Techno-economical evaluations of decarbonized hydrogen production based on direct biogas conversion using thermo-chemical looping cycles

Hydrogen production by biogas conversion represent a promising solution for reduction of fossil CO₂ emissions. In this work, a detailed techno-economic analysis was performed for decarbonized hydrogen production based on biogas conversion using calcium and chemical looping cycles. All evaluated concepts generate 100,000 Nm³/h high purity hydrogen. As reference cases, the biogas steam reforming design without decarbonization and with CO₂ capture by gas-liquid chemical absorption were also considered. The results show that iron-based chemical looping design has higher energy efficiency compared with the gas-liquid absorption case by 2.3 net percentage points as well as a superior carbon capture rate (99% vs. 65%). The calcium looping case shows a lower efficiency than chemical scrubbing, with about 2.5 net percentage points, but the carbon capture rate is higher (95% vs. 65%). The hydrogen production cost increases with decarbonization, the calcium looping shows the most favourable situation (37.14 €/MWh) compared to the non-capture steam reforming case (33 €/MWh) and MDEA and iron looping cases (about 42 €/MWh). The calcium looping case has the lowest CO₂ avoidance cost (10 €/t) followed by iron looping (20 €/t) and MDEA (31 €/t) cases.     

The value of flexible fuel mixing in hydrogen-fueled gas turbines – A techno-economic study

In electricity systems mainly supplied with variable renewable electricity (VRE), the variable generation must be balanced. Hydrogen as an energy carrier, combined with storage, has the ability to shift electricity generation in time and thereby support the electricity system. The aim of this work is to analyze the competitiveness of hydrogen-fueled gas turbines, including both open and combined cycles, with flexible fuel mixing of hydrogen and biomethane in zero-carbon emissions electricity systems. The work applies a techno-economic optimization model to future European electricity systems with high shares of VRE.The results show that the most competitive gas turbine option is a combined cycle configuration that is capable of handling up to 100% hydrogen, fed with various mixtures of hydrogen and biomethane. The results also indicate that the endogenously calculated hydrogen cost rarely exceeds 5 €/kg_H2 when used in gas turbines, and that a hydrogen cost of 3–4 €/kg_H2 is, for most of the scenarios investigated, competitive. Furthermore, the results show that hydrogen gas turbines are more competitive in wind-based energy systems, as compared to solar-based systems, in that the fluctuations of the electricity generation in the former are fewer, more irregular and of longer duration. Thus, it is the characteristics of an energy system, and not necessarily the cost of hydrogen, that determine the competitiveness of hydrogen gas turbines.     

Techno-economic assessment of a synthetic fuel production facility by hydrogenation of CO2 captured from biogas

In this study, a thermodynamic and economic analysis of a synthetic fuel production facility by utilizing the hydrogenation of CO₂ captured from biogas is carried out. It is aimed to produce methanol, a synthetic fuel by hydrogenation of carbon dioxide. A PEM electrolyzer driven by grid-tie solar PV modules is used to supply the hydrogen need of methanol. The CO₂ is captured from biogas produced in an actual wastewater treatment plant by a water washing unit which is a method of biogas purification. The required power which is generated by PV panels, in order to produce methanol, is found to be 2923 kW. Herein, the electricity consumption of 2875 kW, which is the main part of the total electricity generation, belongs to the PEM system. As a result of the study, the daily methanol production is found to be as 1674 kg. The electricity, hydrogen and methanol production costs are found to be $ 0.043 kWh^?1, $ 3.156 kg^?1, and $ 0.693 kg^?1, respectively. Solar availability, methanol yield from the reactor, and PEM overpotentials are significant factors effecting the product cost. The results of the study presents feasible methanol production costs with reasonable investment requirements. Moreover, the efficiency of the cogeneration plant could be increased via enriching the biogas while emissions are reduced.     

