry [34]. Thus, producing biomethane and FA in a biogas upgrading plant would not only provide an extra-energy input, but also a high-value chemical that can avoid the 5 consumption of extra resources (i.e., purchasing of other chemicals produced from fossil fuels). Many catalysis experts have explored the route of FA production from CO2 during the last decade and hence a great deal of data is available in literature [29,34,35]. In this work we analyse the profitability of this novel process, as economic outputs are the basis for the creation of new circular economy policies. To this end, several scenarios were proposed in order to provide a wide range of alternatives. The work is organized as follows: first, a methodology section explains the issues related to process description, modelling and economic assessment. Moreover, the baseline scenarios and the scope of the study are described accordingly in this section. Afterwards, the results obtained for the baseline scenarios are presented. From these results, the study of the influence of some key parameters on the overall economic performance is proposed and analysed. The alternative of receiving subsidides for injecting biomethane to the natural gas grid was also considered through subsidies as feed-in tariffs and percentage of investment. Under these presmises, our work contributes to dictate the future needs and tendencies regarding technical evolution or economic efforts which could be helpful for policymakers. Our ultimate goal is to emphasize the role of biomass-derived products in a sustainable bio-based economy and the need to perform comprehensive technology assessments to support the experimental research on low-carbon technologies. 2. Methodology 2.1 Process description Figure 2 schemematises the process to obtain biomethane and FA from biogas, as briefly described in the Introduction section. The overall process is divided into three main stages according to the three main operations. The first stage is biogas upgrading where biogas is splitted into biomethane and CO2. For sake of simplicity it was assumed that the biogas available is a standard 60% CH4 – 40% CO2 mixture, without considering any 6 specific biomass source. The most studied biogas upgrading technologies are pressure swing adsorption, water scrubbing, organic physical scrubbing, chemical absorption, membrane technology and cryogenic separation [36]. The efficiency in terms of methane recovery of these technologies is very similar (96-99%) [37], but the commercial availability and the upgrading costs differ. The most commercial extended types are water scrubbing, membrane and chemical absorption [38]. Chemical absorption needs extra heat to regenerate the solvent and the amine solution emissions are considered hazardous. Water scrubbing requires the use of antifouling and drying agents [39]. Therefore, membrane technology has increased its commercial extension during the last years. Membrane technology has proved to be an efficient solution for biogas upgrading since it presents the lowest investment and operational costs [39]. For these reasons, membrane operations were chosen for the biogas upgrading stage [40]. Four biogas plant sizes were selected in agreement with the classification previously reported elsewhere [41]. Briefly, small scale (100 and 250 m3/h), medium scale (500 m3/h) and large scale (1000 m3/h) biogas plants were studied. The second stage identified is the production of H2 to fulfil the H2 input in the FA synthesis. Steam reforming of methane (SRM) and water electrolysis are the more extended H2 generation routes [42,43]. Steam reforming is a well-established industrial process but with a heavy carbon fingerprint. Hence, to promote a green process, H2 should be produced by using a renewable electricity source (i.e. wind, solar) or free carbon sources (i.e. nuclear). In this sense, water electrolysis using a renewable electricity source is a sustainable path to produce H2. Thus, water electrolysis fits well in our proposed green process. If for an reason SRM is to be pursued a carbon capture and storage (CCS) should be implemented to alleviate the CO2 emissions, but the uncertainties regarding CO2 storage behaviour makes the process not as mature as water electrolysis in terms of net greenhouse gases (GHG) emissions [44]. Moreover, electrolysis is consider the most effective technology for water splitting as it has been 7 explored for many years [45]. Three different paths can be followed to produce H2 via water electrolysis: alkaline electrolyser (AE), proton exchange membrane (PEM) and solid oxide electrolysis cells (SOEC) [46]. Among them, SOEC is an efficient alternative but the development of the technology to satisfy industrial needs is still ongoing. PEM is being intensively study during the last decades, but its commercial availability is still limited, particularly for large-scale applications [47]. On the other hand, the most commercialised one is AE [48]. Therefore, AE was chosen as H2 source in our study. The efficiency of this type of electrolyser for H2 production is approximately 80% [49]. As recommended by suppliers and previous reports, a small scale AE of 0.6 MW was assumed in our model [29,50]. This scale was assumed to be the