Process design and techno-economic analysis of dual hydrogen and methanol production from plastics using energy integrated system

This study has been dedicated towards the conversion of plastics to methanol and hydrogen. The base design (case 1) represents the conventional design for producing syngas via steam gasification of waste plastics followed by CO₂ and H₂S removal. The syngas then processed in the methanol synthesis reactor to produce methanol, whereas, the remaining unconverted gases are processed in water gas shift reactors to produce hydrogen. On the other hand, an alternative design (case 2) has been also developed with an aim to increase the H₂ and methanol production, which integrates the plastic gasification and the methane reforming units to utilize the high energy stream from gasification unit to heat up the feed stream of reforming unit. Both the cases have been techno-economically compared to evaluate the process feasibility. The comparative analysis revealed that case 2 outperforms the case 1 in terms of both process efficiency and economics.     

Process simulation and integration of IGCC systems for H2/syngas/electricity generation with control on CO2 emissions

IGCC is a pre-combustion technology that can be effectively used to produce both hydrogen and electricity while reducing the greenhouse gas (GHG) emissions. Two process models are developed in Aspen Plus^® software and are compared techno-economically. The conventional design of IGCC process is taken as case 1, whereas, case 2 represents the conceptual design of sequential integration of reforming model with the gasification unit to enhance the syngas yield. The case 2 utilizes the steam generated in the gasification process to sustain the methane reforming process which consequently enhances both the H₂ production capacity and cold gas efficiency. It has been analyzed from results that case 2 can enhance the process performance by 4.77% and economics in terms of cost of electricity by 5.9% compared to the conventional process. However, the utilization of natural gas in the case 2 is considered as a standalone fuel so the process performance of NGCC power plants has been also incorporated to ensure the realistic analysis. The results also showed that case 2 design offers 3.9% higher process performance than the cumulative (IGCC + NGCC) processes, respectively. Moreover, the CO₂ specific emissions and LCOE for the case 2 is also lower than the case.     

Co-production of synthetic fuels and district heat from biomass residues,carbon dioxide and electricity: Performance and cost analysis

Large-scale systems suitable for the production of synthetic natural gas (SNG), methanol or gasoline (MTG) are examined using a self-consistent design, simulation and cost analysis framework. Three basic production routes are considered: (1) production from biomass via gasification; (2) from carbon dioxide and electricity via water electrolysis; (3) from biomass and electricity via hybrid process combining elements from routes (1) and (2). Process designs are developed based on technologies that are either commercially available or successfully demonstrated at precommercial scale. The prospective economics of future facilities coproducing fuels and district heat are evaluated from the perspective of a synthetic fuel producer. The levelised production costs range from 18–37 €/GJ for natural gas, 21–40 €/GJ for methanol and 23–48 €/GJ for gasoline, depending on the production route. For a given end-product, the lowest costs are associated with thermochemical plant configurations, followed by hybrid and electrochemical plants.     

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.     

CO2 enhanced coalbed methane production in the Netherlands

The technical and economical feasibility of CO₂ sequestration in deep coal layers combined with enhanced coalbed methane (ECBM) production in the Netherlands has been explored. Annually, 3.4 Mtonne CO₂ from chemical installations can be delivered to sequestration locations at 15 €/tonne and another 55 Mtonne from power generating facilities at 40–80 €/tonne. Four potential ECBM areas have been assessed, of which Zuid Limburg is the best location for a test site, while the Achterhoek is more suitable for future large-scale CO₂ sequestration. Between 54 Mtonne and 9 Gtonne CO₂ can be sequestered in the four areas together, heavily depending on available technology for accessing the coal seams. At the same time, between 0.3 and 60 EJ of coalbed methane can be produced. The optimal configuration may have 1000 m spacing between production wells, and extreme inseam drilling. The price of coalbed methane may become competitive with natural gas when a bonus for CO₂ sequestration is applied of about 25 €/tonne. For the long term, on-site hydrogen or power (SOFC) production with direct injection of produced CO₂ seems most attractive. Further study is required, most notably more accurate geological surveys, assessment of drilling costs in Dutch context, and environmental impacts of ECBM.     

