1. Introduction
The International Energy Agency (IEA) estimates a global expansion in the population of 21% by 2050, which brings a consequent increase in energy demand and waste production. Currently, around 80% of the energy demand is met by employing fossil fuels, which carry complications in terms of limited resources and emission of greenhouse gases [
1]. Both aspects have brought international panels to push towards more sustainable energy sources [
2]. International policies have been developed with the aim of reducing greenhouse gas (GHG) emissions by 85–90% by 2050, compared to 1990 [
3], as well as pushing for energy supply independence, with projects like “REpower EU” [
4]. The development of low-emission technologies is a crucial focus across many sectors. However, with the chemical and energy industries contributing nearly 80% of global CO
2 emissions (35 billion tons in 2019 [
5]), there is a significant emphasis on advancing process technologies.
The application of renewable energy sources and alternative feedstocks for thermochemical conversion methods have emerged [
6], along with studies on the role of biogas for the production of renewable hydrocarbons [
7]. Biogas produced from organic waste, either from anaerobic digestion or landfills by the biological degradation of organic compounds, is a stream rich in methane and carbon dioxide. Given the number of processes directly sustained by natural gas, the potential of biogas can be exploited in various applications.
Table 1 shows the dependency of biogas composition from waste sources. From 2018 to 2022, biogas production in Europe has increased by 18%, and in Italy, France, the UK, and Denmark, the production has doubled within this time span [
8]. In particular, Italy is one of the EU leading countries in the sector, counting around 1600 biogas plants, with an average capacity of 752 kW [
9]. Most of them are devoted to electricity and heat production through internal combustion engines. Italy. with the Budget Act of 2008, introduced an all-inclusive tariff for all biogas production plants in the 1 kW to 1 MW power production range for grid injection, with a 15-year guarantee [
10]. Due to this, most of the diffused plants on Italian ground are designed to produce 1 MW of electrical power by using combined heat and power (CHP) technologies with partial heat recovery to sustain the digester energy demand and efficiencies in the range of 35–40% [
11,
12]. Alternative routes are available for the biogas valorization, in particular its upgrade to biomethane for injection in the natural gas grid, for use as transportation fuel either as compressed biomethane (CBM) or liquefied biomethane (LBM), and as raw material for chemicals production [
13,
14]. Marchese et al. introduced an energy performance for power-to-liquid applications [
15], integrating carbon capture technologies within the biogas sector, while Kumar et al. brought a focus on biogas for hydrogen production, with previsions upon larger-scale production processes [
16]. Zhao et al. also provided a wide review of all publications on biogas to hydrogen and syngas, showing the potential in transitioning from natural gas to biogas-based plants [
17]. This approach is of great interest in the process industry field.
In the current work, the focus is on methanol production from biogas-produced syngas. The reforming of methane is currently the most widespread method for hydrogen and syngas production, covering 48% of the global demand [
18,
19]. The main downsides of this process are the high CO
2 emissions, in the order of 9.4–11.4 kg/kg H
2 without carbon capture and storage (CCS) systems [
20], and the heat loss in the flue gases [
21]. To mitigate such aspects, literature studies have emerged on the application of renewable energies to reforming technologies. Song et al. compared the performance of an electric evaporator system and a high-temperature heat pump to conventional steam methane reforming (SMR), proving their higher energetic efficiency [
2]. Further studies investigated the economics of electrified methane reformers, obtaining higher production costs than standard SMR. Nonetheless, if contextualized in countries with low prices for renewable energy such as Norway and the Netherlands, the process can be considered competitive with the standard industrial route [
22].
The possibility of transitioning to electrified biogas reforming plants has also emerged in recent years. Maporti et al. obtained the consumption of 1.25 kWh of renewable energy per 1 Nm
3 of hydrogen produced [
23]. Moreover, another study proved an energy efficiency of 80% for a pilot plant with an estimated of only 1 kWh consumption per 1 Nm
3/h of hydrogen produced [
24].
Table 1.
Biogas composition according to various sources.
Table 1.
Biogas composition according to various sources.
Biogas Source | CH4 (vol%) | CO2 (vol%) | N2 (vol%) | O2 (vol%) | H2S (ppm) | Other | Ref. |
---|
Agricultural Waste | 75–45 | 25–55 | 0–25 | 0.01–5 | <01 | - | [25] |
Landfill Waste | 40–60 | 20–40 | 2–20 | <1 | 40–400 | CnH2n+2 | [26] |
Cow Manuring | 55 | 39 | 5 | 0.9 | 400–1000 | NH3 | [27] |
Sludge | 50–69 | 24–45 | 0–9 | 0–3 | 0–855 | Silicon | [28] |
The electrification of industrial processes has emerged as a strong route for lower impacts on emissions. In this matter, promising technologies are electrolyzers, assuming that renewable energy sources are available. Power-to-X (PTX) follows the concept of chemical production with green hydrogen as an intermediate [
29]. Green hydrogen is of great interest when combined with carbon capture technologies, in particular carbon capture and utilization (CCU). CCU technologies allow the capture of CO
2 by transforming it into several valuable products (olefins, formic acid, dimethylether (DME), urea, acetic acid, methanol, and syngas) [
30]. Given the availability of green hydrogen, the hydrogenation of CO
2 by reverse water–gas shift (RWGS) is one of the major approaches for the mitigation of GHG emissions (CAMERE process [
31]). This process has been proposed and investigated by multiple works, proving its viability for methanol and syngas production [
30,
32,
33].