same for all the sizes selected as the H2 production of this scale fulfils the FA plant needs. Although the O2 obtained as by-product could be sold in the market, it was not included in the economic model since it would need a conditioning stage which is out of the scope of this work. Furthermore, some technical aspects such as the interaction between the electrolyser and the electricity grid are beyond the scope of this proof-of-concept work. The FA production stage optimized process has been previously studied [35]. Unfortunetely, the capacities previously published are quite different from the ones analysed in our proposal. Therefore, the FA production stage was techno-economically modelled in agreement with the best process presented to the date [29,35]. To the best of authors’ knowledge, no better results have been obtained in catalytic routes from transforming CO2 to FA. The process employs homogeneous catalysis to produce FA from CO2 and H2. The chemicals used as consumables are methanol, a tertiary amine and ruthenium-phosphino-based catalysts. In the process, firstly CO2 and H2 are compressed to achieve the pressure needed in the reaction stage. Both raw materials react in the presence of the mentioned catalysts, methanol and the tertiary amine. Afterwards, the mix resulting from the reaction stage is sent to a liquid-liquid separation unit where the catalysts is recovered. Then methanol is also recovered in a stripping 8 stage. The last step consists on a reactive-distillation to finally generate and purify FA. Further information of the techno-economic modelling followed for the FA production process is detaled in Appendix A. Figure 2. Schematic of biogas to biomethane and formic acid process. 2.2 Economic model The economic model developed for the profitability analysis was based on the internationally recognized Discounted Cash Flow (DCF) method. DCF method consists on the calculation of Net Present Value (NPV), Profitability Index (PI), Discounted Payback Time (DPBT) and Internal Rate of Return (IRR). Among them, the most helpful indicators are NPV and PI. The first one allows to estimate the positive – negative economic outputs of the project, whereas the second lets investors to quantify the potential value created per unit of investment. Eqs. (1) and (2) allowed us to calculated NPV and PI of our method, respectively. To this end, cash inflows (It) and cash outflows 15 Figure 5. NPV results with FA price evolution. Figure 5 depicts the evolution of NPV with FA price variation. Since the results for the reference price (650 €/t) were already unprofitable, only higher values were selected. To achieve an NPV equal to zero, FA price should be fixed at: 3135 €/t for 100 m3/h, 2292 €/t for 250 m3/h, 1939 €/t for 500 m3/h and 1767 €/t for 1000 m3/h. Even for highest capacities a high market price is needed to yield profitable values. The resulting elevated price is not achievable and not realistic in the current market conditions and therefore it seems that an increase of FA price is not a solution to balance the profitability of this lowcarbon route for FA synthesis. 1000 1500 2000 2500 3000 3500 -80000 -60000 -40000 -20000 0 20000 40000 60000 80000 100000 120000 140000 NPV (k€) FA price (€/t) 100 m3/h 250 m3/h 500 m3/h 1000 m3/h 16 Figure 6. NPV results applying feed-in tariffs subsidies. As for the effect of biomethane subsidies as feed-in tariffs, Figure 6 shows the results of the analysis performed. The trends of increasing FA prices (Figure 5) and biomethane subsidies (Figure 6) on NPV are similar. Bigger plants are more profitable than smaller plants when FA market value increases. Equivalently, smaller subsidies are required for bigger facilities to reach profitable scenarios. Considering that a reasonable value for subsidies would be 20-40 €/MW, the obtained values to make the project profitable are quite high. Indeed, only for equalizing NPV to zero, the subsidies needed are: 269.4 €/MW for 100 m3/h, 178.1 €/MW for 250 m3/h, 139.7 €/MW for 500 m3/h and 121.1 €/MW for 1000 m3/h. Therefore in this case, governmental incentives lacks of effectivity to make NPV positive and hence the technology profitable. Perhaps some strategies can be explored to favour the economic viability of the proposed green route, such as offering substantial subsidies during the first years of the plant to facilitate the technology kickoff and introduce a progressive reduction of such benefits as the plant runs. Such an approach may help to circumvent unforeseen expenses which typically happen at the 050 100 150 200 250 300 -100000 -50000 0 50000 100000 150000 NPV (k€) Subsidies (€/MW) 100 m3/h 250 m3/h 500 m3/h 1000 m3/h 17 beginning of a production plant lifespam. Despite the extra cash-input in the form of subsidies the economic feasibility of this type of plants would be questionable and very likely it would be more efficient to invest on other kind of renewable technologies. 