A pioneering study of biomethane and hydrogen production from the wine industry in Brazil: Pollutant emissions,electricity generation and urban bus fleet supply

The thematic area studied in this paper considers environmental issues such as atmospheric pollution from the combustion of fossil fuels, and the environmental impacts from the generation of urban agricultural solid wastes. This study has estimated the potential for hydrogen and biogas production from solid urban waste (SUW) and wine waste from Bento Gonçalves, which is a region in Brazil with the largest wine throughput and subsequent waste generation, thus providing a potential high-energy feedstock. The resulting hydrogen and biogas are assumed to displace the existing fuels in the local bus fleet. The analytical work consisted of three scenarios - scenario 1: production of biogas using SUW, sourced exclusively from the municipality of Bento Gonçalves; Scenario 2: the possibility to supply SUW from Bento Gonçalves and surrounding cities, to produce biogas; Scenario 3: the possibility to use wine waste and SUW for biogas production. Scenario 3 showed the greatest energy yield with 37.9 Gg of biomethane produced per year, which can supply the entire public bus fleet of Bento Gonçalves. The resulting hydrogen production potential using steam reforming of biomethane is 1.09 E+08 Nm³H₂.d^?1 which can generate 2.62 TW h.year^?1 of electrical energy, avoiding approximate emissions of 355 ktonCO₂.year^?1. These findings indicate value in the production of biogas from urban and agricultural wastes, especially for the generation of methane, hydrogen and useful energy outputs. Its production from renewable and clean sources contributes to the gradual transformation of an economy currently dependent on non-renewable resources into a circular and renewable economy.     

Techno-economic analysis of processes with integration of fluidized bed heat exchangers for H2 production – Part 2: Chemical-looping combustion

This work covers a techno-economic assessment for processes with inherent CO₂ separation, where a fluidized bed heat exchanger (FBHE) is used as heat source for steam reforming in a hydrogen production plant. This article builds upon the work presented in Part 1 of this study by Stenberg et al. [1], where a process excluding CO₂ capture was examined. Part 2 suggests two process configurations integrating steam reforming with a chemical-looping combustion (CLC) system, thus providing inherent CO₂ capture. The first system (case CM) uses natural gas as supplementary fuel whereas the second system (case CB) uses solid biomass, which enables net negative CO₂ emissions. In both systems, the reformer tubes are immersed in a bubbling fluidized bed where heat for steam reforming is efficiently transferred to the tubes. The processes include CO₂ compression for pipeline transportation, but excludes transport and storage. The CLC system is designed based on key parameters, such as the oxygen carrier circulation rate and oxygen transport capacity. The first system displays a process with net zero emissions and a hydrogen production efficiency which is estimated to 76.2%, which is almost 8% higher than the conventional process. The levelized production cost is 1.6% lower at below 2.6 €/kg H₂. The second system shows the possibility to reduce the emissions to ?34.1 g CO₂/MJ_H2 compared to the conventional plant which emits 80.7 g CO₂/MJ_H2. The hydrogen production efficiency is above 72% and around 2% higher than the conventional process. The capital investments are higher in this plant and the levelized hydrogen production cost is estimated to around 2.67 €/kg. The cost of CO₂ avoidance, based on a reference SMR plant with CO₂ capture, is low for both cases (?4.3 €/ton_CO2 for case CM and 2.7 €/ton_CO2 for case CB).     

Bark as feedstock for dual fluidized bed gasifiers—Operability,efficiency, and economics

The demand for biofuels and biochemicals is expected to increase in the future, which will in turn increase the demand for biomass feedstock. Large gasification plants fueled with biomass feedstock are likely to be a key enabling technology in a resource‐efficient, bio‐based economy. Furthermore, the costs for producing biofuels and biochemicals in such plants could potentially be decreased by utilizing inexpensive low‐grade residual biomass as feedstock. This study investigates the usage of shredded tree bark as a feedstock for the production of biomethane in the GoBiGas demonstration plant in Gothenburg, Sweden, based on a 32 MW_th industrial dual fluidized bed gasification unit. The plant was operated with bark feedstock for 12 000 hours during the period 2014 to 2018. Data from the measurement campaign were processed using a stochastic approach to establish the plant's mass and energy balances, which were then compared with operation of the plant with wood pellets. For this comparison, an extrapolation algorithm was developed to predict plant performance using bark dried to the same moisture content as wood pellets, ie, 8%_w.b. Plant operation with bark feedstock was evaluated for operability, efficiency, and feedstock‐related cost. The gas quality achieved during the test period was similar to that obtained for operation with wood pellets. Furthermore, no significant ash sintering or agglomeration problems were observed more than 750 hours of operation. The calculated biomass‐to‐biomethane efficiency is 43% to 47% (lower heating value basis) for operation with wet bark. However, the predicted biomass‐to‐biomethane efficiency can be increased to 55%–65% for operation with bark feedstock dried to 8% moisture content, with corresponding feedstock costs in the range of 24.2 to 32.7 EUR/MWh; ie, a cost reduction of about 40% compared with wood pellets.     