Multiple studies have emerged on the application of biogas for methanol synthesis, going through a total upgrading to biomethane to be sent to the reforming unit [
34,
35,
36,
37]. Methanol plays a pivotal role in the achievement of net-zero targets, since it is a valuable bioenergy carrier for transportation fuel production and is a precursor of many fundamental chemical products [
38]. With the provisions of national incentives and higher pressure on decarbonization, biomethanol production has also started to emerge on the market, with an estimated growth at a compound annual growth rate (CAGR) of around 25% from 2024 to 2030 [
39].
In the present work, a feasibility study has been carried out for an innovative autothermal outer electrification of the biogas reforming process. The alternative layout introduces an RWGS reactor for carbon sequestration, a high-temperature electrolyzer for hydrogen and oxygen production, an oxy-steam biogas combustion chamber and an energy recovery system to ensure thermal auto-sufficiency and only electrical demand to the system. The concept of reforming is twisted in the scheme proposed, as there are still steam and biogas present as feedstock and a syngas-rich stream as a product, but no reforming reaction takes place. The work aims to prove the comparability of the alternative reforming layout to the standard process in optimal conditions for methanol production, supporting the obtained results with available literature data and a particular focus on overall energy consumption and process emissions.
3. Results and Discussion
3.1. Mass Balance
Results for the simulated cases are reported, respectively, in
Table 3 and
Table 4. The flowrate of biogas is 500 Nm
3/h for both configurations, free from contaminants as assumed collected after necessary purification steps.
In Case A, almost 30% of the feedstock has to be invested as fuel in the furnace while the remaining part undergoes partial removal of CO2, finding an optimal composition of 78% of CH4 and 22% of carbon dioxide before the reforming reactor. These conditions strongly depend on the water circulated in the PSWA, which at 15 bar, results in 322 lt/h pumped for a total removal of 143 kg/h of CO2. The carbon dioxide treatment for possible commercialization is not considered in the study, but the stream is assumed to be either implemented within other processes or stocked. Air is compressed by a blower and fed in excess to stoichiometric conditions; it is mixed with fuel and preheated before entering the furnace. Flue gases from the furnace are cooled below 200 °C with 8 mol% oxygen content, after heat recovery in the convective zone of the furnace. On the reactive side of the reformer, the SC ratio is close to 3 and the syngas produced has a tenor of hydrogen of 69.18 mol%. The configuration allows for a yearly methanol production of 2.7 ktons.
The second configuration results are reported in
Table 4 (Case B) allows using the integrity of biogas in the OSC unit, with a full conversion of the methane fraction to CO
2 and water. After condensation, the stream is sent to a compressor to reach the selected pressure of 10 bar, as required by the RWGS. To reach the syngas SN value of 2 at the outlet of the RWGS, 156.8 kg/h of hydrogen are necessary from the SOEC at 10 bar. Along with hydrogen production, the electrolyzer provides a stream of oxygen, of which almost 82% is employed in the OSC chamber, while 207.7 kg/h can be stocked and sold as a product or implied within close process facilities. The syngas produced in the RWGS, SG1, is sent to the methanol synthesis. The product stream undergoes purification, producing almost 6 ktons per year of methanol. This process requires three condensation steps for water separation which, after undergoing degassing and being integrated by a make-up stream, is used as a source for the steam demanded by the OSC and SOEC.
3.2. Energy Balance
The overall electric consumptions are reported in
Table 5 for the two simulated configurations. The standard industrial technology, due to the thermal nature of the process, can sustain the endothermic reforming reaction through the heat released in the furnace. For Case B, the RWGS endothermic reaction is sustained by the OSC unit, but the necessary oxygen to meet total combustion of the fuels, and the hydrogen to reach the required SN value, is provided by the electricity provided to the SOEC. The main source of consumption in Case B is given by the electrolyzer, which counts for 95% of the overall consumption. As expected, in Case B the syngas compressors require higher consumption due to the higher flowrates of gas treated. For better comprehension of the energy integration systems, thermal loads across the processes were analyzed with the Aspen Energy Analyzer. As reported in
Figure 6, both systems show a demand for cooling utilities. The hot zone of the processes can sustain steam generation, with additional heat to spare, for example, to be recovered for the anaerobic digestor heating. The total cooling utility demand for Case A is of 0.58 MW of cooling, while in Case B 3.7 MW. The big difference is associated with the different condensation steps required, the first case requires the condensation of water after the SMR only, while the second one, must remove water after the OSC, the RWGS, and SOEC. In
Table 6 it can be observed the different demand of cooling content for the two cases. The hot region available for Case B is due to the high operating temperatures of the three main reacting units of the systems. Due to the absence of nitrogen, the OSC allows for high temperatures in the combustion chamber, as in common combustion systems. The necessity to condense water before entering the RWGS, operating at 850 °C, introduces a high-temperature jump, which allows recovering heat for steam, but with a strong demand on cooling utility. The choice of a high-temperature electrolyzer has been taken due to the nature of the process, a SOEC allows to lower the electricity demand by recovering more heat in the steam fed to the unit.