3.3 Influence of costs reduction At this point, a discussion of the current efforts to transform our economy towards low- CO2 based economy must be addressed. As explained in the recent HE draft, climateneutral but economically competitive solutions are needed to balance the noticeable climate change through a sustainable economy path. The process herein analysed has proved to be environmentally favourable [29]. However, as evidenced in our technoecoimic assessemnt, the process does not present the necessary economical readiness to be scaled-up to real manufacturing plant size. Our results indeed suggest a warning call to the scienftic community working in this area to re-focus their efforts towards finding cheaper technical solutions for of the production of FA from CO2. To this end, we have analysed the costs breakdown obtained in the profitability study. Figure 7 depicts the annualized costs distribution for the four capacities considered. 18 Figure 7. Annualized costs distribution with different biogas plant sizes. As Figure 7 reveals, consumables needed in the FA production stage represenat the lion share in terms of costing for all the considered biogas plant sizes. Indeed, for 1000 m3/h consumables are more than 70% of the annualized costs. This fact is due to the very high price of the catalysts needed for the process chosen [29,35]. As can be seen in Figure 8, about 80% of the consumables costs are caused by the sum of rutheniumbased and phospino-based catalysts. Therefore, this result somewhat indicates that an important NPV improvement can be obtained by minimizing the consumable costs of the FA production process. 100 250 500 1000 0 10 20 30 40 50 60 70 80 90 100 Cost distribution (%) Biogas plant size (m3/h) Others Consumables Labour Insurance Electricity M&O Investment 19 Figure 8. Consumables costs distribution. Figure 9 reveals the results obtained for reducing the different consumables considered. A reduction of the ruthenium-based catalyst price is the most cost-effective solution for balance the high costs of the project. In some cases the NPV can be improved up to 50% (80% of cost reduction for 1000 m3/h). This result suggests that further research is needed to reduce the price of this reference catalyst or to find a competitive substitute with a more appealing market price. Even though a reduction of methanol price can be also important, it is technically difficult to replace methanol for another lower price chemical with similar characteristics. 13.03% 64.46% 6.81% 15.69% Methanol Amine Ruthenium-based catalyst Phosphino-based catalyst 20 Figure 9. NPV results evolution with consumables costs reduction. Figure 10 remarks the importance of reducing catalysts’ costs for large biogas upgrading plants. Two alternatives were studied: a parallel reduction of both catalysts and contraries-values reductions. Best scenario predicts that 80% of reduction for both catalysts could save more than 30 M€. For small scale plants, NPV is still enhanced but not as critically as in large scale plants. Therefore a potential working option would be to line-up a seires of small biogas plants (instead of developing a large biogas upgrading facility) to boost the production capacity and increase net benefits. Even for medium plants the reduction costs of the catalysts suppose a considerable NPV improvement (aroud 35% for 80% reduction of both catalysts). Again the results obtained encourage the catalysis community to find alternative systems (catalysts, reactor designs, etc.) and reaction routes for low-cost FA production from CO2. A combination of catalysts costs reduction and feed-in tariffs subsidies can be a potential solution to reach profitability in 020 40 60 80 100 -19000 -18000 -17000 -16000 -15000 -14000 -13000 020 40 60 80 100 -30000 -28000 -26000 -24000 -22000 -20000 -18000 020 40 60 80 100 -50000 -45000 -40000 -35000 -30000 -25000 020 40 60 80 100 -90000 -80000 -70000 -60000 -50000 -40000 -30000 Ruthenium-based catalyst Phosphino-based catalyst Methanol Amine NPV (k€) 100 m3/h Ruthenium-based catalyst Phosphino-based catalyst Methanol Amine Cost reduction (%) NPV (k€) 250 m3/h Ruthenium-based catalyst Phosphino-based catalyst Methanol Amine 500 m3/h Cost reduction (%) NPV (k€) Cost reduction (%) Ruthenium-based catalyst Phosphino-based catalyst Methanol Amine 1000 m3/h NPV (k€) Cost reduction (%) 21 the project proposed. If a 80-80% reduction is assumed, the NPV is equal to zero for the following values of feed-in tariffs subsidies: 204.3 €/MW for 100 m3/h, 113.1 €/MW for 250 m3/h, 74.7 €/MW for 500 m3/h and 56.1 €/MW for 1000 m3/h. Despite the values are still high, the lower subsidies could be achievable in a near future assuming a positive actitude of governments to make some efforts and promote biomethane production and CO2 utilization. Figure 10. NPV results evolution with consumables catalysts costs reduction. Another interesting conclusion that can be extracted from Figure 7 is the importance of investment for small scale plants. Thus, small scale plants profitability may be favoured by subsidies as percentage investment. To analyse if a reduction of the overall investment costs can slightly balance the profitability of our approach, the effect of biomethane subsidies as investment percentage was studied. Figure 11 shows that this kind of subsidies boost the NPV results of small scale plants. Indeed, for 100 m3/h biogas upgrading plants an improvement of 47% of the NPV value is obtained for 80% of investment subsidies. In those cases in which governments clearly bet for this kind of renewable