Assessment of membrane plants for biogas upgrading to biomethane at zero methane emission

In the future energy infrastructure there is a considerable potential for biogas and, in particular, for biomethane as a natural gas substitute. Among the alternatives of upgrading biogas to biomethane, this work focuses on membrane permeation. Taking cellulose acetate as membrane material and spiral-wound as membrane configuration, five layouts are assessed. All layouts have the same biogas plant rated at 500 m³/h (STP), yet they may adopt: (i) one- or two-stage permeation, (ii) permeate or residue recycle, and (iii) a water heater or a prime mover (internal combustion engine or a micro gas turbine) to exploit residues as fuel gas. Since residues are consumed, all layouts have zero emission of methane into the atmosphere. The membrane material is modeled considering the phenomenon of plasticization; the membrane modules are described by a crossflow permeation patterns without pressure drops. The results indicates that specific membrane areas range from 1.1 to 2.4 m²h/m³ (STP), specific energy from 0.33 to 0.47 kWh/m³ (STP), and exergy efficiencies from 57.6% to 88.9%. The splitting of permeation over two stages and the adoption of water heater instead of prime movers is a convenient option. The preferred layout employs a single compressor, a two-stage membrane permeation at 26 bar, a water heater fueled by the first-stage permeate, and a second-stage permeate recycle. Assuming a biomethane incentive of 80 €/MWh_LHV and a project life of 15 years, the total investment of this plant is 2.9 M€, the payback time 5 years and the net present value 3.5 M€.     

Purified biohythane (biohydrogen+biomethane) production from food waste using CaO2+CaCO3 and NaOH as additives

The current work focuses on biohythane (biohydrogen + biomethane) production from waste biomass by utilising CaO₂+CaCO₃ and NaOH as additives and purification in a novel purification and mixing column with water and NaOH scrubbing. The production process indicates an enhanced hydrogen content of 33.85% with CaO₂+CaCO₃ as an additive from the fermentative reactor. The methanogenic reactor produces an improved methane content of 67.24% by utilising NaOH as the alkali reagent. During purification, NaOH scrubbing results in the highest purification of 87.43% hydrogen and 91.27% methane. In contrast, the water scrubbing system produces a maximum purity of 76.18 and 82.36%, respectively. Further, the variation of gas flow rate illustrates improved biohydrogen and biomethane purity up to 97.85 and 98.39%, with a gas flow rate of 0.12 m³ h^?1. While producing biohythane, a gas flow rate of 0.12 m³ h^?1 produces the optimum concentration of hydrogen and methane at 31.08 and 66.17%, respectively.     

Farm-scale bio-power-to-methane: Comparative analyses of economic and environmental feasibility

Power-to-gas technologies are considered to be part of the future energy system, but their viability and applicability need to be assessed. Therefore, models for the viability of farm-scale bio-power-to-methane supply chains to produce green gas were analysed in terms of levelised cost of energy, energy efficiency and saving of greenhouse gas emission. In bio-power-to-methane, hydrogen from electrolysis driven by surplus renewable electricity and carbon dioxide from biogas are converted to methane by microbes in an ex situ trickle-bed reactor. Such bio-methanation could replace the current upgrading of biogas to green gas with membrane technology. Four scenarios were compared: a reference scenario without bio-methanation (A), bio-methanation (B), bio-methanation combined with membrane upgrading (C) and the latter with use of renewable energy only (all-green; D). The reference scenario (A) has the lowest costs for green gas production, but the bio-methanation scenarios (B-D) have higher energy efficiencies and environmental benefits. The higher costs of the bio-methanation scenarios are largely due to electrolysis, whereas the environmental benefits are due to the use of renewable electricity. Only the all-green scenario (D) meets the 2026 EU goal of 80% reduction of greenhouse gas emissions, but it would require a CO₂ price of 200 € t⁻¹ to achieve the levelised cost of energy of 65 €ct Nm⁻³ of the reference scenario. Inclusion of the intermittency of renewable energy in the scenarios substantially increases the costs. Further greening of the bio-methanation supply chain and how intermittency is best taken into account need further investigation.     