Catalytic hydrogenation of CO2 from 600 MW supercritical coal power plant to produce methanol: A techno-economic analysis

Electricity and water from renewable hydropower plant are used as input for electrolysis unit to generate hydrogen, while CO₂ is captured from 600 MW supercritical coal power plant using post-combustion chemical solvent based technology. The captured CO₂ and H₂ generated through electrolysis are used to synthesize methanol through catalytic thermo-chemical reaction. The methanol synthesis plant is designed, modeled and simulated using commercial software Aspen Plus^®. The reactor is analyzed for two widely adopted kinetic models known as Graaf model and Vanden-Bossche (VB) model to predict the methanol yield and CO₂ conversion. The results show that the methanol reactor based on Graaf kinetic model produced 0.66 tonne of methanol per tonne of CO₂ utilized which is higher than that of the VB kinetic model where 0.6 tonne of methanol is produced per tonne of CO₂ utilized. The economic analysis reveals that 1.2 billion USD annually is required at the present cost of both H₂ production and CO₂ abatement to utilize continuous emission of 3.2 million tonne of CO₂ annually from 600 MW supercritical coal power unit to synthesize methanol. However, sensitivity analysis indicates that methanol production becomes feasible by adopting anyone of the route such as by increasing methanol production rate, by reducing levelised cost of hydrogen production, by reducing CO₂ mitigation cost or by increasing the current market selling price of methanol and oxygen.     

Techno-economic analysis of the Ca-Cu process integrated in hydrogen plants with CO2 capture

In this work, a techno-economic analysis of a hydrogen production plant based on the Ca-Cu process has been carried out. The simulation of the whole hydrogen production plant has been performed, including the calculation of the Ca-Cu fixed bed reactors system using a sharp front modelling approach. From the analyses carried out, it has been demonstrated that the optimal operation point from the energy performance point of view is reached when fuel needed for sorbent regeneration is entirely supplied by the off-gas from the PSA hydrogen purification unit, which corresponds to operating the plant with the minimum steam-to-carbon ratio in the reforming step. Moreover, lowering the operating pressure of the Ca-Cu system results beneficial from the hydrogen production efficiency, but the CO₂ emissions and the economics worsen.The Ca-Cu based hydrogen production plant operating at a high pressure has been demonstrated to be cost efficient with respect to a benchmark hydrogen production plant based on conventional fired tubular reformer and CO₂ capture by MDEA absorption. A hydrogen production cost of 0.178 €/Nm³ and a CO₂ avoided cost of 30.96 €/ton have been calculated for this Ca-Cu hydrogen production plant, which are respectively 8% and 52% lower than the corresponding costs of the benchmark.     

Integration of water electrolysis for fossil-free steel production

This study investigates the integration of water electrolysis technologies in fossil-free steelmaking via the direct reduction of iron ore followed by processing in an electric arc furnace (EAF). Hydrogen (H₂) production via low or high temperature electrolysis (LTE and HTE) is considered for the production of carbon-free direct reduced iron (DRI). The introduction of carbon into the DRI reduces the electricity demand of the EAF. Such carburization can be achieved by introducing carbon monoxide (CO) into the direct reduction process. Therefore, the production of mixtures of H₂ and CO using either a combination of LTE coupled with a reverse water-gas shift reactor (rWGS-LTE) or high-temperature co-electrolysis (HTCE) was also investigated. The results show that HTE has the potential to reduce the specific electricity consumption (SEC) of liquid steel (LS) production by 21% compared to the LTE case. Nevertheless, due to the high investment cost of HTE units, both routes reach similar LS production costs of approximately 400 €/tonne LS. However, if future investment cost targets for HTE units are reached, a production cost of 301 €/tonne LS is attainable under the conditions given in this study. For the production of DRI containing carbon, a higher SEC is calculated for the LTE-rWGS system compared to HTCE (4.80 vs. 3.07 MWh/tonne LS). Although the use of HTCE or LTE-rWGS leads to similar LS production costs, future cost reduction of HTCE could result in a 10% reduction in LS production cost (418 vs. 375 €/tonne LS). We show that the use of HTE, either for the production of pure H₂ or H₂ and CO mixtures, may be advantageous compared to the use of LTE in H₂-based steelmaking, although results are sensitive to electrolyzer investment costs, efficiencies, and electricity prices.     

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).     