energy, subsidies could reach the 100% of the investment. This measure 20-20 40-40 60-60 80-80 -70000 -60000 -50000 -40000 -30000 -20000 -10000 20-80 40-60 60-40 80-20 Cost reduction Ruthenium - Phosphino based catalysts (%) NPV (k€) 100 m3/h 250 m3/h 500 m3/h 1000 m3/h 22 could encourage investments from small companies considering a low-capital cost, low risk-high gain scenario. Under these extreme circustances, the NPV of the small scale plants would be significantly improved in a 59% for 100 m3/h and 42% for 250 m3/h. Figure 11. NPV results applying percentage of investment subsidies. Electricity is another important cost as reflected in Figure 7. Even if it is subjected to variability, the data chosen (0.13 €/kWh) reflects the average price for industrial users during 2019 in Spain (similar rates and/trends applied across the EU countries) [56]. Decreasing electricity cost to the half price implies a 32% NPV improvement, but this is hardly achievable. Indeed, electricity price for industrial users showcased frequent ups and downs during the last decades, but always with ±15% difference range. A realistic possibility for electricity cost reduction is diminishing the electricity cost of the H2 production stage. This could be possible in the coming years due to either the further development of renewable energies or the subsidies for renewable H2 production from governments. For this very reason, Figure 12 analyses the potential impact of electricity price for H2 production on NPV. As shown, even at the lowest electricity prices the NPV 020 40 60 80 100 -80000 -70000 -60000 -50000 -40000 -30000 -20000 -10000 0 10000 20000 Subsidies (% of investment) 100 m3/h 250 m3/h 500 m3/h 1000 m3/h NPV (k€) 23 enhancement is not remarkable. This fact, along with the results previously presented, suggests that the biggest efforts should be focus on reducing catalyst costs, which play a key role in the FA production. Figure 12. Impact of electricity price for H2 production on NPV results for 1000 m3/h plant. 4. Conclusions Our work thouroughly analyses the technoeconomic viability of a highly desired green route for fuels and chemical production – biogas conversion to formic acid and biomethane. This is indeed an appealing waste to fuels/chemicals strategy broadly studied within the biomass and catalysis communities. Unfortunatly the technoeconomic analysis evidences that this route is economically unfeasible with the current product market values and the available catalytic technologies. The baseline scenario forecasted negative profitability results for all the biogas plant sizes analysed. Furthermore the negative results cannot be inverted by improving some -90000 -80000 -70000 -60000 -50000 -40000 -30000 -20000 -10000 0 0.14 0.12 0.10 0.08 0.06 0.04 0.02 Electricity price for H2 production (€/kWh) NPV (k€) NPV for 0.13 €/kWh 24 key factors such as maintenance and overhead or electricity consumption. An improvement of the revenues was examined by two different alternatives: an increase of formic acid price or feed-in tariffs subsidies for biomethane injection to the natural gas grid. To achieve a net present value equal to zero, formic acid prices range from 1767 €/t (1000 m3/h) to 3135 €/t (100 m3/h), which is at least three times the current market value. Regarding biomethane subsidies as feed-in tariffs, values much higher than reasonable values are needed (from 121.1 to 269.4 €/MW). A cost analysis was also performed. The costs distribution revealed that consumables are a considerable percentage of the total cash needed to run a biogas plant for formic acid and biomethane production. This fact is mainly caused by the high cost of ruthenium-based and phosphino-based catalysts which are considered state of the art materials for this process. The performed analyses showed that net present value can be improved almost 50% if a cost reduction of 80% is achieved in both catalysts. Governmental incentives through percentage of investment were also studied because of their impact in small scale plants. Promising results were obtained since a net present value improvement of 47% can be achieved for 100 m3/h biogas upgrading if 80% of the investment is covered by the subsidies. In fact, we see great opportunities for small-scale biogas plants and certainly it seems much more profitable to run small plants in series than a large-scale facility. The positive chances for small-scale plants may open a new paradigma on waste treatment in rural areas which are delocalised waste producers. Herein biogas could play a significant role as green energy platform. Overall, this study showcases the enourmous challenge we are facing nowadays in terms of developing an ecominically viable circular economy. Obviously, the conversion of CO2 and biogas to added-value chemicals such as formic acid represents a way-to- go in terms of emissions reduction and transition towards a low-carbon society. Nevertheless, the technoeconomic assessment of this route indicates its unfeasibility. Reduction in consumables costs needed to run the production plants seems to be the 31 Renewable Power-to-Gas: A technological and economic review. Renew Energy 2016. doi:10.1016/j.renene.2015.07.066. 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