The fixed dome digester: An appropriate design for the context of Sub-Sahara Africa?

The fixed dome digester design is the most deployed small scale biogas technology in sub-Sahara Africa (SSA). This design is deployed on mono-feedstock-wet anaerobic digestion (WAD) principle. Little or nothing has been reported in the literature on the sustainability in terms of the actual field operation and performance of this design within the SSA context. This study aims at bridging this gap and bringing additional insights to the scientific literature by investigating the sustainability of the Nepali–type fixed dome digester within the context of rural Cameroon. The investigations were evaluated in terms of operating parameters, biogas production, production rate and productivity of the digester. In addition the local investment cost of the design was analyzed. The design was operated on multiple-locally-available feedstock mixed with water at an average of 3:1 ratio resulting in a higher than design TS of 16%. The design, thus was operated towards the dry anaerobic digestion principle, highlighting insufficient mono-feedstock and water scarcity for a sustainable operation of the design within the context of rural SSA. The average biogas production was 1.2 m³_biogas/day, giving average volumetric production rate of 0.16 m³_biogas/m³_digester day⁻¹ and yields of 0.18 m³_biogas/kg VS respectively. This low performance compared with the potential mesophilic biogas production rate of 0.27 m³_biogas/m³_digester day⁻¹ could be linked to insufficient mixing of digester content and low operating temperatures. Gas storage facility (dome), skilled labour and cement made significant contributions to the investment cost of the digester. The Levelized cost of Energy from the digester was less than 1 € cents/MJ.     

Techno-economic feasibility assessment of sorption enhanced gasification of municipal solid waste for hydrogen production

Waste-to-fuel coupled with carbon capture and storage is forecasted to be an effective way to mitigate the greenhouse gas emissions, reduce the waste sent to landfill and, simultaneously, reduce the dependence of fossil fuels. This study evaluated the techno-economic feasibility of sorption enhanced gasification, which involves in-situ CO₂ capture, and benchmarked it with the conventional steam gasification of municipal solid waste for H₂ production. The impact of a gate fee and tax levied on the fossil CO₂ emissions in economic feasibility was assessed. The results showed that the hydrogen production was enhanced in sorption enhanced gasification, that achieved an optimum H₂ production efficiency of 48.7% (T = 650 °C and SBR = 1.8). This was 1.0% points higher than that of the conventional steam gasification (T = 900 °C and SBR = 1.2). However, the total efficiency, which accounts for H₂ production and net power output, for sorption enhanced gasification was estimated to be 49.3% (T = 650 °C and SBR = 1.8). This was 4.4% points lower than the figure estimated for the conventional gasification (T = 900 °C and SBR = 1.2). The economic performance assessment showed that the sorption enhanced gasification will result in a significantly higher levelised cost of hydrogen (5.0 €/kg) compared to that estimated for conventional steam gasification (2.7 €/kg). The levelised cost of hydrogen can be reduced to 4.5 €/kg on an introduction of the gate fee of 40.0 €/t_MSW. The cost of CO₂ avoided was estimated to be 114.9 €/tCO₂ (no gate fee and tax levied). However, this value can be reduced to 90.1 €/tCO₂ with the introduction of an emission allowance price of 39.6 €/tCO₂. Despite better environmental performance, the capital cost of sorption enhanced gasification needs to be reduced for this technology to become competitive with mature gasification technologies.     