CO2 capture study in advanced integrated gasification combined cycle

This paper presents the results of technical and economic studies in order to evaluate, in the French context, the future production cost of electricity from IGCC coal power plants with CO₂ capture and the resulting cost per tonne of CO₂ avoided. The economic evaluation shows that the total cost of base load electricity produced in France by coal IGCC power plants with CO₂ capture could be increased by 39% for ‘classical’ IGCC and 28% for ‘advanced’ IGCC. The cost per tonne of avoided CO₂ is lower by 18% in ‘advanced’ IGCC relatively to ‘classical’ IGCC. The approach aimed to be as realistic as possible for the evaluation of the energy penalty due to the integration of CO₂ capture in IGCC power plants. Concerning the CO₂ capture, six physical and chemical absorption processes were modeled with the Aspen Plus™ software. After a selection based on energy performance three processes were selected and studied in detail: two physical processes based on methanol and Selexol™ solvents, and a chemical process using activated MDEA. For ‘advanced’ IGCC operating at high-pressure, only one physical process is assessed: methanol.     

Performance of simulated flexible integrated gasification polygeneration facilities,Part B: Economic evaluation.

This paper investigates the economics of integrated gasification polygeneration (IG-PG) facilities and assesses under which market conditions flexible facilities outperform static facilities. In this study, the facilities use Eucalyptus wood pellets (EP), torrefied wood pellets (TOPS) and Illinois #6 coal as feedstock to produce electricity, FT-liquids, methanol and urea. All facilities incorporate CCS. The findings show production costs from static IG-PG facilities ranging between 12 and 21 €/GJ using coal, 19–33 €/GJ using TOPS and 22–38 €/GJ using EP, which is above the average market prices. IG-PG facilities can become competitive if capital costs drop by 10%–27% for coal based facilities. Biomass based facilities will need lower biomass pellet prices or higher CO₂ credit prices. Biomass becomes competitive with coal at a CO₂ credit price of 50–55 €/t CO₂. Variations in feedstock, CO₂ credit and electricity prices can be offset by operating a feedstock flexible IG-PG facility, which can switch between coal and TOPS, thereby altering its electricity production. The additional investment is around 0.5% of the capital costs of a dedicated coal based IG-PG facility. At 30 €/t CO₂, TOPS will be the preferred feedstock for 95% of the time at a feedstock price of 5.7 €/GJ. At these conditions, FT-liquids (gasoline/diesel) can be produced for 15.8 €/GJ (116 $/bbl). Historic records show price variations between 5.7 and 7.3 €/GJ for biomass pellet, 1.0–5.6 €/GJ for coal and 0–32 €/t CO₂. Within these price ranges, coal is generally the preferred feedstock, but occasionally biomass is preferred. Lower biomass prices will increase the frequency of switching feedstock preference from coal to biomass, raising the desire for flexibility. Of the three investigated chemicals, an IG-PG facility producing FT-liquids benefits the most from flexibility. Our study suggests that if the uncertainty in commodity prices is high, a small additional investment can make flexible IG-PG facilities attractive.     

Progress on methanol reforming technologies for highly efficient hydrogen production and applications

With the continuous development of human society, the shortages of fossil resource and environmental pollution are increasingly prominent. Hydrogen is a clean and efficient alternative energy, among various hydrogen production technologies, methanol reforming has been regarded as a promising candidate to produce hydrogen for daily energy supply due to its low cost and safe transportation. In this review, we discuss the sources of methanol and the methods of methanol reforming for hydrogen production. Then, we focus on the catalysts for methanol reforming and their preparation methods. Particular attention is paid to the structural design and manufacturing process to make methanol reforming microreactors. We also summarize recent studies on the practical applications of methanol reforming technologies, as well as the capture and utilization of the generated carbon to reduce its emission. Finally, the prospect challenges of methanol reforming for highly efficient hydrogen production technologies and contribution to the “double carbon” goals and the challenges are discussed. In summary, this review will be conducive to the development of hydrogen-methanol economy for practical and industry applications.     