3.3. Key Performance Indicators
The key performance indicators are summarized in
Table 7 for the four cases under study. Results are normalized to provide a proper comparison, given that the studies found in the literature operated on different biogas-size plants. Case A and Case C are directly compared to evaluate the uncommon smaller-scale plant results. The two process configurations differ only in the CO
2 separation method, the one considered for this study opted for a partial upgrading through water absorption, rather than total separation with amine, as in Case C. Case D has been included to better understand results from Case B, especially in energetic consumption terms. Both scenarios provide electrification of the RWGS reactor, Case B supports the endothermicity of the reactor with the OSC, while Case D directly employs electrical energy. Also in this comparison, the similarities between the results are noticeable.
The two opposing technologies differ strongly in methanol global yield; this directly depends on the necessity of the SMR processes to invest some of the feedstock as fuel, while in the electrified process (Case B), the integrity of the feedstock is interested in the reaction and the CO2-rich stream is integrated with H2 to produce valuable syngas. Furthermore, methane conversion is total in Case B since the OSC consumes it integrally through the oxygen from the SOEC. Methanol reactor yield strongly depends on the operating conditions of the synthesis, in particular, the SN ratio highly impacts it.
This study’s results are similar (Case A 93.76% 0 Case B 93.80%) due to the boundary conditions of an SN value equal to 2.05 at the inlet of the methanol reactor. Carbon dioxide directly emitted, in Case B, is below unity while in Case A SMR is heated by the combustion of biogas and carbon dioxide-rich flue gas is introduced into the atmosphere. Sources of carbon differ strongly in the two cases, Case B has only one voice of emission, which is the carbon dioxide content in the synthesis purge gas, while Case A has both the CO2 separated by the PSWA and the content in the flue gas.
Global carbon efficiency is quite lower for SMR processes due to the amount of carbon used in the combustion rather than its availability to the synthesis, Case D has lower values since it invests biogas in biomethane production and only the remaining carbon dioxide in the methanol synthesis. Some further considerations have been carried out to visualize the carbon intensity of the process better. Reported in
Figure 7 is the relationship between the carbon intensity and the amount of CO
2 emitted in the methanol production. If electrical energy had no emission intensity, this process would be entirely carbon negative, since the CO
2 emitted compared to the amount fed, over kg of MeOH produced, is around −507 gCO
2/kgMeOH. Carbon neutrality is met at 75 gCO
2/kWh; therefore, the impact of the system strongly depends on the carbon intensity of the country and energy source. In Europe, France and Sweden have a low impact due to nuclear and renewable power. In these countries, Case B would have a competitively low GHG impact, while in Italy, for example, the system would highly benefit from the introduction of renewable electricity sources. This suggests the necessity of combining electrified industrial processes with renewables.
The process efficiency is a relevant indicator of the system’s energy efficiency. The electrified processes require a large amount of electric energy, SMR ones show an efficiency of 63–64% exploiting methane calorific value. It is interesting to notice how Case B presents 49% efficiency compared to Case D’s 24% efficiency. The introduction of the OSC allows for a lower energy demand from the electrolyzer, consequently, a higher energetical efficiency is recovered.
The total carbon potential underlines the biggest advantage in the electrified processes, the amount of captured CO2 is in the order of 90% for the global balance. SMR technologies present a negative value due to the upgrading step of biogas, the amount of carbon dioxide removed strongly impacts on the total direct emissions, as well as the exhaust percentage derived by burning off-gases in the system.
Lastly, the energy consumption is given; for the SMR technologies, the main contribution is given by the gas compressors, 0.35 kWh/kg of MeOH for Case A and 0.49 kWh/kg of MeOH for Case C, while for the electrified processes, the electrolyzer is the major source. Case B, using a SOEC working at high temperatures, consumes 6.6 kWh/kg of MeOH, and Case D, exploiting a PEM electrolyzer at lower temperatures, 10.6 kWh/kg of MeOH. This result favors the use of a high-temperature electrolyzer for a lower energy consumption if the system has available heat.