Biogas upgrading using ionic liquid [Bmim][PF6] followed by thermal-plasma-assisted renewable hydrogen and solid carbon production

The use of hydrogen as clean energy has attracted significant attention because conventional industrial hydrogen production processes show negative environmental impact, require intensive energy, and/or are dependent on natural gas. The main objective of this study is to develop an innovative and environment-friendly hydrogen production process utilizing biogas as an alternative to natural gas. Ionic liquid [Bmim][PF₆] shows high potential for the replacement of aqueous amine solutions for CO₂ absorption and are employed for biogas upgrading, while thermal plasma (TP), which is beneficial for converting electrical energy to chemical energy, is employed for the simultaneous production of clean “turquoise” hydrogen and solid carbon. In addition, an intercooler is used to improve CO₂ removal in the absorber. Heat and power integration are employed to enhance the performance of the upgrading process and thermal-plasma-assisted hydrogen production. All simulations were conducted using Aspen Plus V10.0 software. The simulated results show that the solid carbon production from biomethane increases compared to that in the proposed base case. The savings in both the heater used to preheat the TP reactor and the third flash drum are 100%, while the saving in power consumption in the compression section is 62.0%. Furthermore, sensitivity is investigated to determine the effect of biomethane composition on the performance of the proposed configuration.     

Performance of semi-continuous fixed-bed digester for thalassic biogas production of the brown seaweed,Ecklonia spp.

Ecklonia spp. is available during summer (June–September), making it a possible rotational brown seaweed feedstock for biogas production. Hence, biogas production of Ecklonia was tested in a pilot-scale (120 L volume) semi-continuous fixed-bed digester under thalassic (high salinity) condition – seeded with marine bacteria. The biogasification efficiency obtained for Ecklonia in terms of its theoretical methane yield (345.6 mL CH₄/g VS) was 68.5%. This is higher than obtained in a batch digester (5.8%). The successful thalassic biogas production of Ecklonia may help secure the continuous operation and lower the biogas operation cost by directly using seawater as liquid substrate.     

Evaluation of energy efficiency of various biogas production and utilization pathways

The energy efficiency of different biogas systems, including single and co-digestion of multiple feedstock, different biogas utilization pathways, and waste-stream management strategies was evaluated. The input data were derived from assessment of existing biogas systems, present knowledge on anaerobic digestion process management and technologies for biogas system operating conditions in Germany. The energy balance was evaluated as Primary Energy Input to Output (PEIO) ratio, to assess the process energy efficiency, hence, the potential sustainability. Results indicate that the PEIO correspond to 10.5–64.0% and 34.1–55.0% for single feedstock digestion and feedstock co-digestion, respectively. Energy balance was assessed to be negative for feedstock transportation distances in excess of 22 km and 425 km for cattle manure and for Municipal Solid Waste, respectively, which defines the operational limits for respective feedstock transportation. Energy input was highly influenced by the characteristics of feedstock used. For example, agricultural waste, in most part, did not require pre-treatment. Energy crop feedstock required the respect cultivation energy inputs, and processing of industrial waste streams included energy-demanding pre-treatment processes to meet stipulated hygiene standards. Energy balance depended on biogas yield, the utilization efficiency, and energy value of intended fossil fuel substitution. For example, obtained results suggests that, whereas the upgrading of biogas to biomethane for injection into natural gas network potentially increased the primary energy input for biogas utilization by up to 100%; the energy efficiency of the biogas system improved by up to 65% when natural gas was substituted instead of electricity. It was also found that, system energy efficiency could be further enhanced by 5.1–6.1% through recovery of residual biogas from enclosed digestate storage units. Overall, this study provides bases for more detailed assessment of environmental compatibility of energy efficiency pathways in biogas production and utilization, including management of spent digestate.     

What type of digester configurations should be employed to produce biomethane from grass silage?

Grass is an excellent energy crop; it may be classified as a high yielding, low energy input, perennial crop. Over 90% of Irish agricultural land is under grass; thus farmers are familiar with, and comfortable with, this crop as opposed to a “new energy crop” such as Miscanthus. Of issue therefore is not the crop, but the methodology of generating energy from the crop. Numerous farmers across Europe (in particular Germany and Austria) use grass silage as a feedstock for biogas production; in a number of cases the produced biogas is scrubbed to biomethane and used as a transport fuel or injected into the natural gas grid. Many Irish farmers are considering converting from conventional farming such as beef production to grass biomethane production. Numerous technologies and combinations of such technologies are available; from one-stage batch dry systems to two-stage wet continuous systems; from one-stage continuous wet systems to two-stage systems incorporating a batch dry reactor coupled with a second stage high-rate reactor. This paper reviews work carried out both in the scientific literature and in practice at commercial scale.     