Design,modelling and optimal power and hydrogen management strategy of an off grid PV system for hydrogen production using methanol electrolysis

Hydrogen used as an energy carrier and chemical element can be produced by several processes such as gasification of coal and biomass, steam reforming of fossil fuel and electrolysis of water. Each of these methods has its own advantage and disadvantage. Electrolysis process is seen as the best option for quick hydrogen production. Hydrogen generation by methanol electrolysis process (MEP) gained much attention since it guarantees high purity gas and can be compatible with renewable energies. Furthermore, due to its very low theoretical potential (0.02 V), MEP can save more than 65% of electrical energy required to produce 1 kg of hydrogen compared to water electrolysis process (WEP). Electrolytic hydrogen production using solar photovoltaic (PV) energy is positioned to become as one of the preferred options due to the harmful environmental impacts of widely used methane steam reforming process and also since the prices of PV modules are more competitive.In this paper, hydrogen production by MEP using PV energy is investigated. A design of an off grid PV/battery/MethElec system is proposed. Mathematical models of each component of the system are presented. Semi-empirical relationship between hydrogen production rate and power consumption at 80 °C and 4 M concentration is developed. Optimal power and hydrogen management strategy (PHMS) is designed to achieve high system efficiency and safe operation. Case studies are carried out on two tilts of PV array: horizontal and tilted at 36° using measured meteorological data of solar irradiation and ambient temperature of Algiers site. Simulation results reveal great opportunities of hydrogen production using MEP compared to the WEP with 22.36 g/m² d and 24.38 g/m² d of hydrogen when using system with horizontal and tilted PV array position, respectively.     

Low-carbon hydrogen production via electron beam plasma methane pyrolysis: Techno-economic analysis and carbon footprint assessment

Electron beam plasma methane pyrolysis is a hydrogen production pathway from natural gas without direct CO₂ emissions. In this work, two concepts for a technical implementation of the electron beam plasma pyrolysis in a large-scale hydrogen production plant are presented and evaluated in regards of efficiency, economics and carbon footprint. The potential of this technology is identified by an assessment of the results with the benchmark technologies steam methane reforming, steam methane reforming with carbon capture and storage as well as water electrolysis. The techno-economic analysis shows levelized costs of hydrogen for the plasma pyrolysis between 2.55 €/kg H₂ and 5.00 €/kg H₂ under the current economic framework. Projections for future price developments reveal a significant reduction potential for the hydrogen production costs, which support the profitability of plasma pyrolysis under certain scenarios. In particular, water electrolysis as direct competitor with renewable electricity as energy supply shows a considerably higher specific energy consumption leading to economic advantages of plasma pyrolysis for cost-intensive energy sources and a high degree of utilization. Finally, the carbon footprint assessment indicates the high potential for a reduction of life cycle emissions by electron beam plasma methane pyrolysis (1.9 kg CO₂ eq./kg H₂ – 6.4 kg CO₂ eq./kg H₂, depending on the electricity source) compared to state-of-the-art hydrogen production technology (10.8 kg CO₂ eq./kg H₂).     

A techno-economic review of biomass gasification for production of chemicals

Gasification is a thermochemical process which can be used as a low-emission and highly efficient method to produce syngas and chemicals such as biomethanol and dimethyl ether (DME). In this paper, a review of technologies and methods for economic production of chemicals through gasification of biomass and other fuels has been carried out. A variety of techno-economic studies and analysis have been proposed in order to better understand the technical and economic assessments during the biomass gasification. Results showed that the methanol production cost for biomass (wood) is from 195 to 935 €/t, for waste residues is from 200 to 930 €/t, for coal is from 160 to 480 €/t, and for natural gas is from 90 to 290 €/t. It also concluded that fuel (wood) cost has positive linear relationship with ethanol production cost, meaning as the feedstock cost increases from 30 to 50 $/day-ton, the ethanol production cost enhances from 1.66 to 1.95 $/gal.     

Process analysis of a novel coal-to-methanol technology for gasification integrated solid oxide electrolysis cell (SOEC)