Effects of harvest month on biochemical composition of alligator weed for biohydrogen and biomethane cogeneration：Identifying critical variations in microbial communities

To determine the optimal harvest period for alligator weed used in fermentation-based gaseous biofuel production, the effects of harvest months on the biochemical composition and fermentative hydrogen and methane co-production from alligator weed were evaluated. Compositional analysis indicates that alligator weed harvested in September was most suitable for fermentative hydrogen production because it exhibited an appropriate carbon to nitrogen molar ratio (26.75), the highest cellulose content (20.34%) and the lowest weight ratio of ash to volatiles (0.09). Biohydrogen production was significantly affected by the harvest month, peaking at 48.4 mL/g VS in September. Microbial community analysis suggests that the abundance of Clostridium sensu stricto, the dominating hydrogen producer in dark fermentation reactors, was greatly enriched with feedstock harvested in September. Moreover, the expression levels of functional genes involved in carbohydrate metabolism and microbial proliferation were highest in the reactor fed with feedstock harvested in September. During the second-stage anaerobic digestion (AD), biomethane yield mainly depended on the soluble COD content in the hydrogenogenic effluent and was highest in August (214.6 mL/g VS). A maximum total energy conversion efficiency of 44.8% was obtained in September through two-stage process combining dark fermentation and AD.     

Experimental and computational study on the enhancement of engine characteristics by hydrogen enrichment in a biogas fuelled spark ignition engine

Limitations on the upgradation of biogas to biomethane in terms of cost effectiveness and technology maturity levels for stationary power generation purpose in rural applications have redirected the research focus towards possibilities for enhancement of biogas fuel quality by blending with superior quality fuels. In this work, the effect of hydrogen enrichment on performance, combustion and emission characteristics of a single-cylinder, four-stroke, water-cooled, biogas fuelled spark-ignition engine operated at the compression ratio of 10:1 and 1500 rpm has been evaluated using experimental and computational (CFD) studies. The percentage share of hydrogen in the inducted biogas fuel mixture was increased from 0 to 30%, and engine characteristics with pure methane fuel was considered as a baseline for comparative analysis. The CFD model is developed in Converge CFD software for a better understanding on combustion phenomenon and is validated with experimental data. In addition, the percentage share of hydrogen enrichment which would serve as a compromise between biogas upgradation cost and engine characteristics is also identified. The results of study indicated an enhancement in combustion characteristics (peak in-cylinder pressure increased; COV_IMEP reduced from 9.87% to 1.66%; flame initiation and combustion durations reduced) and emission characteristics (hydrocarbon emissions reduced, and NOx emissions increased but still lower than pure methane) with increase in hydrogen share from 0 to 30% in biogas fuelled SI engine. Flame propagation speed increased and combustion duration reduced with hydrogen supplementation and the same was evident from the results of the CFD model. Performance of the engine increased with increase in hydrogen share up to 20% and further increment in hydrogen share degraded the performance, owing to heat losses and the enhancement in combustion characteristics were relatively small. Overall, it was found that 20% blending of hydrogen in the inducted biogas fuel mixture will be effective in enhancing the engine characteristics of biogas fuelled engines for stationary power generation applications and it holds a good compromise between biogas upgradation cost and engine performance.     

Techno-economic assessment of solar steam reforming of methane in a membrane reactor using molten salts as heat transfer fluid

This paper reports the results obtained in a techno-economic analysis of the Steam Methane Reforming (SMR) technology aided with solar heat, developed and demonstrated in the European FCH JU project CoMETHy: a compact membrane reformer heated with molten salt up to 550 °C allowed to simultaneously carry out methane steam reforming, water-gas-shift reaction and hydrogen separation. This reactor can be integrated with new generation Concentrating Solar Thermal (CST) systems to supply the process heat. Experimental validation of the technology has been successfully achieved in a pilot scale plant and the results recently published. In this paper, we introduce a fully-integrated scheme and operation strategies of a plant on the 1500 Nm³/h hydrogen production scale. Then, techno-economic analysis of this new solar-driven process is presented to evaluate its competitiveness. Considering a plant capacity of 1500 Nm³/h (pure hydrogen production) and today's costs for the methane feed and the CST technology, obtained Hydrogen Production Cost (HPC) are in the range of 2.8–3.3 €/kg for a “solar-hybrid” system with high capacity factor (8000 h/year operation) and 4.7 €/kg for a “solar-only” case, while HPC≅1.7 €/kg can be obtained with the conventional route under equivalent assumptions. However, a sensitivity analysis shows that the expected drop of the cost of the CST technology will bring the HPC around 2.4 €/kg for the “solar-hybrid” case and close to 3.4 €/kg for the “solar-only” case, thus making the cost of solar reforming closer to conventional SMR with CO₂ capture and with wind/solar electrolysis in the future. In the “solar-hybrid” case total CO₂ production can be reduced by 13–29% with 58–70% of produced CO₂ recovered as pure stream (at 1.3 bar); in the “solar-only” case total CO₂ production can be reduced by 52% and 100% of produced CO₂ recovered as pure stream (at 1.3 bar). However, compared to the conventional route, CO₂ avoidance costs are still relatively high (≥137 €/ton_CO2) and process optimization measures required. Therefore, optimization measures have been outlined to increase the overall process efficiency and further reduce the HPC.     

Pure hydrogen co-production by membrane technology in an IGCC power plant with carbon capture

The CO₂ capture in Integrated Gasification Combined Cycle (IGCC) plants causes a significant increase of the cost of electricity (COE) and thus determines high CO₂ mitigation cost (cost per ton of avoided CO₂ emissions). In this work the economic sustainability of the co-production of pure hydrogen in addition to the electricity production was assessed by detailed process simulations and a techno-economic analysis. To produce pure hydrogen a Water Gas Shift reactor and a Selexol^® process was combined with H₂ selective palladium membranes. This innovative process section was compared with the more conventional Pressure Swing Adsorption in order to produce amount of pure hydrogen up to 20% of the total hydrogen available in the syngas.Assuming for a base case a hydrogen selling price of 3 €/kg and a palladium membrane cost of 9200 €/m², a cost of electricity (COE) of 64 €/MWh and a mitigation cost of 20 €/ton_CO2 were obtained for 90% captured CO₂ and 10% hydrogen recovery. An increase of the hydrogen recovery up to 20% determines a reduction of the COE and of the mitigation cost to 50 €/MWh and 5 €/ton_CO2, respectively. A sensitivity analysis showed that even a 50% increase of cost of the membrane per unit surface could determine a COE increase of only about 10% and a maximum increase of the mitigation cost of further 5 €/ton_CO2.     

Economic assessment of membrane-assisted autothermal reforming for cost effective hydrogen production with CO2 capture

A recent techno-economic study (Spallina et al., Energy Conversion and Management 120: p. 257–273) showed that the membrane assisted chemical looping reforming (MA-CLR) technology can produce H₂ with integrated CO₂ capture at costs below that of conventional steam methane reforming. A key technical challenge related to MA-CLR is the achievement of reliable solids circulation between the air and fuel reactors at large scale under the high (>50 bar) operating pressures required for optimal performance. This work therefore presents process modelling and economic assessments of a simplified alternative; membrane assisted autothermal reforming (MA-ATR), that inherently avoids this technical challenge. The novelty of MA-ATR lies in replacing the MA-CLR air reactor with an air separation unit (ASU), thus avoiding the need for oxygen carrier circulation. The economic assessment found that H₂ production from MA-ATR is only 1.5% more expensive than MA-CLR in the base case. The calculated cost of hydrogen (compressed to 150 bar) in the base case was 1.55 €/kg with a natural gas price of €6/GJ and an electricity price of €60/MWh. Both concepts show continued performance improvements with an increase in reactor pressure and temperature, while an optimum cost is achieved at about 2 bar H₂ permeate pressure. Sensitivities to other variables such as financing costs, membrane costs, fuel and electricity prices are similar between MA-ATR and MA-CLR. Natural gas prices represent the most important sensitivity, while the sensitivity to membrane costs is relatively small at high reactor pressures. MA-ATR therefore appears to be a promising alternative to achieve competitive H₂ production with CO₂ capture if technical challenges significantly delay scale-up and deployment of MA-CLR technology. The key technical demonstration required before further MA-ATR scale-up is membrane longevity under the high reactor pressures and temperatures required to minimize the cost of hydrogen.