China's carbon peaking and carbon neutrality goals present a significant challenge for coal chemical technology, which is critical to securing the energy structure. Combining coal chemical industry technology with new energy is an effective approach to transform the development of the coal chemical industry. This paper proposes and studies a novel coal-to-methanol (CTM) technology of gasification integrated solid oxide electrolysis cell (SOEC). SOEC electrolytic hydrogen production technology is an advanced electrolytic water technology with the advantages of large scale and high efficiency, which is very suitable to be combined with industrial technology and can solve the painful problem of H₂ deficiency in the conventional coal to methanol process. In this study, from mechanistic analysis and model simulations, it is observed that by increasing the SOEC capacity, the novel CTM system can create more methanol at the same coal consumption and simultaneously reduce CO₂ emissions. The novel CTM system can produce up to 2.2 times more methanol and reduce CO₂ emissions by 94% by replacing the water-gas-shift (WGS) process with the SOEC unit. The novel CTM increases energy consumption. In addition, the novel CTM technology will effectively improve the economics of coal to methanol, taking into account the carbon tax. At the methanol price of 2900 RMB/t and SOEC capacity of 250 MW, the economic benefits of novel CTM were 2.1 times greater than CTM technology.     

The net greenhouse warming forcing of methanol produced from biomass

Recent national and international actions regarding atmosphere warming mitigation, clean technology, and technology transfer have emphasized the need for a method for unambiguous greenhouse gas emissions analysis for comparing technologies, documentation of application of the method, and proof of applicability. We have developed and applied such an approach to production of methanol fuel from woody biomass. The entire approach is detailed, whereby the system was defined, its emissions for its entire lifetime delineated, and the atmospheric warming forcing calculated for that lifetime plus after effects. The results are presented with material and energy balances including ancillary equipment, external energy subsidies and invested quantities. These extend the analysis considerably beyond those possible using the global warming potential (GWP). For wood input of 283 mg day⁻¹, 70 mg of methanol are produced. System carbon dioxide emissions are 3.18 tonne/tonne methanol produced, with another 1.37 mg emitted when that tonne methanol is burned in a vehicle. System energy usage efficiency was 41.2%, and 41.1% with inclusion of energy to construct the system. In essence, more than two Joules of carbon must be produced in wood for every Joule burned in the vehicle.     

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.     

Integrated energy systems based on cascade utilization of energy

Focusing on the traditional principle of physical energy utilization, new integration concepts for combined cooling, heating and power (CCHP) system were identified, and corresponding systems were investigated. Furthermore, the principle of cascade utilization of both chemical and physical energy in energy systems with the integration of chemical processes and thermal cycles was introduced, along with a general equation describing the interrelationship among energy levels of substance, Gibbs free energy of chemical reaction and physical energy. On the basis of this principle, a polygeneration system for power and liquid fuel (methanol) production has been presented and investigated. This system innovatively integrates a fresh gas preparation subsystem without composition adjustment process (NA) and a methanol synthesis subsystem with partial-recycle scheme (PR). Meanwhile, a multi-functional energy system (MES) that consumes coal and natural gas as fuels simultaneously, and co-generates methanol and power, has been presented. In the MES, coal and natural gas are utilized synthetically based on the method of dual-fuel reforming, which integrates methane/steam reforming and coal combustion. Compared with conventional energy systems that do not consider cascade utilization of chemical energy, both of these systems provide superior performance, whose energy saving ratio can be as high as 10%–15%. With special attention paid to chemical energy utilization, the integration features of these two systems have been revealed, and the important role that the principle of cascade utilization of both chemical and physical energy plays in system integration has been identified.     

Development of methanol steam reforming microreactor based on stacked wave sheets and copper foam for hydrogen production

Methanol steam reforming has been used for in-situ hydrogen production and supply for proton exchange membrane fuel cell (PEMFC), while its power density and energy efficiency still needs to be improved. Herein, we present a novel methanol steam reforming microreactor based on the stacked wave sheets and copper foam for highly efficient hydrogen production. The structural of stacked wave sheets and copper foam, and their roles in the microreactor are described, methanol catalytic combustion is adopted to supply heat for methanol steam reforming reaction and enables the microreactor to work automatically. For catalyst carrier, a fractal body-centered cubic model is established to study the flow characteristics and chemical reaction performances of the copper foam with coated catalyst layer. Both simulation and experimental results showed that the reformate flowrate increases with the increasing of microreactor layers and methanol solution flowrate, the discrepancies of methanol conversion between simulation and experimental tests are less than 7%. Experimental results demonstrated that the reformate flowrate of 1.0 SLM can be achieved with methanol conversion rate of 65%, the output power of the microreactor is 159 W and power density is 395 W/L. The results obtained in this study indicates that stacked wave sheets and copper foam can uniform the reactant flow and improve the hydrogen production performances.